UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2007
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to .
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Commission file number:
001-33787
QUEST ENERGY PARTNERS,
L.P.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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26-0518546
(I.R.S. Employer
Identification
No.
)
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210 Park Avenue, Suite 2750
Oklahoma City, OK
(Address of principal
executive offices)
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73102
(Zip
Code)
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(405) 600-7704
(Registrants telephone
number, including area code)
SECURITIES
REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units representing
limited partner interests
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Nasdaq Global Market
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SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
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No
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Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
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No
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Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes
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No
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Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
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Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated
filer
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(Do not check if a smaller reporting company)
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Smaller reporting
company
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
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No
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The registrants common units were not publicly traded as
of the last business day of the registrants most recently
completed second fiscal quarter. The aggregate market value of
the common units of the registrant held by non-affiliates
computed by reference to the $14.55 closing price of such common
units on March 25, 2008, was approximately $132,405,000. As
of March 25, 2008, the registrant had 12,301,521 common
units and 8,857,981 subordinated units outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
None.
GUIDE
TO READING THIS REPORT
As used in this report, unless we indicate otherwise:
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when we use the terms Quest Energy Partners,
the Partnership, Successor,
our, we, us and similar
terms in a historical context prior to November 15, 2007,
we are referring to Predecessor, and when we use such terms in a
historical context on or after November 15, 2007, in the
present tense or prospectively, we are referring to Quest Energy
Partners, L.P. and its subsidiaries;
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when we use the term Predecessor, we are referring
to the assets, liabilities and operations of our Parent located
in the Cherokee Basin (other than its midstream assets), which
our Parent contributed to us at the completion of our initial
public offering on November 15, 2007;
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when we use the terms Quest Energy GP or our
general partner, we are referring to Quest Energy GP, LLC,
our general partner;
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when we use the term our Parent, we are referring to
Quest Resource Corporation (Nasdaq: QRCP), the owner of our
general partner, and its subsidiaries (other than us); and
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when we use the term Quest Midstream, we are
referring to Quest Midstream Partners, L.P. and its subsidiaries.
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In this report we also use some oil and natural gas industry
terms that are defined under the caption Glossary of
Selected Terms at the end of Items 1 and 2 of this
report.
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PART I
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Items 1.
and 2.
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Business
and
Properties.
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Overview
We are a Delaware limited partnership formed in July 2007 by our
Parent to acquire, exploit and develop oil and natural gas
properties. Effective November 15, 2007, we consummated the
initial public offering of our common units and acquired the gas
and oil properties contributed to us by our Parent in connection
with that offering. Our primary business objective is to
generate stable cash flows allowing us to make quarterly cash
distributions to our unitholders at our initial distribution
rate and, over time, to increase our quarterly cash
distributions. Our operations currently are focused on the
development of coal bed methane, or CBM, in a
15-county
region in southeastern Kansas and northeastern Oklahoma,
referred to in this report as the Cherokee Basin. In
addition to our producing properties, we have a significant
inventory of potential drilling locations and acreage in the
Cherokee Basin that we believe will allow us to grow our
reserves and production over time.
We operate in one reportable segment engaged in the
exploitation, development and production of gas and oil
properties. As of December 31, 2007, our properties had
211.1 Bcfe of estimated net proved reserves, of which
approximately 99% were CBM and 66.9% were proved developed. We
operate over 99% of our existing wells, with an average net
working interest of 99% and an average net revenue interest of
approximately 82%. We believe we are the largest producer of
natural gas in the Cherokee Basin with an average net daily
production of 46.7 Mmcfe for the year ended
December 31, 2007. Our estimated net proved reserves at
December 31, 2007 had estimated future net revenues
discounted at 10%, which we refer to as the standardized
measure, of $322.5 million. Our reserves are
long-lived, with an average proved reserve-to-production ratio
of 12.3 years (8.12 years for our proved developed
properties) as of December 31, 2007. Our typical Cherokee
Basin CBM well has a predictable production profile and a
standard economic life of approximately 15 years.
We have entered into derivative contracts with respect to
approximately 80% of our estimated net production from proved
developed producing reserves through the fourth quarter of 2010.
The derivative contracts for 2008 cover approximately 58% of our
total estimated net production for 2008. We also intend to
diversify our operations by pursuing accretive acquisitions of
conventional and unconventional gas and oil assets outside the
Cherokee Basin.
As of December 31, 2007, we were operating approximately
2,254 gross gas wells, of which over 90% were multi-seam
wells, and 29 gross oil wells. As of December 31,
2007, we owned the development rights to approximately
558,190 net acres throughout the Cherokee Basin and had
only developed approximately 52% of our acreage. For 2008, we
have budgeted approximately $41.0 million to drill and
complete an estimated 325 gross wells and recomplete an
estimated 52 gross wells, as well as an additional
$37.5 million for acreage, equipment and vehicle
replacement and purchases and salt water disposal facilities.
Our recompletions generally consist of converting wells that
were originally completed with single seam completions into
multi-seam completions, which allows us to produce additional
gas from different levels. We expect to drill and connect
325 wells in 2008. At this time, we have identified our
drilling locations for 2008 and many of these wells will be
drilled on locations that are classified as containing proved
reserves in our December 31, 2007 reserve report. As of
December 31, 2007, our undeveloped acreage contained
approximately 2,100 gross CBM drilling locations, of
which approximately 800 were classified as proved undeveloped.
Over 99% of the CBM wells that have been drilled on our acreage
to date have been successful. Our Cherokee Basin acreage is
currently being developed utilizing primarily
160-acre
spacing. However, several of our competitors are currently
developing their CBM reserves in the Cherokee Basin on
80-acre
spacing. We are currently conducting a pilot program to test the
development of a portion of our acreage using
80-acre
spacing. If our pilot project is successful, we could
significantly increase the number of CBM drilling locations
which are present on our acreage. None of our acreage or
producing wells is associated with coal mining operations.
As of December 31, 2007, we had an inventory of
approximately 212 drilled CBM wells awaiting connection to the
gathering system of our affiliate, Quest Midstream. It is our
intention to focus on the development of CBM reserves that can
be immediately served by Quest Midstreams gathering system.
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The following chart reflects our organizational structure.
Recent
Developments
Our Formation and IPO.
In July 2007, our
Parent formed us to acquire, exploit and develop oil and natural
gas properties. On November 15, 2007, our Parent
transferred Quest Cherokee, LLC (which owned all of its Cherokee
Basin gas and oil leases) and Quest Cherokee Oilfield Service,
LLC (which owned all of its Cherokee Basin field equipment and
vehicles) to us in exchange for 3,201,521 common units and
8,857,981 subordinated units and a 2% general partner interest.
Also on November 15, 2007, we completed our initial public
offering of 9,100,000 common units at $18.00 per unit, or $16.83
per unit after payment of the underwriting discount (excluding a
structuring fee). Total proceeds from the sale of our common
units in the initial public offering were $163.8 million,
before underwriting discounts, a structuring fee and offering
costs, of approximately $10.6 million, $0.4 million
and $1.5 million, respectively. On November 9, 2007,
our common units began trading on the NASDAQ Global Market under
the symbol QELP.
Quest Energy GP, our general partner, was formed in July 2007.
Quest Energy GP is a wholly-owned subsidiary of our Parent.
Quest Energy GP owns 431,827 general partner units representing
a 2% general partner interest in us and all of the incentive
distribution rights. For more information regarding our initial
public offering and related transactions, see our Current
Reports on
Form 8-K
filed November 9 and November 21, 2007.
New Credit Agreement.
In connection with the
closing of our initial public offering, on November 15,
2007, we entered into an Amended and Restated Credit Agreement
(the Credit Agreement), as a guarantor, with our
wholly-owned subsidiary, Quest Cherokee, as the borrower, our
Parent, as the initial co-borrower, Royal Bank of Canada
(RBC), as administrative agent and collateral agent,
KeyBank National Association, as documentation agent and the
lenders party thereto. Our Parent and Quest Cherokee had
previously been parties to the following credit agreements with
Guggenheim Corporate Funding, LLC (Guggenheim):
(i) Amended and Restated Senior Credit Agreement, dated
February 7, 2006, as amended; (ii) Amended and
Restated Second Lien Term Loan Agreement, dated June 9,
2006, as amended; and (iii) Third Lien Term Loan Agreement,
dated June 9, 2006, as amended (collectively, the
Prior Credit Agreements). Guggenheim and the lenders
under the Prior Credit Agreements assigned all of their
interests and rights (other than certain excepted interests and
rights) in the Prior Credit Agreements to RBC and the new
lenders under the Credit Agreement pursuant to a Loan Transfer
Agreement, dated November 15, 2007, by and among Quest
Cherokee, our Parent, certain of our Parents subsidiaries,
Guggenheim, Wells Fargo Foothill, Inc., the lenders under the
Prior Credit Agreements and RBC. The Credit Agreement amended
and restated the Prior Credit Agreements in their entirety.
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The credit facility under the Credit Agreement consists of a
five-year $250 million revolving credit facility.
Availability under the revolving credit facility is tied to a
borrowing base that will be redetermined by RBC and the lenders
every six months taking into account the value of Quest
Cherokees proved reserves. In addition, Quest Cherokee and
RBC each have the right to initiate a redetermination of the
borrowing base between each six-month redetermination. As of
December 31, 2007, the borrowing base was
$160 million, and the amount borrowed under the Credit
Agreement was $94 million. At the closing of our initial
public offering, our Parent was released as a borrower under the
Credit Agreement.
For more information regarding the Credit Agreement, see
Note 4. Long-Term Debt to the financial statements included
in this
Form 10-K.
Acquisition of Oil Producing Properties.
In
early February 2008, we purchased 1,200 acres in Seminole
County, Oklahoma from Landmark Energy for $9.5 million. We
reduced our land budget for 2008 in a similar amount to retain
our total capital budget unchanged. The oil producing properties
have estimated reserves of 712,000 Bbl, all of which are
proved developed producing.
Business
Strategies
Our primary business objective is to make quarterly cash
distributions to our unitholders at our initial distribution
rate, and over time increase our quarterly cash distributions.
Our strategy for achieving this objective is to:
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Efficiently control the drilling and development of our acreage
position in the Cherokee Basin;
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Accumulate additional acreage in the Cherokee Basin in areas
where management believes the most attractive development
opportunities exist;
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Pursue selected strategic acquisitions in the Cherokee Basin
that would add attractive development opportunities and critical
gas gathering infrastructure;
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Maintain operational control over our assets whenever
possible; and
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Limit our reliance on third party contractors with respect to
the completion, stimulation and connection of our wells.
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Competitive
Strengths
We believe that we are well positioned to achieve our primary
business objective and to execute our strategies because of the
following competitive strengths:
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Experienced management.
Key members of our
executive management and technical teams have on average more
than 20 years of experience developing conventional and
unconventional oil and natural gas fields in the United States.
Several have been developing CBM in the Cherokee Basin since
1995.
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Low geological risk.
The coal seams from which
we produce CBM are notable for their consistent thickness and
gas content. In addition, extensive drilling dating back 60 to
80 years for the development of oil reserves in the
Cherokee Basin gives us access to substantial information
related to the coal seams we target. Over 100,000 well
bores have penetrated the Cherokee Basin since the 1920s. Data
available from the drilling records of these wells allows us to
determine the aerial extent, thickness and relative permeability
of the coal seams we target for development, which greatly
reduces its dry hole risk.
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High rate of drilling success.
Over 99% of the
CBM wells that have been drilled on our acreage have been, or
are capable of being, completed as economic producers.
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Expertise in Cherokee Basin geology.
We have
spent several years conducting technical research on historical
data related to the development of the Cherokee Basin. From this
analysis, we believe we have determined where the most
attractive opportunities for CBM development exist within the
basin.
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Large acreage position and inventory of drilling
sites.
We have the right to develop 558,190
net CBM acres in the Cherokee Basin. As of
December 31, 2007, our acreage was approximately 51.6%
developed
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and offered approximately 2,100 gross CBM drilling
locations, of which approximately 800 were classified as proved
undeveloped.
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Availability of significant quantities of low cost
acreage.
Presently, several hundred thousand
acres of unleased CBM acreage are available in the Cherokee
Basin. We believe this acreage generally can be leased for an
amount less than acreage in other basins. These circumstances
afford us the opportunity to sustain long-term organic growth by
adding undeveloped acreage and CBM drilling locations at a
reasonable cost.
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Competitive advantage of our gas gathering
agreement.
Our gas gathering agreement with Quest
Midstream represents a competitive advantage compared to third
parties seeking to lease acreage that is readily served by the
system. The gathering fee that Quest Midstream receives for
gathering our gas is determined annually compared to a volume
take allowance of up to 30% before royalties for third party
operators in the basin. This not only makes development
economics less attractive for third party operators to lease
land served by the system, it also makes us a more attractive
lessee for landowners. The vast geographic extent of Quest
Midstreams gas gathering system together with our large
land position makes it unattractive for third parties to lease
proximate acreage and build duplicate gas gathering facilities.
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Attractive geological characteristics of Cherokee Basin
CBM.
Compared to some other basins in the United
States where CBM is produced, CBM production in the Cherokee
Basin has distinct economic advantages. First, the coal seams in
the Cherokee Basin are relatively more permeable and thus tend
to produce at a faster rate. This results in a shorter reserve
life, the need to drill fewer wells, a faster payout period and
a higher present value of reserves. Second, Cherokee Basin coal
seams produce relatively less water than coal seams in some
other basins. Cherokee Basin CBM wells produce gas immediately,
have a shorter dewatering period, and produce less water overall
than CBM wells in some other basins.
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Predictable results of our CBM wells.
Our CBM
wells in the Cherokee Basin have highly consistent behavior in
terms of recoverable reserves, production rates and decline
curves, which results in lower development risk.
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Concentrated ownership and operational
control.
We own 100% of the working interest in
over 95% of the wells in which we have ownership. As a result of
this ownership position, we operate substantially all of the
wells in which we own an economic interest.
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Long-lived reserves.
Our average proved
reserve-to-production ratio is 8.12 years for our proved
developed properties based on our reserves as of
December 31, 2007 and production (17.15 Bcfe) for the
year ended December 31, 2007. Based on our current rate of
new well development and current undeveloped acreage, we
estimate that it would take approximately 6.34 years to
fully develop our existing acreage. In addition, the standard
economic life of our typical Cherokee Basin well is
approximately 15 years. We believe this long reserve life
reduces the reinvestment risk associated with the Companys
asset base.
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Our
Relationship with Our Parent
One of our principal attributes is our relationship with our
Parent, which is an independent energy company engaged in the
exploration, development and production of gas and oil and
related midstream activities. Our Parent controls us through its
ownership of our general partner, which owns a 2% general
partner interest in us as well as all of the incentive
distribution rights. Our Parent also owns 3,201,521 common units
and 8,857,981 subordinated units representing an aggregate 57%
limited partner interest in us.
In connection with our initial public offering, we entered into
the following agreements with our Parent:
Omnibus Agreement.
We, our general partner,
and our Parent entered into an Omnibus Agreement, which governs
our Parents and its affiliates relationship with us
regarding the following matters:
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reimbursement of certain insurance, operating and general and
administrative expenses incurred on our behalf;
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indemnification for certain environmental liabilities, tax
liabilities, tax defects and other losses in connection with
assets;
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a license for the use of the Quest name and mark; and
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our right to purchase from our Parent and its affiliates certain
assets that they acquire within the Cherokee Basin.
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Our Parents maximum liability for its environmental
indemnification obligations will not exceed $5 million, and
it will not have any indemnification obligation for
environmental claims or title defects until our aggregate losses
exceed $500,000.
Management Agreement.
We, our general partner,
and Quest Energy Service, LLC, our Parents wholly-owned
subsidiary (Quest Energy Service), entered into a
Management Services Agreement, under which Quest Energy Service
will perform acquisition services and general and administrative
services, such as accounting, finance, tax, property management,
risk management, land, marketing, legal and engineering to us,
as directed by our general partner, for which we will reimburse
Quest Energy Service on a monthly basis for the reasonable costs
of the services provided.
While our relationship with our Parent may benefit us, it is
also a source of potential conflicts of interest. Our Parent
currently owns approximately 22,700 net undeveloped acres
located in the States of Texas, Maryland, New Mexico and
Pennsylvania. Part of our Parents strategy is to acquire
additional acreage in areas without proved gas and oil reserves
and to conduct exploration activities on its existing properties
and any other properties acquired in the future. Our Parent
currently intends to focus its exploration activities on areas
with potential for producing unconventional gas.
For example, on February 6, 2008, our Parent entered into
an amended and restated merger agreement with Pinnacle Gas
Resources, Inc. or Pinnacle to acquire Pinnacle.
Pinnacle is an independent energy company engaged in the
acquisition, exploration and development of domestic onshore
natural gas reserves and focuses on the development of CBM
properties located in the Rocky Mountain Region. Pinnacle
currently conducts its operations in the Powder River Basin and
Green River Basin located in Montana and Wyoming. As of
December 31, 2007, Pinnacle owned natural gas and oil
leasehold interests in approximately 494,000 gross (316,000
net) acres, approximately 93% of which were undeveloped. It is
anticipated that the closing of the merger will occur in the
second quarter of 2008.
We believe that we may have opportunities to acquire from our
Parent gas or oil properties with additional proved reserves
that are appropriate to our structure and strategy as a master
limited partnership. In addition, opportunities may arise to
acquire a package of gas or oil properties, only some of which
have proved reserves. In those cases, we anticipate that we and
our Parent could work together to acquire all of the properties
with our Parent acquiring those properties on which further
exploration activities are required while we would acquire those
properties that are suitable for exploitation and development
activity. We believe our Parent will have a strong incentive to
contribute or sell additional assets to us, and to team with us
to acquire properties jointly, due to its significant ownership
of limited and general partner interests in us. However, our
Parent has no obligation to do so and may elect to acquire or
dispose of gas and oil properties outside the Cherokee Basin in
the future without offering us the opportunity to purchase or
participate in the acquisition of those assets. Our Parent has
retained such flexibility because it believes it is in the best
interests of its shareholders to do so. We cannot say which, if
any, opportunities to acquire assets from our Parent may be made
available to us or if we will choose to pursue any such
opportunity. Moreover, our Parent and its subsidiaries are not
prohibited from competing with us outside the Cherokee Basin.
Description
of Our Properties and Projects
Cherokee Basin.
We produce CBM gas out of our
properties located in the Cherokee Basin. The Cherokee Basin is
located in southeastern Kansas and northeastern Oklahoma.
Geologically, it is situated between the Forest City Basin to
the north, the Arkoma Basin to the south, the Ozark Dome to the
east and the Nemaha Ridge to the west. The Cherokee Basin is a
mature producing area with respect to conventional reservoirs
such as the Bartlesville sandstones and the Mississippian
limestones, which were developed beginning in the early 1900s.
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The Cherokee Basin is part of the Western Interior Coal Region
of the central United States. The coal seams we target for
development are found at depths of 300 to 1,400 feet. The
principal formations we target include the Mulky,
Weir-Pittsburgh and the Riverton. These coal seams are blanket
type deposits, which extend across large areas of the basin.
Each of these seams generally range from two to five feet thick.
Additional minor coal seams such as the Summit, Bevier, Fleming
and Rowe are found at varying locations throughout the basin.
These seams range in thickness from one to two feet.
We acquired the properties in the Cherokee Basin in the
following transactions:
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the Predecessor acquired approximately 372,000 gross
(366,000 net) acres of gas leases, 418 gross (325 net) gas
wells and 207 miles of gas gathering pipelines in the
Cherokee Basin from Devon Energy Production Company, L.P. and
Tall Grass Gas Services, LLC in December 2003;
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the Predecessor acquired 53 natural gas and oil leases and
related assets in Chautauqua, Elk, and Montgomery Counties,
Kansas from James R. Perkins Energy, L.L.C. and E. Wayne
Willhite Energy, L.L.C. in June 2003; and
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we acquired all of these properties from our Parent in November
2007 in connection with the closing of our initial public
offering.
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Characteristics of Coal Bed Methane.
The rock
containing gas, referred to as source rock, is
usually different from reservoir rock, which is the rock through
which the gas is produced, while in CBM, the coal seam serves as
both the source rock and the reservoir rock. The storage
mechanism is also different. Gas is stored in the pore or void
space of the rock in conventional gas, but in CBM, most, and
frequently all, of the gas is stored by adsorption. This
adsorption allows large quantities of gas to be stored at
relatively low pressures. A unique characteristic of CBM is that
the gas flow can be increased by reducing the reservoir
pressure. Frequently, the coal bed pore space, which is in the
form of cleats or fractures, is filled with water. The reservoir
pressure is reduced by pumping out the water, releasing the
methane from the molecular structure, which allows the methane
to flow through the cleat structure to the well bore. Because of
the necessity to remove water and reduce the pressure within the
coal seam, CBM, unlike conventional hydrocarbons, often will not
show immediately on initial production testing. Coalbed
formations typically require extensive dewatering and
depressuring before desorption can occur and the methane begins
to flow at commercial rates. Our Cherokee Basin CBM properties
typically dewater for a period of 12 months before peak
production rates are achieved.
CBM and conventional gas both have methane as their major
component. While conventional gas often has more complex
hydrocarbon gases, CBM rarely has more than 2% of the more
complex hydrocarbons. Once coalbed methane has been produced, it
is gathered, transported, marketed and priced in the same manner
as conventional gas. The CBM produced from our Cherokee Basin
properties has an MMBtu content of approximately 970 MMBtu,
compared to conventional natural gas hydrocarbon production
which can typically vary from 1,050-1,300 MMBtus.
The content of gas within a coal seam is measured through gas
desorption testing. The ability to flow gas and water to the
well bore in a CBM well is determined by the fracture or cleat
network in the coal. While, at shallow depths of less than
500 feet, these fractures are sometimes open enough to
produce the fluids naturally, at greater depths the networks are
progressively squeezed shut, reducing the ability to flow. It is
necessary to provide other avenues of flow such as hydraulically
fracturing the coal seam. By pumping fluids at high pressure,
fractures are opened in the coal and a slurry of fluid and sand
is pumped into the fractures so that the fractures remain open
after the release of pressure, thereby enhancing the flow of
both water and gas to allow the economic production of gas.
Cherokee Basin Projects.
Historically, we have
developed our CBM reserves in the Cherokee Basin on
160-acre
spacing. However, we are beginning to develop some test wells on
80-acre
spacing. Our wells generally reach total depth in 1.5 days
and our average cost for 2007 to drill and complete a well,
excluding the related pipeline infrastructure, was approximately
$124,000. We estimate that for 2008, our average cost for
drilling and completing a well will be approximately $121,000,
excluding the related pipeline infrastructure. We perforate and
frac the multiple coal seams present in each well. Our typical
Cherokee Basin multi-seam CBM well has net reserves of
130 Mmcf. Our general production profile for a CBM well
averages an initial production rate of
15-20 Mcf/d
(net), steadily rising for the first twelve months while water
is pumped off and the formation pressure is lowered. A period of
relatively flat production of
55-60 Mcf/d
(net) follows the initial dewatering period for a period
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of approximately twelve months. After 24 months, production
begins to decline. The standard economic life is approximately
15 years. Our completed wells rely on very basic industry
technology.
Our development activities in the Cherokee Basin also include an
active program to recomplete CBM wells that produce from a
single coal seam to wells that produce from multiple coal seams.
During the year ended December 31, 2007, we recompleted
approximately 43 wellbores in Kansas and an additional
7 wellbores in Oklahoma and we had an additional
100 wellbores awaiting recompletion to multi-seam
producers. The recompletion strategy is to add four to five
additional pay zones to each wellbore, in a two-stage process at
an average cost of approximately $20,000 per well. Adding new
zones to a well has a brief negative effect on production by
first taking the well offline to perform the work and then by
introducing a second dewatering phase of the newly completed
formations. However, in the long term, we believe the impact of
the multi-seam recompletions will be positive as a result of an
increase in the rate of production and the ultimate recoverable
reserves available per well.
Wells are equipped with small pumping units to facilitate the
dewatering of the producing coal seams. Generally, upon initial
production, a single coal seam will produce
50-60 Bbls
of water per day. A multi-seam completion produces about
150 Bbls of water per day. Eventually, water production
subsides to
30-50 Bbls
per day. Produced water is disposed through injection wells we
drill into the underlying Arbuckle formation. One disposal well
will generally handle the water produced from 25 producing wells.
Gas and
Oil Data
Estimated Net Proved Reserves.
The following
table presents our estimated net proved gas and oil reserves
relating to our natural gas and oil properties as of the dates
presented based on our reserve reports as of the dates listed
below. The data was prepared by the petroleum engineering firm
Cawley, Gillespie & Associates, Inc. in
Ft. Worth, Texas. We filed estimates of our gas and oil
reserves for the calendar years 2007, 2006 and 2005 with the
Energy Information Administration of the U.S. Department of
Energy on
Form EIA-23.
The data on
Form EIA-23
was presented on a different basis, and included 100% of the gas
and oil volumes from our operated properties only, regardless of
net interest. The difference between the gas and oil reserves
reported on
Form EIA-23
and those reported in this table exceeds 5%. The standardized
measure values shown in the table are not intended to represent
the current market value of our estimated gas and oil reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
|
210,923,000
|
|
|
|
198,040,000
|
|
|
|
134,319,000
|
|
Oil (Bbls)
|
|
|
36,556
|
|
|
|
32,272
|
|
|
|
32,269
|
|
Total (Mcfe)
|
|
|
211,142,000
|
|
|
|
198,234,000
|
|
|
|
134,513,000
|
|
Proved developed gas reserves (Mcf)
|
|
|
140,966,000
|
|
|
|
122,390,000
|
|
|
|
71,638,000
|
|
Proved undeveloped gas reserves (Mcf)
|
|
|
69,957,000
|
|
|
|
75,650,000
|
|
|
|
62,681,000
|
|
Proved developed oil reserves (BBls)(1)
|
|
|
36,556
|
|
|
|
32,272
|
|
|
|
32,269
|
|
Proved developed reserves as a percentage of total proved
reserves
|
|
|
66.9
|
%
|
|
|
61.8
|
%
|
|
|
53.4
|
%
|
Standardized measure in (thousands)(2)
|
|
$
|
322,537
|
|
|
$
|
268,072
|
|
|
$
|
482,545
|
|
|
|
|
(1)
|
|
Although we have proved undeveloped oil reserves, they are
insignificant, so no effort was made to calculate such reserves.
|
|
(2)
|
|
Standardized measure is the present value of estimated future
net revenue to be generated from the production of proved
reserves, determined in accordance with the rules and
regulations of the Securities and Exchange Commission (the
SEC) (using prices and costs in effect as of the
date of estimation), less future development, production and
income tax expenses, and discounted at 10% per annum to reflect
the timing of future net revenues. Our standardized measure does
not reflect any future income tax expenses because we are not
subject to income taxes. Standardized measure does not give
effect to derivative transactions. For a description of our
|
10
|
|
|
|
|
derivative transactions, see Note 6. Financial Instruments
and Note 7. Derivatives, in the notes to the
consolidated/carve out financial statements of this
Form 10-K.
The standardized measure shown should not be construed as the
current market value of the reserves. The 10% discount factor
used to calculate present value, which is required by FASB
pronouncements, is not necessarily the most appropriate discount
rate. The present value, no matter what discount rate is used,
is materially affected by assumptions as to timing of future
production, which may prove to be inaccurate.
|
The data in the table above represents estimates only. Gas and
oil reserve engineering is inherently a subjective process of
estimating underground accumulations of gas and oil that cannot
be measured exactly. The accuracy of any reserve estimate is a
function of the quality of available data and engineering and
geological interpretation and judgment. Accordingly, reserve
estimates may vary from the quantities of gas and oil that are
ultimately recovered. See Item 1A Risk
Factors Risks Related to Our Business
Our estimated proved reserves are based on many assumptions that
may prove to be inaccurate.
Production Volumes, Sales Prices and Production
Costs.
The following table sets forth information
regarding the natural gas and oil properties owned by us through
our subsidiaries. The gas and oil production figures reflect the
net production attributable to our revenue interest and are not
indicative of the total volumes produced by the wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15
|
|
|
January 1
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (bcf)
|
|
|
2.4
|
|
|
|
14.7
|
|
|
|
12.29
|
|
|
|
9.57
|
|
Oil (bbls)
|
|
|
393
|
|
|
|
6,677
|
|
|
|
9,737
|
|
|
|
9,241
|
|
Gas equivalent (bcfe)
|
|
|
2.4
|
|
|
|
14.7
|
|
|
|
12.34
|
|
|
|
9.62
|
|
Gas and Oil Sales ($ in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
15,420
|
|
|
$
|
89,903
|
|
|
$
|
72,865
|
|
|
$
|
71,137
|
|
Gas derivatives gains (loss)
|
|
$
|
388
|
|
|
$
|
6,892
|
|
|
$
|
(7,888
|
)
|
|
$
|
(27,066
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales
|
|
$
|
15,808
|
|
|
$
|
96,795
|
|
|
$
|
64,977
|
|
|
$
|
44,071
|
|
Oil sales
|
|
$
|
34
|
|
|
$
|
398
|
|
|
$
|
574
|
|
|
$
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas and oil sales
|
|
$
|
15,842
|
|
|
$
|
97,143
|
|
|
$
|
65,551
|
|
|
$
|
44,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg Sales Price (excluding effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas ($ per mcf)
|
|
$
|
6.45
|
|
|
$
|
6.11
|
|
|
$
|
5.93
|
|
|
$
|
7.44
|
|
Oil ($ per bbl)
|
|
$
|
85.98
|
|
|
$
|
59.65
|
|
|
$
|
58.95
|
|
|
$
|
53.46
|
|
Gas equivalent ($ per mcfe)
|
|
$
|
6.45
|
|
|
$
|
6.12
|
|
|
$
|
5.95
|
|
|
$
|
7.45
|
|
Avg Sales Price (including effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas ($ per mcf)
|
|
$
|
6.71
|
|
|
$
|
6.56
|
|
|
$
|
5.29
|
|
|
$
|
4.61
|
|
Oil ($ per bbl)
|
|
$
|
85.98
|
|
|
$
|
59.65
|
|
|
$
|
58.95
|
|
|
$
|
53.46
|
|
Gas equivalent ($ per mcfe)
|
|
$
|
6.71
|
|
|
$
|
6.57
|
|
|
$
|
5.31
|
|
|
$
|
4.63
|
|
Expenses ($ per mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting
|
|
$
|
1.22
|
|
|
$
|
1.33
|
|
|
$
|
1.29
|
|
|
$
|
0.98
|
|
Production and property tax
|
|
$
|
0.45
|
|
|
$
|
0.46
|
|
|
$
|
0.55
|
|
|
$
|
0.58
|
|
Net Revenue ($ per mcfe)
|
|
$
|
5.04
|
|
|
$
|
4.78
|
|
|
$
|
3.47
|
|
|
$
|
3.07
|
|
11
Producing Wells and Acreage.
The following
tables set forth information regarding our ownership of
productive wells and total acres as of December 31, 2005,
2006 and 2007. For purposes of the table below, productive wells
consist of producing wells and wells capable of production.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive Wells
|
|
|
|
|
|
|
Gas(1)
|
|
|
Oil
|
|
|
Total
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
Predecessor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
1,026
|
|
|
|
999.3
|
|
|
|
29
|
|
|
|
27.9
|
|
|
|
1,055
|
|
|
|
1,027.2
|
|
|
|
|
|
December 31, 2006
|
|
|
1,653
|
|
|
|
1,609.9
|
|
|
|
29
|
|
|
|
27.9
|
|
|
|
1,682
|
|
|
|
1,637.8
|
|
|
|
|
|
Successor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
2,225
|
|
|
|
2,182.2
|
|
|
|
29
|
|
|
|
27.9
|
|
|
|
2,254
|
|
|
|
2,210.1
|
|
|
|
|
|
|
|
|
(1)
|
|
At December 31, 2007, we had approximately 1,320 gross
wells that were producing from multiple seams.
|
During the year ended December 31, 2007, we drilled
575 gross (571 net) new wells on our properties, all being
gas wells. The wells drilled have been evaluated and were
included in the year-end reserve report. The oil well count
remains constant as we have been focused on adding gas reserves.
See Drilling Activities. During the year
ended December 31, 2007, we continued to lease additional
acreage in certain core development areas of the Cherokee Basin.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold Acreage(1)
|
|
|
|
|
|
|
Producing(2)
|
|
|
Nonproducing
|
|
|
Total Leased
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Predecessor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
334,676
|
|
|
|
310,663
|
|
|
|
198,569
|
|
|
|
184,322
|
|
|
|
533,245
|
|
|
|
494,985
|
|
December 31, 2006
|
|
|
394,795
|
|
|
|
385,148
|
|
|
|
132,189
|
|
|
|
124,774
|
|
|
|
526,984
|
|
|
|
509,923
|
|
Successor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
402,888
|
|
|
|
393,320
|
|
|
|
179,524
|
|
|
|
164,870
|
|
|
|
582,412
|
|
|
|
558,190
|
|
|
|
|
(1)
|
|
Approximately 45,000 and 90,000 net acres that were
included in the 2006 and 2005 leasehold acreage amounts have
expired.
|
|
(2)
|
|
Includes acreage held by production under the terms of the lease.
|
As of December 31, 2007, in the Cherokee Basin, we had
287,903 net developed acres and 270,287 net
undeveloped acres. Developed acres are acres spaced or assigned
to productive wells/units. Undeveloped acres are acres on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of gas or oil,
regardless of whether such acreage contains proved reserves.
12
Drilling Activities.
The table below sets
forth the number of wells completed at any time during the
period, regardless of when drilling was initiated. Most of the
wells expected to be drilled in the next year will be of the
development category and in the vicinity of Quest
Midstreams existing or planned construction pipeline
network. Our drilling, recompletion, abandonment, and
acquisition activities for the periods indicated are shown below
(all wells are in the Cherokee Basin):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
|
|
|
|
|
|
November 15
|
|
|
Predecessor
|
|
|
|
Through
|
|
|
January 1
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
Through
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
|
2007(1)
|
|
|
November 14, 2007(1)
|
|
|
2006(1)
|
|
|
2005(1)
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Gas
|
|
|
Gas
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells Drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells Drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of Production
|
|
|
64
|
|
|
|
63
|
|
|
|
511
|
|
|
|
508
|
|
|
|
638
|
|
|
|
621
|
|
|
|
233
|
|
|
|
227
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Abandoned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Acquired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in Capable Wells
|
|
|
64
|
|
|
|
63
|
|
|
|
511
|
|
|
|
508
|
|
|
|
638
|
|
|
|
621
|
|
|
|
233
|
|
|
|
227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recompletion of Old Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of Production
|
|
|
3
|
|
|
|
3
|
|
|
|
47
|
|
|
|
46
|
|
|
|
125
|
|
|
|
122
|
|
|
|
205
|
|
|
|
200
|
|
|
|
|
(1)
|
|
No change to oil wells for the years ended December 31,
2007, 2006 and 2005.
|
The 575 gross new natural gas wells completed for the year
ended December 31, 2007 reflect an average activity level
of approximately 48 gross wells per month. We plan to drill
and complete an average of approximately 27 gross wells per
month for year 2008, subject to capital being available for such
expenditures.
During the period from December 31, 2007 through
March 4, 2008, we drilled 73 gross wells and connected
65 gross wells. As of March 5, 2008, we were drilling
2 gross wells and approximately 140 gross wells were
in the process of being completed.
Operations
General.
As the operator of wells in which we
have an interest, we design and manage the development of a well
and supervise operation and maintenance activities on a
day-to-day basis. Quest Energy Service manages all of our
properties and employs production and reservoir engineers,
geologists and other specialists. Quest Cherokee Oilfield
Service, LLC, our wholly-owned subsidiary, employs our Cherokee
Basin field personnel.
Field operations conducted by our personnel include duties
performed by pumpers or employees whose primary
responsibility is to operate the wells. Other field personnel
are experienced and involved in the activities of well
servicing, the development and completion of new wells and the
construction of supporting infrastructure for new wells (such as
electric service, salt water disposal facilities, and gas feeder
lines). The primary equipment categories owned by us are trucks,
well service rigs, stimulation assets and construction
equipment. We utilize third party contractors on an as
needed basis to supplement our field personnel.
We also provide, on an in-house basis, many of the services
required for the completion and maintenance of our CBM wells.
Internally sourcing these functions significantly reduces our
reliance on third-party contractors, which typically provide
these services. We believe this results in reduced delays in
executing our plan of development. We are also able to realize
significant cost savings because we can avoid paying price
mark-ups
and
also because we are able to purchase our own supplies at bulk
discounts.
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We rely on third-party contractors to drill our wells. Once a
well is drilled, either we or a third-party contractor will run
the casing, and we will perform the cementing work. We also
perform our own fracturing and stimulation work. Finally, we
complete our own well site construction. We have our own fleet
of 20 well service units that we use in the process of
completing our wells, and also to perform remedial field
operations required to maintain production from our existing
wells.
Gas and Oil Leases.
As of December 31,
2007, we had over 4,350 leases covering approximately
558,190 net acres. The typical gas lease provides for the
payment of royalties to the mineral owner for all gas produced
from any well drilled on the lease premises. This amount ranges
from 18.75% to 12.5% resulting in an 81.25% to 87.5% net revenue
interest to us.
Because the acquisition of gas and oil leases is a very
competitive process, and involves certain geological and
business risks to identify productive areas, prospective leases
are sometimes held by other gas and oil operators. In order to
gain the right to drill these leases, we may purchase leases
from other gas and oil operators. In some cases, the assignor of
such leases will reserve an overriding royalty interest, ranging
from 1/32nd to 1/16th (3.125% to 6.25%), which further
reduces the net revenue interest available to us to between
78.125% and 81.25%.
Approximately 75% of our gas and oil leases are held by
production, which means that for as long as our wells continue
to produce gas or oil, we will continue to own the lease.
Gas
Gathering
We became a party to an existing midstream services and gas
dedication agreement entered into on December 22, 2006, but
effective as of December 1, 2006, between our Parent and
Quest Midstream. Pursuant to the midstream services agreement,
Quest Midstream gathers and provides certain midstream services,
including, dehydration, treating and compression, to us for all
gas produced from our wells in the Cherokee Basin that are
connected to Quest Midstreams gathering system.
The initial term of the midstream services agreement expires on
December 1, 2016, with two additional five-year extension
periods that may be exercised by either party upon
180 days notice. The fees charged under the midstream
services agreement are subject to renegotiation upon the
exercise of each five-year extension period.
Under the midstream services agreement, we agreed to pay Quest
Midstream $0.50 per MMBtu of gas for gathering, dehydration and
treating services and $1.10 per MMBtu of gas for compression
services, subject to an annual adjustment to be determined by
multiplying each of the gathering services fee and the
compression services fee by the sum of (i) 0.25 times the
percentage change in the producer price index for the prior
calendar year and (ii) 0.75 times the percentage change in
the Southern Star first of month index for the prior calendar
year. Such adjustment will be calculated within 60 days
after the beginning of each year, but will be retroactive to the
beginning of the year. Such fees will never be reduced below the
initial rates described above. For 2008, we anticipate the fees
will be $0.51 per MMBtu of gas for gathering, dehydration and
treating services and $1.13 per MMBtu of gas for compression
services. In addition, at any time after each five year
anniversary of the date of the midstream services agreement,
each party will have a one-time option to elect to renegotiate
the fees
and/or
the
basis for the annual adjustment to the fees if the party
believes there has been a material change to the economic
returns or financial condition of either party. If the parties
are unable to agree on the changes, if any, to be made to such
terms, then the parties will enter into binding arbitration to
resolve any dispute with respect to such terms.
In accordance with the midstream services agreement, we will
bear the cost to remove and dispose of free water from our gas
prior to delivery to Quest Midstream and of all fuel
requirements necessary to perform the gathering and midstream
services, plus any gas shrinkage.
Quest Midstream will have an exclusive option for sixty days to
connect to its gathering system each of the gas wells that we
develop in the Cherokee Basin. In addition, Quest Midstream will
be required to connect to its gathering system, at its expense,
any new gas wells that we complete in the Cherokee Basin if
Quest Midstream would earn a specified internal rate of return
from those wells. This rate of return is subject to
renegotiation once after the fifth anniversary of the agreement
and once during each renewal period at the election of either
party. Quest Midstream also has the sole discretion to cease
providing services on all or any part of its gathering system if
it determines that continued operation is not economically
justified. If Quest Midstream elects to do so, it must
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provide us with 90 days written notice and will offer
us the right to purchase that part of the terminated system. If
we do acquire that part of the system and it remains connected
to any other portion of Quest Midstreams gathering system,
then we may deliver our gas from the terminated system to Quest
Midstreams system, and a fee for any services provided by
Quest Midstream will be negotiated.
In addition, Quest Midstream agreed to install the saltwater
disposal lines for our gas wells connected to Quest
Midstreams gathering system for a fee of $1.25 per linear
foot and connect such lines to our saltwater disposal wells for
a fee of $1,000 per well, subject to an annual adjustment based
on changes in the Employment Cost Index for Natural Resources,
Construction, and Maintenance. For 2008, we anticipate the fees
will be $1.29 per linear foot to install saltwater disposal
lines and $1,030 per well to connect such lines to our saltwater
disposal wells.
The midstream services agreement also requires the drilling of a
minimum of 750 new wells in the Cherokee Basin during the two
year period ending December 1, 2008, 575 of which have been
drilled in the Cherokee Basin through December 31, 2007. We
expect to drill 325 wells in 2008.
Marketing
and Major Customers
We market our own natural gas. For the year ended
December 31, 2007, approximately 79% of our gas was sold to
ONEOK Energy Marketing and Trading Company (ONEOK)
and 21% was sold to Tenaska Marketing Ventures
(Tenaska). For the period from November 15,
2007 through December 31, 2007, approximately 100% of our
natural gas was sold to ONEOK. More than 95% of our natural gas
was sold to ONEOK in 2006 and 2005. No other customer accounted
for more than 10% of our consolidated revenues for the years
ended December 31, 2007, 2006 and 2005.
Our oil is currently being sold to Coffeyville Refining.
Previously, it had been sold to Plains Marketing, L.P. We do not
have long term delivery commitments for our gas and oil
production.
If we were to lose any of these gas and oil purchasers, we
believe that we would be able to promptly replace the purchaser.
Hedging
Activities
We seek to mitigate our exposure to volatility in commodity
prices through our use of derivative contracts including
fixed-price contracts comprised of energy swaps and collars. As
of December 31, 2007, we had entered into derivative
contracts with respect to approximately 80% of our total
estimated net production from proved developed producing
reserves through the fourth quarter of 2010. These fixed price
swaps and collars cover 40% and 40%, respectively, of our
estimated net gas production from proved developed producing
reserves in 2008 or 29% and 29%, respectively, of our total
estimated net production for 2008. In addition, for 2009 and
2010, these fixed price swaps cover 80% and 80%, respectively,
of our estimated net gas production from proved developed
producing reserves. By removing a significant portion of price
volatility of our future gas production we have mitigated, but
not eliminated, the potential effects of changing gas prices on
our cash flows from operations for those periods. We sell the
majority of our gas based on the Southern Star first of month
index, with the remainder sold on the daily price on the
Southern Star index. All of these derivative contracts are based
on the Southern Star first of month index, except for some of
our older collar agreements covering approximately 2.9 Bcf
of gas in 2008 (17% of our estimated net gas production from
proved developed producing reserves) and fixed price swaps
covering approximately 4.8 Bcf of gas in 2008 (27% of our
estimated net gas production from proved developed producing
reserves) that are based on NYMEX pricing. As a result, our
derivative contracts do not expose us to basis differential
risk, except for the NYMEX collars and swaps. As of
December 31, 2007, we had entered into derivative contracts
locking the basis differential on approximately 25% of these
NYMEX volumes at a weighted average rate of approximately $1.09
per Mcf. For more information on our derivative contracts, see
Note 6. Financial Instruments and Note 7. Derivatives,
in the notes to the consolidated/carve out financial statements
included in Item 8 of this report.
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Competition
We operate in a highly competitive environment for acquiring
properties, marketing gas and oil and securing trained
personnel. Many of our competitors possess and employ financial,
technical and personnel resources substantially greater than
ours, which can be particularly important in the areas in which
we operate. As a result, our competitors may be able to pay more
for productive gas and oil properties and exploratory prospects
and to evaluate, bid for and purchase a greater number of
properties and prospects than our financial or personnel
resources permit. Our ability to acquire additional prospects
and to find and develop reserves in the future will depend on
our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
Also, there is substantial competition for capital available for
investment in the gas and oil industry. None of our Parent or
any of its affiliates is restricted from competing with us
outside the Cherokee Basin. Our Parent or its affiliates may
acquire, invest in or dispose of assets outside the Cherokee
Basin in the future without any obligation to offer us the
opportunity to purchase or own interests in those assets.
We are also affected by competition for drilling rigs,
completion rigs and the availability of related equipment. In
the past, the gas and oil industry has experienced shortages of
drilling and completion rigs, equipment, pipe and personnel,
which has delayed development drilling and other exploitation
activities and has caused significant increases in the prices
for this equipment and personnel. We are unable to predict when,
or if, such shortages may occur or how they would affect our
exploitation program.
Competition is also strong for attractive gas and oil producing
properties, undeveloped leases and drilling rights, and we
cannot assure you that we will be able to compete satisfactorily
when attempting to make further acquisitions.
Title to
Properties
As is customary in the gas and oil industry, we initially
conduct only a cursory review of the title to our properties on
which we do not have proved reserves. Prior to the commencement
of development operations on those properties, we conduct a
thorough title examination and perform curative work with
respect to significant defects. To the extent title opinions or
other investigations reflect title defects on those properties,
we are typically responsible for curing any title defects at our
expense. We generally will not commence development operations
on a property until we have cured any material title defects on
such property. Prior to completing an acquisition of producing
gas and oil leases, we perform title reviews on the most
significant leases and, depending on the materiality of
properties, we may obtain a title opinion or review previously
obtained title opinions. As a result, we believe that we have
satisfactory title to our producing properties in accordance
with standards generally accepted in the gas and oil industry.
Although title to these properties is subject to encumbrances in
some cases, such as customary interests generally retained in
connection with the acquisition of real property, customary
royalty interests and contract terms and restrictions, liens
under operating agreements, liens related to environmental
liabilities associated with historical operations, liens for
current taxes and other burdens, easements, restrictions and
minor encumbrances customary in the gas and oil industry, we
believe that none of these liens, restrictions, easements,
burdens and encumbrances will materially detract from the value
of these properties or from our interest in these properties or
will materially interfere with our use in the operation of our
business. In addition, we believe that we have obtained
sufficient rights-of-way grants and permits from public
authorities and private parties for us to operate our business
in all material respects as described in this report.
On a small percentage of our acreage (less than 1.0%), the land
owner in the past transferred the rights to the coal underlying
their land to a third party. With respect to those properties,
we have obtained gas and oil leases from the owners of the oil,
gas, and minerals other than coal underlying those lands. In
Oklahoma and Kansas, the law is unsettled as to whether the
owner of the gas rights or the coal rights is entitled to the
CBM gas. We are currently involved in litigation with the owner
of the coal rights on these lands to determine who has the
rights to the CBM gas. Please read Legal Proceedings
under Item 3 of this report.
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Seasonal
Nature of Business
Seasonal weather conditions and lease stipulations can limit our
development activities and other operations and, as a result, we
seek to perform a significant percentage of our development
during the spring and summer months. These seasonal anomalies
can pose challenges for meeting our well development objectives
and increase competition for equipment, supplies and personnel
during the spring and summer months, which could lead to
shortages and increase costs or delay our operations.
In addition, freezing weather, winter storms and flooding in the
spring and summer have in the past resulted in a number of our
wells being knocked off-line for a short period of time, which
adversely affects our production volumes and revenues and
increases our lease operating costs due to the time spent by
field employees to bring the wells back on-line.
Generally, but not always, the demand for gas decreases during
the summer months and increases during the winter months thereby
affecting the price we receive for gas. Seasonal anomalies such
as mild winters and hot summers sometimes lessen this
fluctuation.
Environmental
Matters and Regulation
General.
Our operations are subject to
stringent and complex federal, state and local laws and
regulations governing environmental protection as well as the
discharge of materials into the environment. These laws and
regulations may, among other things:
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require the acquisition of various permits before drilling
commences;
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enjoin some or all of the operations of facilities deemed in
non-compliance with permits;
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with gas and oil drilling, production and
transportation activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands, areas inhabited by endangered or
threatened species, and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
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These laws, rules and regulations may also restrict the rate of
gas and oil production below the rate that would otherwise be
possible. The regulatory burden on the gas and oil industry
increases the cost of doing business in the industry and
consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise environmental laws
and regulations, and the clear trend in environmental regulation
is to place more restrictions and limitations on activities that
may affect the environment. Any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the gas and oil industry could have a
significant impact on our operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Waste Handling.
The Resource Conservation and
Recovery Act, or RCRA, and comparable state statutes, regulate
the generation, transportation, treatment, storage, disposal and
cleanup of hazardous and non-hazardous solid wastes. Under the
auspices of the federal Environmental Protection Agency, or EPA,
the individual states administer some or all of the provisions
of RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the
other wastes associated with the exploration, development, and
production of gas and oil are currently regulated under
RCRAs non-hazardous waste provisions. However, it is
possible that certain gas and oil exploration and production
wastes now classified as non-hazardous could be classified as
hazardous wastes in the future. Any such change could result in
an increase in our costs to manage and dispose of wastes, which
could have a material adverse effect on our results of
operations and financial position. Also, in the course of our
operations, we generate some amounts of ordinary industrial
wastes, such as paint wastes, waste solvents, and waste oils,
that may be regulated as hazardous wastes.
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Comprehensive Environmental Response, Compensation and
Liability Act.
The Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, also known
as the Superfund law, imposes joint and several liability,
without regard to fault or legality of conduct, on classes of
persons who are considered to be responsible for the release of
a hazardous substance into the environment. These persons
include the current and past owner or operator of the site where
the release occurred, and anyone who disposed or arranged for
the disposal of a hazardous substance released at the site.
Under CERCLA, such persons may be subject to joint and several
liability for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to
natural resources, and for the costs of certain environmental
studies. In addition, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous
substances released into the environment.
We currently own, lease or operate numerous properties that have
been used for gas and oil exploration and production for many
years. Although we believe that we have utilized operating and
waste disposal practices that were standard in the industry at
the time, hazardous substances, wastes, or hydrocarbons may have
been released on or under the properties owned or leased by us,
or on or under other locations, including off-site locations,
where such substances have been taken for disposal. In addition,
some of our properties have been operated by third parties or by
previous owners or operators whose treatment and disposal of
hazardous substances, wastes, or hydrocarbons was not under our
control. In fact, there is evidence that petroleum spills or
releases have occurred in the past at some of the properties
owned or leased by us. These properties and the substances
disposed or released on them may be subject to CERCLA, RCRA, and
analogous state laws. Under such laws, we could be required to
remove previously disposed substances and wastes, remediate
contaminated property, or perform plugging or pit closure
operations to prevent future contamination.
Water Discharges.
The Clean Water Act, or CWA,
and analogous state laws, impose restrictions and strict
controls with respect to the discharge of pollutants in waste
water and storm water, including spills and leaks of oil and
other substances, into waters of the United States. The
discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by EPA or
an analogous state agency. The CWA regulates storm water run-off
from oil and gas production operations and requires a storm
water discharge permit for certain activities. Such a permit
requires the regulated facility to monitor and sample storm
water run-off from its operations. The CWA and regulations
implemented thereunder also prohibit the discharge of dredge and
fill material into regulated waters, including wetlands, unless
authorized by an appropriately issued permit. Spill prevention,
control and countermeasure requirements of the CWA may require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak. Federal and
state regulatory agencies can also impose administrative, civil
and criminal penalties for non-compliance with discharge permits
or other requirements of the CWA and analogous state laws and
regulations.
Our operations also produce wastewaters that are disposed via
underground injection wells. These activities are regulated by
the Safe Drinking Water Act, or SDWA, and analogous state and
local laws. The underground injection well program under the
SDWA classifies produced wastewaters and imposes controls
relating to the drilling and operation of the wells as well as
the quality of the injected wastewaters. This program is
designed to protect drinking water sources and requires a permit
from the EPA or the designated state agency in our
case, the Oklahoma Corporation Commission and the Kansas
Corporation Commission. Currently, our operations comply with
all applicable requirements and have a sufficient number of
operating injection wells. However, a change in the regulations
or the inability to obtain new injection well permits in the
future may affect our ability to dispose of the produced waters
and ultimately affect the results of operations.
The primary federal law for oil spill liability is the Oil
Pollution Act, or OPA, which addresses three principal areas of
oil pollution: prevention, containment, and cleanup. OPA applies
to vessels, offshore facilities, and onshore facilities,
including exploration and production facilities that may affect
waters of the United States. Under OPA, responsible parties,
including owners and operators of onshore facilities, may be
subject to oil cleanup costs and natural resource damages as
well as a variety of public and private damages that may result
from oil spills.
Air Emissions.
The Federal Clean Air Act, or
CAA, and comparable state laws regulate emissions of various air
pollutants through air emissions permitting programs and the
imposition of other requirements. Such laws and
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regulations may require a facility to obtain pre-approval for
the construction or modification of certain projects or
facilities expected to produce air emissions or result in the
increase of existing air emissions, obtain or strictly comply
with air permits containing various emissions and operational
limitations or utilize specific emission control technologies to
limit emissions. In addition, EPA has developed, and continues
to develop, stringent regulations governing emissions of toxic
air pollutants at specified sources. Moreover, depending on the
state-specific statutory authority, states may be able to impose
air emissions limitations that are more stringent than the
federal standards imposed by EPA. Federal and state regulatory
agencies can also impose administrative, civil and criminal
penalties for non-compliance with air permits or other
requirements of the federal CAA and associated state laws and
regulations.
Permits and related compliance obligations under the CAA, as
well as changes to state implementation plans for controlling
air emissions in regional non-attainment areas, may require gas
and oil exploration and production operations to incur future
capital expenditures in connection with the addition or
modification of existing air emission control equipment and
strategies. In addition, some gas and oil facilities may be
included within the categories of hazardous air pollutant
sources, which are subject to increasing regulation under the
CAA. Failure to comply with these requirements could subject a
regulated entity to monetary penalties, injunctions, conditions
or restrictions on operations and enforcement actions. Gas and
oil exploration and production facilities may be required to
incur certain capital expenditures in the future for air
pollution control equipment in connection with obtaining and
maintaining operating permits and approvals for air emissions.
Such laws and regulations may require that we obtain
pre-approval for the construction or modification of certain
projects or facilities expected to produce air emissions or
result in the increase of existing air emissions, obtain and
strictly comply with air permits containing various emissions
and operational limitations, or use specific emission control
technologies to limit emissions. Our failure to comply with
these requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. Historically, air
pollution control has become more stringent over time. This
trend is expected to continue. The cost of technology and
systems to control air pollution to meet regulatory requirements
is significant today. These costs are expected to increase as
air pollution control requirements increase. We believe,
however, that our operations will not be materially adversely
affected by such requirements, and the requirements are not
expected to be any more burdensome to us than to any other
similarly situated companies.
The Kyoto Protocol to the United Nations Framework Convention on
Climate Change, or the Protocol, became effective in February
2005. Under the Protocol, participating nations are required to
implement programs to reduce emissions of certain gases,
generally referred to as greenhouse gases, that are
suspected of contributing to global warming. The United States
is not currently a participant in the Protocol; however,
Congress has recently considered proposed legislation directed
at reducing greenhouse gas emissions, and certain
states have adopted legislation, regulations
and/or
initiatives addressing greenhouse gas emissions from various
sources, primarily power plants. Additionally, on April 2,
2007, the U.S. Supreme Court ruled in Massachusetts v.
EPA that the EPA has authority under the CAA to regulate
greenhouse gas emissions from mobile sources (e.g., cars and
trucks). The Court also held that greenhouse gases fall within
the CAAs definition of air pollutant, which
could result in future regulation of greenhouse gas emissions
from stationary sources, including those used in gas and oil
exploration and production operations. The gas and oil industry
is a direct source of certain greenhouse gas emissions, namely
carbon dioxide and methane, and future restrictions on such
emissions could impact our future operations. Our operations are
not adversely impacted by the current state and local climate
change initiatives and, at this time, it is not possible to
accurately estimate how potential future laws or regulations
addressing greenhouse gas emissions would impact our business.
Hydrogen Sulfide.
Hydrogen sulfide gas is a
byproduct of sour gas treatment. Exposure to unacceptable levels
of hydrogen sulfide (known as sour gas) is harmful to humans,
and prolonged exposure can result in death. We employ numerous
safety precautions to ensure the safety of our employees. There
are various federal and state environmental and safety
requirements that apply to facilities using or producing
hydrogen sulfide gas. Notwithstanding compliance with such
requirements, common law causes of action are available to
persons damaged by exposure to hydrogen sulfide gas.
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National Environmental Policy Act
. Gas and oil
exploration and production activities on federal lands are
subject to the National Environmental Policy Act, or NEPA. NEPA
requires federal agencies, including the Department of Interior,
to evaluate major agency actions having the potential to
significantly impact the environment. In the course of such
evaluations, an agency will prepare an Environmental Assessment
that assesses the potential direct, indirect and cumulative
impacts of a proposed project and, if necessary, will prepare a
more detailed Environmental Impact Statement that may be made
available for public review and comment. If we were to conduct
any exploration and production activities on federal lands in
the future, those activities would need to obtain governmental
permits that are subject to the requirements of NEPA. This
process has the potential to delay the development of gas and
oil projects.
Endangered Species Act.
The Endangered Species
Act and analogous state laws restrict activities that may affect
endangered or threatened species or their habitats. Although we
believe that our current operations do not affect endangered or
threatened species or their habitats, the existence of
endangered or threatened species in areas of future operations
and development could cause us to incur additional mitigation
costs or become subject to construction or operating
restrictions or bans in the affected areas.
OSHA and Other Laws and Regulation.
We are
subject to the requirements of the federal Occupational Safety
and Health Act, or OSH Act, and comparable state statutes. These
laws and the implementing regulations strictly govern the
protection of the health and safety of employees. The
Occupational Safety and Health Administrations hazard
communication standard, EPA community right-to-know regulations
under the Title III of CERCLA and similar state statutes
require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
comparable laws.
We believe that we are in substantial compliance with all
existing environmental and safety laws and regulations
applicable to our current operations and that our continued
compliance with existing requirements will not have a material
adverse impact on our financial condition and results of
operations. For instance, we did not incur any material capital
expenditures for remediation or pollution control activities for
the year ended December 31, 2007. Additionally, as of the
date of this report, we are not aware of any environmental
issues or claims that will require material capital expenditures
during 2008. However, accidental spills or releases may occur in
the course of our operations, and we cannot assure you that we
will not incur substantial costs and liabilities as a result of
such spills or releases, including those relating to claims for
damage to property and persons. Moreover, we cannot assure you
that the passage of more stringent laws or regulations in the
future will not have a negative impact on our business,
financial condition, results of operations or ability to make
distributions to you.
Other
Regulation of the Gas and Oil Industry
The gas and oil industry is extensively regulated by numerous
federal, state and local authorities. Legislation affecting the
gas and oil industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Also,
numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations binding on
the gas and oil industry and its individual members, some of
which carry substantial penalties for failure to comply.
Although the regulatory burden on the gas and oil industry
increases our cost of doing business and, consequently, affects
our profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect
other companies in the industry with similar types, quantities
and locations of production.
Legislation continues to be introduced in Congress and
development of regulations continues in the Department of
Homeland Security and other agencies concerning the security of
industrial facilities, including gas and oil facilities. Our
operations may be subject to such laws and regulations.
Presently, it is not possible to accurately estimate the costs
we could incur to comply with any such facility security laws or
regulations, but such expenditures could be substantial.
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Drilling and Production.
Our operations are
subject to various types of regulation at federal, state and
local levels. These types of regulation include requiring
permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states, and some counties and
municipalities, in which we operate also regulate one or more of
the following:
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the location of wells;
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells
are drilled;
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the plugging and abandoning of wells; and
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notice to surface owners and other third parties.
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State laws regulate the size and shape of drilling and spacing
units or proration units governing the pooling of gas and oil
properties. Some states allow forced pooling or integration of
tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and
may reduce our interest in the unitized properties. In addition,
state conservation laws establish maximum rates of production
from gas and oil wells, generally prohibit the venting or
flaring of gas and impose requirements regarding the ratability
of production. These laws and regulations may limit the amount
of gas and oil we can produce from our wells or limit the number
of wells or the locations at which we can drill. Moreover, each
state generally imposes a production or severance tax with
respect to the production and sale of oil, gas and gas liquids
within its jurisdiction.
The Cherokee Basin has been an active gas and oil producing
region for a number of years. Many of our properties had
abandoned oil and conventional gas wells on them at the time the
current lease was entered into with the landowner. A number of
these wells remain unplugged or were improperly plugged by a
prior landowner or operator. Many of the former operators of
these wells have ceased operations and cannot be located or do
not have the financial resources to plug these wells. We believe
that we are not responsible for plugging an abandoned well on
one of our leases, unless we have used, attempted to use or
invaded the abandoned well bore in our operations on the land or
have otherwise agreed to assume responsibility for plugging the
wells. The law is unsettled in the State of Kansas as to who has
the responsibility to plug such abandoned wells and the Kansas
Corporation Commission, or KCC, issued a Show Cause Order in
February 2007 requiring our operating company, Quest Cherokee,
to demonstrate why it should not be held responsible for
plugging 22 abandoned and unplugged oil wells on land covered by
a gas lease that is owned and operated by Quest Cherokee in
Wilson County, Kansas, and upon which Quest Cherokee has drilled
and is operating a gas well. Please read Legal
Proceedings under Item 3 of this report.
Gas Marketing.
The availability, terms and
cost of transportation significantly affect sales of gas. The
interstate transportation and sale for resale of gas is subject
to federal regulation, including regulation of the terms,
conditions and rates for interstate transportation, storage and
various other matters, primarily by the Federal Energy
Regulatory Commission or FERC. Federal and state regulations
govern the price and terms for access to gas pipeline
transportation. FERC is continually proposing and implementing
new rules and regulations affecting those segments of the gas
industry, most notably interstate gas transmission companies
that remain subject to the FERCs jurisdiction. These
initiatives also may affect the intrastate transportation of gas
under certain circumstances. The stated purpose of many of these
regulatory changes is to promote competition among the various
sectors of the gas industry, and these initiatives generally
reflect more light handed regulation. We cannot predict the
ultimate impact of these regulatory changes to our gas marketing
operations, and we note that some of the FERCs more recent
proposals may adversely affect the availability and reliability
of interruptible transportation service on interstate pipelines.
We do not believe that we will be affected by any such FERC
action materially differently than other gas marketers with
which we compete.
The Energy Policy Act of 2005, or EP Act 2005, gave the FERC
increased oversight and penalty authority regarding market
manipulation and enforcement. EP Act 2005 amended the NGA to
prohibit market manipulation and also amended the Natural Gas
Act of 1938, or NGA, and the Natural Gas Policy Act of 1978, or
NGPA, to increase civil and criminal penalties for any
violations of the NGA, NGPA and any rules, regulations or orders
of the FERC to up to $1,000,000 per day, per violation. In
addition, the FERC issued a final rule effective
January 26, 2006
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regarding market manipulation, which makes it unlawful for any
entity, in connection with the purchase or sale of gas or
transportation service subject to the FERCs jurisdiction,
to defraud, make an untrue statement or omit a material fact or
engage in any practice, act or course of business that operates
or would operate as a fraud. This final rule works together with
the FERCs enhanced penalty authority to provide increased
oversight of the gas marketplace.
Although gas prices are currently unregulated, FERC promulgated
regulations in December 2007 requiring natural gas sellers to
submit an annual report, beginning in May 2009, reporting
certain information regarding natural gas purchases and sales
(
e.g.
, total volumes bought and sold, volumes bought and
sold and index prices, etc.). Additionally, Congress
historically has been active in the area of gas regulation. We
cannot predict whether new legislation to regulate gas might be
proposed, what proposals, if any, might actually be enacted by
Congress or the various state legislatures, and what effect, if
any, the proposals might have on the operations of the
underlying properties. Sales of condensate and gas liquids are
not currently regulated and are made at market prices.
State Regulation.
The various states regulate
the drilling for, and the production, gathering and sale of, gas
and oil, including imposing severance taxes and requirements for
obtaining drilling permits. For example, Kansas currently
imposes a severance tax on the gross value of gas and oil
produced from wells having an average daily production during a
calendar month with a gross value of more than $87 per day.
Kansas also imposes gas and oil conservation assessments per
barrel of oil and per 1,000 cubic feet of gas produced. In
general, gas and oil leases and gas and oil wells (producing or
capable of producing), including all equipment associated with
such leases and wells, are subject to an ad valorem property tax.
Oklahoma imposes a monthly gross production tax and excise tax
based on the gross value of the gas and oil produced. Oklahoma
also imposes an excise tax based on the gross value of gas and
oil produced. All property used in the production of gas and oil
is exempt from ad valorem taxation if gross production taxes are
paid. Lastly, the rate of taxation of locally assessed property
varies from county to county and is based on the fair cash value
of personal property and the fair cash value of real property.
States may regulate rates of production and may establish
maximum daily production allowables from gas and oil wells based
on market demand or resource conservation, or both. States do
not regulate wellhead prices or engage in other similar direct
economic regulation, but there can be no assurance that they
will not do so in the future. The effect of these regulations
may be to limit the amounts of gas and oil that may be produced
from our wells and to limit the number of wells or locations we
can drill.
Other
In addition to existing laws and regulations, the possibility
exists that new legislation or regulations may be adopted which
would have a significant impact on our operations or our
customers ability to use gas and may require us or our
customers to change their operations significantly or incur
substantial costs. Additional proposals and proceedings that
might affect the gas industry are pending before Congress, FERC,
the Minerals Management Service, state commissions and the
courts. We cannot predict when or whether any such proposals may
become effective. In the past, the natural gas industry has been
heavily regulated. There is no assurance that the regulatory
approach currently pursued by various agencies will continue
indefinitely.
Failure to comply with these laws and regulations may result in
the assessment of administrative, civil
and/or
criminal penalties, the imposition of injunctive relief or both.
Moreover, changes in any of these laws and regulations could
have a material adverse effect on our business. In view of the
many uncertainties with respect to current and future laws and
regulations, including their applicability to us, we cannot
predict the overall effect of such laws and regulations on our
future operations.
Management believes that our operations comply in all material
respects with applicable laws and regulations and that the
existence and enforcement of such laws and regulations have no
more restrictive effect on our method of operations than on
other similar companies in the energy industry. We have internal
procedures and policies to ensure that our operations are
conducted in substantial regulatory compliance.
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Employees
At March 1, 2008, we employed approximately 250 field
employees that perform development and maintenance services on
our wells. We entered into a management services agreement with
Quest Energy Service, LLC pursuant to which it performs
administrative services for us such as accounting, finance,
land, legal and engineering. We also have access to Quest Energy
Services personnel and senior management team and access
to its operational, commercial, technical, risk management and
administrative infrastructure. Quest Energy Service has an
experienced staff of approximately 60 executive and
administrative personnel. None of these employees are
represented by labor unions or covered by any collective
bargaining agreement. Quest Energy Service and our general
partner believe that relations with these employees are
satisfactory.
Administrative
Facilities
Our principal executive offices are located at 210 Park Avenue,
Suite 2750, Oklahoma City, Oklahoma 73102, which is also
where our Parents principal executive offices are located.
Our Parent leases this office space, and the lease covers
approximately 35,000 square feet with annual rental costs
of approximately $631,000. The lease is for 10 years
expiring in August 31, 2017.
We own a building located at 211 West 14th Street in
Chanute, Kansas 66720 that we use as an administrative office,
an operations terminal and a repair facility. We own an
additional building on Johnson Road for field offices. An office
building at 127 West Main in Chanute, Kansas is owned and
operated by us as a geological laboratory.
Available
Information
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934, or Exchange Act, are made available free of charge on our
website at www.qelp.net as soon as reasonably practicable after
these reports have been electronically filed with, or furnished
to, the SEC. These documents are also available at the
SECs website at www.sec.gov or you may read and copy any
materials that we file with the SEC at the SECs Public
Reference Room at 100 F Street, NE, Washington DC
20549. Our website also includes our Code of Business Conduct
and Ethics and the charter of the audit committee of the board
of directors of our general partner. No information from either
the SECs website or our website is incorporated herein by
reference.
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GLOSSARY
OF SELECTED TERMS
The following is a description of the meanings of some of the
oil and natural gas industry terms used in this
Form 10-K.
Bbl.
One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
Bbl/d.
One Bbl per day.
Bcf.
One billion cubic feet of gas.
Bcfe.
One billion cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of crude
oil, condensate or gas liquids.
Btu
or
British Thermal Unit.
The
quantity of heat required to raise the temperature of a one
pound mass of water by one degree Fahrenheit.
CBM.
Coal bed methane.
Cherokee Basin.
A fifteen-county region in
southeastern Kansas and northeastern Oklahoma.
Completion.
The installation of permanent
equipment for the production of oil or gas, or in the case of a
dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage.
The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development well.
A well drilled within the
proved boundaries of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Dry hole
or
dry well.
A well found to
be incapable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of such production exceed
production expenses and taxes.
Eligible Holder.
A person or entity qualified
to hold an interest in gas and oil leases on federal lands. As
of the date hereof, an Eligible Holder means: (1) a citizen
of the United States; (2) a corporation organized under the
laws of the United States or of any state thereof; (3) a
public body, including a municipality; or (4) an
association of United States citizens, such as a partnership or
limited liability company, organized under the laws of the
United States or of any state thereof, but only if such
association does not have any direct or indirect foreign
ownership, other than foreign ownership of stock in a parent
corporation organized under the laws of the United States
or of any state thereof.
Exploitation.
A development or other project
which may target proven or unproven reserves (such as probable
or possible reserves), but which generally has a lower risk than
that associated with exploration projects.
Exploratory well.
A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Field.
An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Frac/fracturing.
The method used to increase
the deliverability of a well by pumping a liquid or other
substance into a well under pressure to crack and prop open the
hydrocarbon formation.
Gas.
Hydrocarbon gas found in the earth,
composed of methane, ethane, butane, propane and other gases.
Gathering system.
Pipelines and other
equipment used to move gas from the wellhead to the trunk or the
main transmission lines of a pipeline system.
Gross acres
or
gross wells.
The total
acres or wells, as the case may be, in which we have a working
interest.
Horizon
or
formation.
The section of
rock, from which gas is expected to be produced.
Mcf.
One thousand cubic feet of gas.
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Mcf/d.
One Mcf per day.
Mcfe.
One thousand cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of crude
oil, condensate or gas liquids.
MMBtu.
One million British thermal units.
MMcf.
One million cubic feet of gas.
MMcf/d.
One
MMcf per day.
MMcfe.
One Mcf equivalent, determined using
the ratio of six Mcf of gas to one Bbl of crude oil, condensate
or gas liquids.
Mmcfe/d.
One Mmcfe per day.
Net acres
or
net wells.
The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
Net production.
Production that is owned by us
less royalties and production due others.
Net revenue interest.
The percentage of
revenues due an interest holder in a property, net of royalties
or other burdens on the property.
NGLs.
The combination of ethane, propane,
butane and natural gasolines that when removed from natural gas
become liquid under various levels of higher pressure and lower
temperature.
NYMEX.
The New York Mercantile Exchange.
Oil.
Crude oil, condensate and NGLs.
Permeability.
The ease of movement of water
and/or
gases
through a soil material.
Perforation.
The making of holes in casing and
cement (if present) to allow formation fluids to enter the well
bore.
Productive well.
A well that produces
commercial quantities of hydrocarbons exclusive of its capacity
to produce at a reasonable rate of return.
Proved developed non-producing
reserves.
Proved developed reserves expected to
be recovered from zones behind casings in existing wells.
Proved developed reserves.
Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods. This definition of
proved developed reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the internet
at
http://www.sec.gov/about/forms/regs-x.pdf.
Proved reserves.
The estimated quantities of
crude oil, natural gas and NGLs that geological and engineering
data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions. This definition of proved reserves has
been abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the internet
at
http://www.sec.gov/about/forms/regs-x.pdf.
Proved undeveloped reserves
or
PUDs.
Proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on acreage
yet to be drilled for which the existence and recoverability of
such reserves can be estimated with reasonable certainty, or
from existing wells where a relatively major expenditure is
required to establish production. This definition of proved
undeveloped reserves has been abbreviated from the applicable
definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the internet
at www.sec.gov/about/forms/regs-x.pdf.
Recompletion.
The completion for production of
an existing wellbore in another formation from that which the
well has been previously completed.
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Reserve.
That part of a mineral deposit which
could be economically and legally extracted or produced at the
time of the reserve determination.
Reserve-to-production ratio.
This ratio is
calculated by dividing estimated net proved reserves by the
production from the previous year to estimate the number of
years of remaining production.
Reservoir.
A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or
gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
Royalty Interest.
A real property interest
entitling the owner to receive a specified portion of the gross
proceeds of the sale of oil and natural gas production or, if
the conveyance creating the interest provides, a specific
portion of oil or natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and
gas. A royalty interest owner has no right to consent to or
approve the operation and development of the property, while the
owners of the working interests have the exclusive right to
exploit the mineral on the land.
Shut in.
Stopping an oil or gas well from
producing.
Standardized measure.
The present value of
estimated future net revenue to be generated from the production
of proved reserves, determined in accordance with the rules and
regulations of the SEC (using prices and costs in effect as of
the date of estimation), less future development, production and
income tax expenses, and discounted at 10% per annum to reflect
the timing of future net revenue. Our standardized measure does
not reflect any future income tax expenses because we are not
subject to federal income taxes. Our standardized measure
differs from the standardized measure presented in the
historical audited financial statements of the Predecessor
included in this report due to the exclusion of future income
tax expense. Standardized measure does not give effect to
derivative transactions.
Unconventional resource development.
A
development in which the targeted reservoirs generally fall into
three categories: (1) tight sands, (2) coal beds, and
(3) gas shales. The reservoirs tend to cover large areas
and lack the readily apparent traps, seals and discrete
hydrocarbon-water boundaries that typically define conventional
reservoirs. These reservoirs generally require stimulation
treatments or other special recovery processes in order to
produce economic flow rate.
Undeveloped acreage.
Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Working interest.
The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
Limited partner interests are inherently different from
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in similar businesses. The
following risk factors should be carefully considered together
with all of the other information included in this report. If
any of the following risks and uncertainties described below or
elsewhere in this report were actually to occur, our business,
financial condition or results of operations could be materially
adversely affected. In that case, we may not be able to pay
distributions on our common units, the trading price of our
common units could decline, and unitholders could lose all or
part of their investment.
Risks
Related to Our Business
We may
not have sufficient cash flow from operations to pay quarterly
distributions on our common units following the establishment of
cash reserves and the payment of fees and expenses, including
reimbursements of expenses to our general partner and its
affiliates.
We may not have sufficient available cash flow from operations
each quarter to pay the initial quarterly distribution of $0.40
per common unit following establishment of cash reserves and
payment of fees and expenses,
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including payments to our general partner and its affiliates.
Under the terms of our partnership agreement, the amount of cash
otherwise available for distribution will be reduced by our
operating expenses and the amount of any cash reserves that our
general partner establishes to provide for future operations,
future capital expenditures, future debt service requirements
and future cash distributions to our unitholders. Further, our
credit facility contains, and future debt agreements may
contain, restrictions on our ability to pay distributions. We
intend to reserve a substantial portion of our cash generated
from operations to develop our gas properties and to acquire
additional gas and oil properties in order to maintain and grow
our level of reserves. The amount of cash we can distribute on
our common units principally depends upon the amount of cash we
generate from our operations, which will fluctuate from quarter
to quarter based on numerous factors, including, among other
things:
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the amount of gas and oil we produce;
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the demand for and the price at which we are able to sell our
gas and oil production;
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the results of our hedging activity;
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the costs incurred for continued development of gas wells and
proved undeveloped properties;
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the level of our operating costs, including reimbursements of
expenses to our general partner and its affiliates;
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timing and collectability of receivables;
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prevailing economic conditions;
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our ability to acquire additional gas and oil properties at
economically attractive prices;
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our ability to continue our exploitation activities at
economically attractive costs;
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the level of our interest expense, which depends on the amount
of our indebtedness and the interest payable thereon; and
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the level of our capital expenditures.
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As a result of these factors, the amount of cash we distribute
in any quarter to our unitholders may fluctuate significantly
from quarter to quarter and may be significantly less than the
minimum quarterly distribution amount. For a description of
additional restrictions and factors that may affect our ability
to make cash distributions, please read Market for
Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities Cash
Distributions to Unitholders under Item 5 of this
report.
Gas
prices are at relatively high levels and are very volatile, and
if commodity prices decline significantly for a temporary or
prolonged period, our cash flow from operations will decline and
we may have to lower our quarterly distributions or may not be
able to pay distributions at all.
Our revenue, profitability and cash flow depend upon the prices
and demand for gas and oil, and a drop in prices can
significantly affect our financial results and impede our
growth. In particular, declines in commodity prices will reduce
the value of our reserves, our cash flow, our ability to borrow
money or raise capital and our ability to pay distributions. Gas
prices have been at high levels over the past several years when
compared to prior years. The gas market is very volatile, and we
cannot predict future gas prices. Prices for gas may fluctuate
widely in response to relatively minor changes in the supply of
and demand for gas, market uncertainty and a variety of
additional factors that are beyond our control, such as:
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the domestic and foreign supply of and demand for gas;
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the price and level of foreign imports of gas and oil;
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the level of consumer product demand;
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weather conditions;
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overall domestic and global economic conditions;
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political and economic conditions in gas and oil producing
countries, including embargoes and continued hostilities in the
Middle East and other sustained military campaigns, acts of
terrorism or sabotage;
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actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls;
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the impact of the U.S. dollar exchange rates on gas and oil
prices;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the costs, proximity and capacity of gas pipelines and other
transportation facilities; and
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the price and availability of alternative fuels.
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In the past, the prices of gas have been extremely volatile, and
we expect this volatility to continue. For example, during the
year ended December 31, 2006, the NYMEX spot price ranged
from a high of $18.41 per MMBtu to a low of $1.97 per MMBtu.
During the year ended December 31, 2007, the NYMEX monthly
gas index price (last day) ranged from a high of $7.59156 per
MMBtu to a low of $5.445 MMBtu. If we raise our
distribution levels in response to increased cash flow during
periods of relatively high commodity prices, we may not be able
to sustain those distribution levels during subsequent periods
of lower commodity prices.
Future
price declines may result in a write-down of our asset carrying
values.
Lower gas prices may not only decrease our revenues,
profitability and cash flows, but also reduce the amount of gas
that we can produce economically. This may result in our having
to make substantial downward adjustments to our estimated proved
reserves. Substantial decreases in gas prices would render a
significant number of our planned exploitation projects
uneconomic. If this occurs, or if our estimates of development
costs increase, production data factors change or drilling
results deteriorate, accounting rules may require us to write
down, as a non-cash charge to earnings, the carrying value of
our gas properties for impairments. We are required to perform
impairment tests on our assets periodically and whenever events
or changes in circumstances warrant a review of our assets. To
the extent such tests indicate a reduction of the estimated
useful life or estimated future cash flows of our assets, the
carrying value may not be recoverable and may, therefore,
require a write-down of such carrying value. For example, for
the year ended December 31, 2006, we had an impairment
charge of $30.7 million. Based on the low natural gas
prices on December 31, 2007, we would have incurred a
non-cash impairment loss of approximately $14.9 million for
the quarter ended December 31, 2007. However, under the
SECs accounting guidance in Staff Accounting
Bulletin Topic 12(D)(e), if natural gas prices increase
sufficiently between the end of a period and the completion of
the financial statements for that period to eliminate the need
for an impairment charge, an issuer is not required to recognize
the non-cash impairment loss in its financial statements for
that period. As of March 1, 2008, natural gas prices had
improved sufficiently to eliminate the need for an impairment
loss at December 31, 2007 and as a result, no impairment
loss is reflected in our financial statements for the year ended
December 31, 2007. We may incur impairment charges in the
future, which could have a material adverse effect on our
results of operations in the period incurred and on our ability
to borrow funds under our credit facility, which in turn may
adversely affect our ability to make cash distributions to our
unitholders.
Unless
we replace the reserves that we produce, our existing reserves
and production will decline, which would adversely affect our
cash from operations and our ability to make cash distributions
to our unitholders.
Producing gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir
characteristics and other factors. CBM production generally
declines at a shallow rate after initial increases in production
as a consequence of the dewatering process. Our future gas
reserves, production, cash flow and ability to make
distributions depend on our success in developing and exploiting
our current reserves efficiently and finding or acquiring
additional recoverable reserves economically. We may not be able
to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs, which would
adversely
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affect our business, financial condition and results of
operations and reduce cash available for distribution. Factors
that may hinder our ability to acquire additional reserves
include competition, access to capital, prevailing gas prices
and attractiveness of properties for sale.
As of December 31, 2007, our proved reserve-to-production
ratio was 12.3 years (8.12 years for our proved
developed properties). Because this ratio includes our proved
undeveloped reserves, we expect that this ratio will not
increase even if those proved undeveloped reserves are developed
and the wells produce as expected. The reserve-to-production
ratio reflected in our reserve report of December 31, 2007
will change if production from our existing wells declines in a
different manner than we have estimated and can change when we
drill additional wells, make acquisitions and under other
circumstances.
We
will not be able to sustain distributions at the current level
without making accretive acquisitions or capital expenditures
that maintain or grow our asset base. If our asset base
decreases and we do not reduce our distributions, a portion of
the distributions may be considered a return of part of your
investment in us as opposed to a return on your
investment.
We will not be able to sustain distributions at the current
level without making accretive acquisitions or capital
expenditures that maintain or grow our asset base. We will need
to make substantial capital expenditures to maintain and grow
our asset base, which will reduce our cash available for
distribution. Because the timing and amount of these capital
expenditures fluctuate each quarter, we expect to reserve
substantial amounts of cash each quarter to finance these
expenditures over time. We may use the reserved cash to reduce
indebtedness until we make the capital expenditures. Over a
longer period of time, if we do not set aside sufficient cash
reserves or make sufficient capital expenditures to maintain our
asset base, we will be unable to pay distributions at the
current level from cash generated from operations and would
therefore expect to reduce our distributions.
If our reserves decrease and we do not reduce our distribution,
then a portion of the distribution may be considered a return of
part of your investment in us as opposed to a return on your
investment, which would lower the return on your investment.
Also, if we do not make sufficient growth capital expenditures,
we will be unable to expand our business operations and
therefore will be unable to raise the level of future
distributions.
If our
Parent fails to present us with, or successfully competes
against us for, attractive acquisition opportunities, we may not
be able to replace or increase our reserves, which would
adversely affect our cash from operations and our ability to
make cash distributions.
We rely upon our Parent and its affiliates to identify and
evaluate for us prospective oil and natural gas properties for
acquisition. Our Parent and its affiliates are not obligated to
present us with potential acquisitions, and are not restricted
from competing with us for potential acquisitions outside the
Cherokee Basin. Because our Parent controls our general partner,
we will not be able to pursue or consummate any acquisition
opportunity unless our Parent causes us to do so. Further, we
may be unable to make acquisitions because:
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our Parent chooses to acquire oil and natural gas properties for
itself instead of allowing us to acquire them;
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the board of directors of our general partner or its conflicts
committee is unable to agree with our Parent and its affiliates
on a purchase price or on acceptable purchase terms for our
Parents properties that are attractive to all parties;
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our Parent is unable or unwilling to identify attractive
properties for us or is unable to negotiate acceptable purchase
contracts;
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we are unable to obtain financing for acquisitions on
economically acceptable terms; or
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we are outbid by competitors.
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If our Parent and its affiliates fail to present us with, or
successfully compete against us for, potential acquisitions, we
may not be able to adequately maintain our asset base, which
would adversely affect our cash from operations and our ability
to make cash distributions.
29
To
fund our growth capital expenditures, we will be required to use
cash generated from our operations, additional borrowings or the
issuance of additional partnership interests, or some
combination thereof.
Use of cash generated from operations will reduce cash available
for distribution to our unitholders. Our ability to obtain bank
financing or to access the capital markets for future equity or
debt offerings may be limited by our financial condition at the
time of any such financing or offering and the covenants in our
existing debt agreements, as well as by adverse market
conditions resulting from, among other things, general economic
conditions and contingencies and uncertainties that are beyond
our control. Our failure to obtain the funds for necessary
future capital expenditures could have a material adverse effect
on our business, results of operations, financial condition and
ability to pay distributions. Even if we are successful in
obtaining the necessary funds, the terms of such financings
could limit our ability to pay distributions to our unitholders.
In addition, incurring additional debt may significantly
increase our interest expense and financial leverage, and
issuing additional partnership interests may result in
significant unitholder dilution thereby increasing the aggregate
amount of cash required to maintain the then-current
distribution rate, which could have a material adverse effect on
our ability to pay distributions at the then-current
distribution rate.
The
amount of cash we have available for distribution to our
unitholders depends primarily on our cash flow and not solely on
our profitability.
The amount of cash we have available for distribution depends
primarily upon our cash flow, including cash from financial
reserves and working capital or other borrowings, and not solely
on our profitability, which will be affected by non-cash items.
As a result, we may make cash distributions during periods when
we record losses and may not make cash distributions during
periods when we record net income.
If we
do not make acquisitions on economically acceptable terms, our
future growth and ability to sustain or increase distributions
will be limited.
Our ability to grow and to increase distributions to unitholders
depends in part on our ability to make acquisitions that result
in an increase in pro forma available cash per unit. We may be
unable to make such acquisitions because we are: (1) unable
to identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically
acceptable terms or (3) outbid by competitors. If we are
unable to acquire properties containing proved reserves, our
total level of proved reserves will decline as a result of our
production, and we will be limited in our ability to increase or
possibly even to maintain our level of cash distributions.
Furthermore, even if we do make acquisitions that we believe
will be accretive, these acquisitions may nevertheless result in
a decrease in the cash generated from operations per unit.
Our
operations require substantial capital expenditures to increase
our asset base, which will reduce our cash available for
distribution.
In order to increase our asset base, we will need to make
substantial capital expenditures for the exploitation,
development, production and acquisition of gas and oil reserves.
These capital expenditures may include capital expenditures
associated with drilling and completion of additional wells to
offset the production decline from our producing properties or
additions to our inventory of unproved properties or our proved
reserves to the extent such additions maintain our asset base.
Management currently estimates that it will require capital
investments of approximately $41.0 million to drill and
complete an estimated 325 gross wells for 2008, and
recomplete an estimated 52 gross wells in 2008. Management
also currently estimates that it will require capital
investments of approximately $37.5 million for acreage,
equipment and vehicle replacement and purchases and salt water
disposal facilities for 2008. These expenditures could increase
as a result of:
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changes in our reserves;
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changes in gas and oil prices;
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changes in labor and drilling costs;
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our ability to acquire, locate and produce reserves;
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changes in leasehold acquisition costs; and
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government regulations relating to safety and the environment.
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Our cash flow from operations and access to capital are subject
to a number of variables, including:
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our proved reserves;
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the level of gas and oil we are able to produce from existing
wells;
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the prices at which our gas and oil is sold; and
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our ability to acquire, locate and produce new reserves.
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If we do not make sufficient or effective expansion capital
expenditures, we will be unable to expand our business
operations and will be unable to raise the level of our future
cash distributions. To fund our expansion capital expenditures
and investment capital expenditures, we will be required to use
cash from our operations or incur borrowings or sell additional
common units or other securities. Such uses of cash from
operations will reduce cash available for distribution to our
unitholders.
The
credit facility of our operating subsidiary, Quest Cherokee, (to
which we are a guarantor) has substantial restrictions and
financial covenants that may restrict our business and financing
activities and our ability to pay distributions.
The operating and financial restrictions and covenants in the
credit facility restricts our ability to finance future
operations or capital needs or to engage, expand or pursue our
business activities or to pay distributions. The credit facility
restricts our ability to:
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incur indebtedness;
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grant liens;
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make certain investments;
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enter into certain hedging agreements;
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create certain lease obligations;
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dispose of property;
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enter into certain types of agreements;
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use the loan proceeds;
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make capital expenditures above specified amounts;
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make distributions to unitholders or repurchase units;
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enter into transactions with affiliates; and
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enter into a merger, consolidation or sale of assets.
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We also are required to comply with certain financial covenants
and ratios. The credit facility requires us to maintain a
leverage ratio (the ratio of our consolidated funded debt to our
adjusted consolidated EBITDA, as defined by the credit facility)
of less than 3.50 to 1.00 determined as of the last day of each
quarter for the four-quarter period ending on the date of
determination. The credit facility requires us to maintain an
interest coverage ratio (the ratio of our adjusted consolidated
EBITDA to our consolidated interest charges, as defined by the
credit facility) of not less than 2.50 to 1.00 determined as of
the last day of each quarter for the four-quarter period ending
on the date of determination. The credit facility requires us to
maintain a current ratio (the ratio of our consolidated current
assets plus unused availability under our borrowing base to our
consolidated current liabilities excluding non-cash obligations,
asset and asset retirement obligations and current maturities of
indebtedness) of not less than 1.00 to 1.00. In the past, our
Parent has not satisfied all of the financial covenants and
ratios contained in its credit facilities. In January 2005, our
Parent determined that it was not in compliance with the
leverage and interest
31
coverage ratios under a prior secured credit agreement and, in
connection with a February 2005 amendment to such credit
agreement, our Parent was unable to drill any additional wells
until its gross daily production reached certain levels. Our
Parent was unable to reach these production goals without the
drilling of additional wells and, in the fourth quarter of 2005,
our Parent undertook a significant recapitalization that
included a private placement of its common stock and the
refinancing of its credit facilities. For the quarter ended
March 31, 2007, our Parent was not in compliance with the
maximum total debt to EBITDA ratio, and our Parent obtained a
waiver of this default from its lenders. The credit facility
generally permits us to pay distributions of available cash so
long as we are in compliance with the provisions of the credit
facility. A default under the credit facility similar to those
experienced by our Parent in the past would have precluded us
from making any distributions during the periods in which such
defaults occurred.
Our ability to comply with these restrictions and covenants in
the future is uncertain and will be affected by the levels of
cash flow from our operations and events or circumstances beyond
our control. If market or other economic conditions deteriorate,
our ability to comply with these covenants may be impaired. If
we violate any of the restrictions, covenants, ratios or tests
in the credit facility, a significant portion of our
indebtedness may become immediately due and payable, our ability
to make distributions will be inhibited and our lenders
commitment to make further loans to us may terminate. We might
not have, or be able to obtain, sufficient funds to make these
accelerated payments. In addition, our obligations under the
credit facility are secured by substantially all of our assets,
and if we are unable to repay the indebtedness under the credit
facility, the lenders could seek to foreclose on our assets.
The credit agreement limits the amount we can borrow to a
borrowing base amount, determined by the lenders in their sole
discretion. Outstanding borrowings in excess of the borrowing
base will be required to be repaid (1) within 90 days
following receipt of notice of the new borrowing base or
(2) immediately if the borrowing base is reduced in
connection with a sale or disposition of certain properties in
excess of 5% of the borrowing base. Additionally, if the
lenders exposure under letters of credit exceeds the
borrowing base after all borrowings under the credit agreement
have been repaid, we will be required to provide additional cash
collateral.
We may
incur substantial additional debt in the future to enable us to
pay distributions to our unitholders, which may negatively
affect our ability to execute on our business
plan.
Our business requires a significant amount of capital
expenditures to maintain and grow production levels. Commodity
prices have historically been volatile and we cannot predict the
prices we will be able to realize for our production in the
future. As a result, we may be unable to pay a distribution at
the minimum quarterly distribution rate or the then-current
distribution rate without borrowing under the credit facility.
Significant declines in our production or significant declines
in realized gas prices for prolonged periods and resulting
decreases in our borrowing base may force us to reduce or
suspend distributions to our unitholders.
When we borrow to pay distributions, we are distributing more
cash than we are generating from our operations on a current
basis. This means that we are using a portion of our borrowing
capacity under the credit facility to pay distributions rather
than to maintain or expand our operations. If we use borrowings
under the credit facility to pay distributions for an extended
period of time rather than toward funding capital expenditures
and other matters relating to our operations, we may be unable
to support or grow our business. Such a curtailment of our
business activities, combined with our payment of principal and
interest on our future indebtedness to pay these distributions,
will reduce our cash available for distribution on our units. If
we borrow to pay distributions during periods of low commodity
prices and commodity prices remain low, we may have to reduce
our distribution in order to avoid excessive leverage.
Our
future debt levels may limit our flexibility to obtain
additional financing and pursue other business
opportunities.
We have the ability to incur debt, including under the credit
facility, subject to borrowing base limitations in the credit
facility. Our future indebtedness could have important
consequences to us, including:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisition or other
purposes may be impaired or such financing may not be available
on favorable terms;
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covenants contained in our existing and future debt arrangements
will require us to meet financial tests that may affect our
flexibility in planning for and reacting to changes in our
business, including possible acquisition opportunities;
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we will need a substantial portion of our cash flow to make
principal and interest payments on our indebtedness, reducing
the funds that would otherwise be available for operations,
future business opportunities and distributions to
unitholders; and
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our debt level will make us more vulnerable than our competitors
with less debt to competitive pressures or a downturn in our
business or the economy generally.
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Our ability to service our indebtedness will depend upon, among
other things, our future financial and operating performance,
which will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying business activities, acquisitions,
investments
and/or
capital expenditures, selling assets, restructuring or
refinancing our indebtedness or seeking additional equity
capital or bankruptcy protection. We may not be able to effect
any of these remedies on satisfactory terms or at all.
There
is a significant delay between the time we drill and complete a
CBM well and when the well reaches peak production. As a result,
there will be a significant lag time between when we expend
capital expenditures and when we will begin to recognize
significant cash flow from those expenditures.
Our general production profile for a CBM well averages an
initial production rate of
15-20 Mcf/d
(net), steadily rising for the first twelve months while water
is pumped off and the formation pressure is lowered until the
wells reach peak production (an average of
55-60 Mcf/d
(net)). In addition, there could be significant delays between
the time a well is drilled and completed and when the well is
connected to a gas gathering system. This delay between the time
when we expend capital expenditures to drill and complete a well
and when we will begin to recognize significant cash flow from
those expenditures may adversely affect our cash flow from
operations.
Any
acquisitions we complete are subject to substantial risks that
could reduce our ability to make distributions to
unitholders.
Even if we do make acquisitions that we believe will increase
pro forma available cash per unit, these acquisitions may
nevertheless result in a decrease in pro forma available cash
per unit. Any acquisition involves potential risks, including,
among other things:
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mistaken assumptions about reserves, future production, volumes,
revenues and costs, including synergies;
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an inability to integrate successfully the businesses we acquire;
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a decrease in our liquidity as a result of our using a
significant portion of our available cash or borrowing capacity
to finance the acquisition;
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a significant increase in our interest expense or financial
leverage if we incur additional debt to finance the acquisition;
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dilution to our unitholders and a decrease in available cash per
unit if we issue additional units to finance acquisitions;
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the assumption of unknown liabilities for which we are not
indemnified or for which our indemnity is inadequate;
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an inability to hire, train or retain qualified personnel to
manage and operate our growing business and assets;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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the incurrence of other significant charges, such as impairment
of goodwill or other intangible assets, asset devaluation or
restructuring charges;
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unforeseen difficulties operating in new product areas or new
geographic areas; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and you will not
have the opportunity to evaluate the economic, financial and
other relevant information that we will consider in determining
the application of these funds and other resources.
Our decision to acquire a property will depend in part on the
evaluation of data obtained from production reports and
engineering studies, geophysical and geological analyses and
seismic and other information, the results of which are often
inconclusive and subject to various interpretations. Also, our
reviews of acquired properties are inherently incomplete because
it generally is not feasible to perform an in-depth review of
the individual properties involved in each acquisition. Even a
detailed review of records and properties may not necessarily
reveal existing or potential problems, nor will it permit a
buyer to become sufficiently familiar with the properties to
assess fully their deficiencies and potential. Inspections may
not always be performed on every well, and environmental
problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken.
Even when problems are identified, we often assume environmental
and other risks and liabilities in connection with acquired
properties. If our acquisitions do not generate increases in
available cash per unit, our ability to make cash distributions
to our unitholders could materially decrease.
Due to
the vast majority of our current operations taking place in the
Cherokee Basin, acquisitions outside of the Cherokee Basin will
expose us to operational inefficiencies and new operational
risks.
Acquisitions outside the Cherokee Basin will expose us to
different operational risks due to potential differences, among
others, in:
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geology;
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well economics;
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availability of third party services;
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transportation charges;
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content, quantity and quality of gas and oil produced;
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volume of waste water produced;
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state and local regulations and permit requirements; and
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production, severance, ad valorem and other taxes.
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Our
estimated proved reserves are based on many assumptions that may
prove to be inaccurate. Any material inaccuracies in these
reserve estimates or underlying assumptions will materially
affect the quantities and present value of our
reserves.
It is not possible to measure underground accumulations of gas
in an exact way. Gas reserve engineering requires subjective
estimates of underground accumulations of gas and assumptions
concerning future gas prices, production levels and operating
and development costs. In estimating our level of gas reserves,
we and our independent reserve engineers make certain
assumptions that may prove to be incorrect, including
assumptions relating to:
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a constant level of future gas and oil prices;
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geological conditions;
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production levels;
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capital expenditures;
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operating and development costs;
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the effects of regulation; and
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availability of funds.
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If these assumptions prove to be incorrect, our estimates of
proved reserves, the economically recoverable quantities of gas
and oil attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and our
estimates of the future net cash flows from our reserves could
change significantly. For example, if gas prices at
December 31, 2007 had been $1.00 less per Mcf, then the
standardized measure of our proved reserves as of
December 31, 2007 would have decreased by
$125.2 million, from $322.5 million to
$197.3 million and our proved reserves would have decreased
by 10.8 Bcfe from 211.1 Bcfe to 200.1 Bcfe.
Our standardized measure is calculated using unhedged gas prices
and is determined in accordance with the rules and regulations
of the SEC. Over time, we may make material changes to reserve
estimates to take into account changes in our assumptions and
the results of actual drilling and production.
The
present value of future net cash flows from our estimated proved
reserves is not necessarily the same as the current market value
of our estimated proved reserves.
We base the estimated discounted future net cash flows from our
estimated proved reserves on prices and costs in effect on the
day of estimate. However, actual future net cash flows from our
gas properties also will be affected by factors such as:
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the actual prices we receive for gas;
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our actual operating costs in producing gas;
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the amount and timing of actual production;
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the amount and timing of our capital expenditures;
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supply of and demand for gas; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses
in connection with the development and production of gas
properties will affect the timing of actual future net cash
flows from proved reserves, and thus their actual present value.
In addition, the 10% discount factor we use when calculating
discounted future net cash flows in compliance with the
Financial Accounting Standards Boards
Statement of
Financial Accounting Standards No. 69, Disclosures about
Oil and Gas Producing Activities
, may not be the most
appropriate discount factor based on interest rates in effect
from time to time and risks associated with us or the gas
industry in general.
Drilling
for and producing gas are costly and high-risk activities with
many uncertainties that could adversely affect our financial
condition or results of operations, and as a result, our ability
to pay distributions to our unitholders.
Our drilling activities are subject to many risks, including the
risk that we will not discover commercially productive
reservoirs. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect
the economics of a well. Furthermore, our drilling and producing
operations may be curtailed, delayed or canceled as a result of
other factors, including:
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high costs, shortages or delivery delays of drilling rigs,
equipment, labor or other services;
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reductions in gas prices;
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limitations in the market for gas;
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adverse weather conditions;
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facility or equipment malfunctions;
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difficulty disposing of water produced as part of the CBM
production process;
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equipment failures or accidents;
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title problems;
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pipe or cement failures or casing collapses;
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compliance with environmental and other governmental
requirements;
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environmental hazards, such as gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases;
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lost or damaged oilfield drilling and service tools;
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loss of drilling fluid circulation;
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unexpected operational events and drilling conditions;
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unusual or unexpected geological formations;
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formations with abnormal pressures;
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natural disasters, such as fires;
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blowouts, surface craterings and explosions; and
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uncontrollable flows of gas or well fluids.
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A productive well may become uneconomic in the event water or
other deleterious substances are encountered, which impair or
prevent the production of gas from the well. In addition,
production from any well may be unmarketable if it is
contaminated with water or other deleterious substances. We may
drill wells that are unproductive or, although productive, do
not produce gas in economic quantities. Unsuccessful drilling
activities could result in higher costs without any
corresponding revenues. Furthermore, a successful completion of
a well does not ensure a profitable return on the investment.
Our Cherokee Basin acreage is currently being developed
utilizing primarily
160-acre
spacing. We are currently conducting a pilot program to test the
development of a portion of our acreage using
80-acre
spacing. There can be no assurance that this pilot program will
be successful.
Our
hedging activities could result in financial losses or reduce
our income, which may adversely affect our ability to pay
distributions to our unitholders.
To achieve more predictable cash flow and to reduce our exposure
to adverse fluctuations in the prices of gas, we currently and
may in the future enter into derivative arrangements for a
significant portion of our gas production. We have entered into
derivative contracts with respect to approximately 80% of our
estimated net production from proved developed producing
reserves through the fourth quarter of 2010. Because a
significant portion of the estimated increase in our net
production will come from the development of new wells, our
derivative contracts cover a smaller percentage of our total
estimated production. For example, the derivative contracts for
2008 cover approximately 58% of our total estimated net
production for 2008. Our derivative instruments are subject to
mark-to-market accounting treatment, and the change in fair
market value of the instrument is reported in our statement of
operations each quarter, which has resulted in and may in the
future result in significant net losses. The extent of our
commodity price exposure is related largely to the effectiveness
and scope of our hedging activities. The prices at which we
enter into derivative financial instruments covering our
production in the future will be dependent upon commodity prices
at the time we enter into these transactions, which may be
substantially lower than current gas prices. Accordingly, our
commodity price risk management strategy will not protect us
from significant and sustained declines in gas prices received
for our future production. Conversely, our commodity price risk
management strategy may limit our ability to realize cash flow
from commodity price increases. Furthermore, we have direct
commodity price exposure on the unhedged portion of our
production volumes. Please read Quantitative and
Qualitative Disclosures about Market Risk under
Item 7A of this report.
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Our actual future production may be significantly higher or
lower than we estimate at the time we enter into hedging
transactions for such period. If the actual amount is higher
than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal
amount that is subject to our derivative financial instruments,
we might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the cash flow from our sale
or purchase of the underlying physical commodity, resulting in a
substantial diminution of our liquidity. As a result of these
factors, our hedging activities may not be as effective as we
intend in reducing the volatility of our cash flows, and in
certain circumstances may actually increase the volatility of
our cash flows. In addition, our hedging activities are subject
to the following risks:
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a counterparty may not perform its obligation under the
applicable derivative instrument;
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there may be a change in the expected differential between the
underlying commodity price in the derivative instrument and the
actual price received; and
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the steps we take to monitor our derivative financial
instruments may not detect and prevent violations of our risk
management policies and procedures.
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Because
of our lack of asset and geographic diversification, adverse
developments in our operating area would reduce our ability to
make distributions to our unitholders.
The vast majority of our assets are currently located in the
Cherokee Basin. As a result, our business is disproportionately
exposed to adverse developments affecting this region. These
potential adverse developments could result from, among other
things, changes in governmental regulation, capacity constraints
with respect to the pipelines connected to our wells,
curtailment of production, natural disasters or adverse weather
conditions in or affecting this region. Due to our lack of
diversification in asset type and location, an adverse
development in our business or this operating area would have a
significantly greater impact on our financial condition and
results of operations than if we maintained more diverse assets
and operating areas.
The
economic terms of the midstream services agreement may become
unfavorable to us.
Under the midstream services agreement, we pay Quest Midstream,
which is a party related to us, a fee for gathering, dehydration
and treating services and a compression fee. These fees are
subject to an annual upward adjustment in the event of increases
in the producer price index and the market price for gas. If
these fees increase at a faster rate than gas prices, our
ability to make cash distributions to our unitholders may be
adversely affected. Such fees are subject to renegotiation in
connection with each of the two five year renewal terms,
beginning after the initial term expires on December 1,
2016. In addition, at any time after each five year anniversary
of the date of the midstream services agreement, each party will
have a one-time option to elect to renegotiate the fees
and/or
the
basis for the annual adjustment to the fees if the party
believes there has been a material change to the economic
returns or financial condition of either party. If the parties
are unable to agree on the changes, if any, to be made to such
terms, then the parties will enter into binding arbitration to
resolve any dispute with respect to such terms. The renegotiated
fees may not be as favorable to us as the initial fees. For
2008, the fees will be $0.51 per MMBtu of gas for gathering,
dehydration and treating services and $1.13 per MMBtu of gas for
compression services.
In addition, the midstream services agreement requires the
drilling of a minimum of 750 new wells in the Cherokee Basin
during the two year period ending December 1, 2008, 575 of
which have been drilled in the Cherokee Basin through
December 31, 2007. We expect to drill 325 wells in
2008. At this time, we have identified our drilling locations
for 2008 and many of these wells will be drilled on locations
that are classified as containing proved reserves in our
December 31, 2007 reserve report. We are required to drill
these wells even if gas prices were to decline, or our costs
were to increase, to the point that these wells were
uneconomical for us to drill. We cannot assure you that any of
the remaining new wells required to be drilled pursuant to the
midstream services agreement will be economically favorable for
us. For additional information regarding the midstream services
agreement, please read Gas Gathering
under Item 1 of this report.
37
The
gathering fees payable to Quest Midstream under the midstream
services agreement in some cases could exceed the amount we are
able to charge to royalty owners under our gas leases for
gathering and compression.
Under the midstream services agreement we are required to pay
fees for gathering, dehydration and treating services and fees
for compression services to Quest Midstream for each MMBtu of
gas produced from our wells in the Cherokee Basin. The terms of
some of our existing gas leases may not, and the terms of some
of the gas leases that we may acquire in the future may not,
allow us to charge the full amount of these fees to the royalty
owners under the leases. We currently have leases covering
approximately 116,000 net acres that generally permit only
deductions for compression expenses, subject to certain
exceptions. With respect to our remaining leases, we believe
that we have the right to charge our royalty owners their
proportionate share of the full amount of the fees due under the
midstream services agreement. However, on August 3, 2007,
certain mineral interest owners filed a putative class action
lawsuit against Quest Cherokee that, among other things, alleges
Quest Cherokee improperly charged certain expenses to the
mineral
and/or
overriding royalty interest owners under leases covering the
acres leased by Quest Cherokee in Kansas. We will be responsible
for any judgments or settlements with respect to this
litigation. To the extent that we are unable to charge the full
amount of these fees to our royalty owners, it will reduce our
net income and the cash available for distribution to our
unitholders.
We may
be unable to compete effectively with larger companies, which
may adversely affect our ability to generate sufficient revenue
to allow us to pay distributions to our
unitholders.
The gas and oil industry is intensely competitive with respect
to acquiring prospects and productive properties, marketing gas
and oil and securing equipment and trained personnel, and we
compete with other companies that have greater resources. Many
of our competitors are major and large independent gas and oil
companies, and they not only drill for and produce gas and oil,
but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. Our
larger competitors also possess and employ financial, technical
and personnel resources substantially greater than ours. These
companies may be able to pay more for gas and oil properties and
evaluate, bid for and purchase a greater number of properties
than our financial or human resources permit. In addition, there
is substantial competition for investment capital in the gas and
oil industry. These larger companies may have a greater ability
to continue drilling activities during periods of low gas prices
and to absorb the burden of present and future federal, state,
local and other laws and regulations. Our inability to compete
effectively with larger companies could have a material impact
on our business activities, results of operations, financial
condition and ability to make cash distributions to our
unitholders.
We may
have difficulty managing growth in our business.
Because of the relatively small size of our business, growth in
accordance with our business plans, if achieved, will place a
significant strain on our financial, technical, operational and
management resources. As we increase our activities and the
number of projects we are evaluating or in which we participate,
there will be additional demands on our financial, technical,
operational and management resources. The failure to continue to
upgrade our technical, administrative, operating and financial
control systems or the occurrence of unexpected expansion
difficulties, including the recruitment and retention of
required personnel could have a material adverse effect on our
business, financial condition and results of operations and our
ability to timely execute our business plan.
Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs that is not fully insured, our
operations and financial results could be adversely
affected.
There are a variety of risks inherent in our operations that may
generate liabilities, including contingent liabilities, and
financial losses to us, such as:
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damage to wells, pipelines, related equipment and surrounding
properties caused by hurricanes, tornadoes, floods, fires and
other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of gas or losses of gas as a result of the malfunction of
equipment or facilities;
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fires and explosions; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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Any of these or other similar occurrences could result in the
disruption of our operations, substantial repair costs, personal
injury or loss of human life, significant damage to property,
environmental pollution, impairment of our operations and
substantial revenue losses.
In accordance with typical industry practice, we currently
possess property, business interruption and general liability
insurance at levels we believe are appropriate; however,
insurance against all operational risk is not available to us.
We are not fully insured against all risks, including drilling
and completion risks that are generally not recoverable from
third parties or insurance. Pollution and environmental risks
generally are not fully insurable. Additionally, we may elect
not to obtain insurance if we believe that the cost of available
insurance is excessive relative to the perceived risks
presented. Losses could, therefore, occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance
coverage. Moreover, insurance may not be available in the future
at commercially reasonable costs and on commercially reasonable
terms. Changes in the insurance markets subsequent to the
terrorist attacks on September 11, 2001 and the hurricanes
in 2005 have made it more difficult for us to obtain certain
types of coverage. There can be no assurance that we will be
able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes or that
the insurance coverage we do obtain will not contain large
deductibles or fail to cover certain hazards or cover all
potential losses. Losses and liabilities from uninsured and
underinsured events and delay in the payment of insurance
proceeds could have a material adverse effect on our business,
financial condition, results of operations and ability to make
distributions to our unitholders.
Any
amounts that we are required to pay as a result of our pending
legal proceedings may affect our ability to pay
distributions.
We are currently a party to several pending legal proceedings
arising out of the conduct of our business. Please read
Legal Proceedings under Item 3 of this report
for a description of our material legal proceedings. Our Parent
and its affiliates have also been named as defendants in a
number of these proceedings. We will be responsible for any
judgments or settlements resulting from these legal proceedings
and have agreed to indemnify our Parent and its affiliates for
any liability they may incur as a result of these legal
proceedings. Any amounts that we are required to pay as a result
of these legal proceedings would reduce our cash available for
distribution to our unitholders. Our estimated cash available
for distribution for the twelve months ending December 31,
2008, as set forth in our cash distribution policy described
under Cash Distributions to Unitholders in
Item 5 of this report assumes no amounts are required to be
paid by us with respect to these proceedings.
The
credit and risk profile of our Parent could adversely affect our
credit ratings and risk profile, which could increase our
borrowing costs or hinder our ability to raise
capital.
The credit and business risk profiles of our Parent may be
factors considered in our credit evaluations because our general
partner controls our business activities, including our cash
distribution policy and acquisition strategy and business risk
profile. Another factor that may be considered is the financial
condition of our Parent including the degree of its financial
leverage and any dependence on cash flow from us to service its
indebtedness.
If we were to seek a credit rating in the future, our credit
rating may be adversely affected by the leverage of our Parent,
as credit rating agencies such as Standard &
Poors Ratings Services and Moodys Investors Service
may consider the leverage and credit profile of our Parent and
its affiliates because of their ownership interest in and
control of us and the strong operational links between our
Parent and us. Any adverse effect on our credit rating would
increase our cost of borrowing or hinder our ability to raise
financing in the capital markets, which would impair our ability
to grow our business and make distributions to unitholders.
39
Our
operations expose us to significant costs and liabilities with
respect to environmental and operational safety matters
applicable to gas and oil exploitation and production
operations.
We may incur significant costs and liabilities as a result of
environmental, health and safety requirements applicable to our
gas and oil exploitation and production activities. These costs
and liabilities could arise under a wide range of federal, state
and local environmental, health and safety laws and regulations,
including regulations and enforcement policies, which have
tended to become increasingly strict over time. Failure to
comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and
to a lesser extent, issuance of injunctions to limit or cease
operations. In addition, claims for damages to persons or
property may result from environmental and other impacts of our
operations. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for damages as
a result of environmental and other impacts. Please read
Environmental Matters and Regulation under
Item 1 of this report for more information.
Strict, joint and several liability may be imposed under certain
environmental laws, which could cause us to become liable for
the conduct of others or for consequences of our own actions
that were in compliance with all applicable laws at the time
those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen
liabilities or significantly increase compliance costs. If we
are not able to recover the resulting costs through insurance or
increased revenues, our ability to make distributions to our
unitholders could be adversely affected. Please read
Environmental Matters and Regulation under
Item 1 of this report for more information.
We are
subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or
feasibility of conducting our operations.
Our gas and oil exploitation, development and production
operations are subject to complex and stringent laws, rules and
regulations. In order to conduct our operations in compliance
with these laws, rules and regulations, we must obtain and
maintain numerous permits, licenses, approvals and certificates
from various federal, state and local governmental authorities.
We may incur substantial costs in order to maintain compliance
with these existing laws, rules and regulations. In addition,
our costs of compliance may increase if existing laws, rules and
regulations are revised or reinterpreted, or if new laws, rules
and regulations become applicable to our operations.
The Cherokee Basin has been an active gas and oil producing
region for a number of years. Many of our properties had
abandoned oil and conventional gas wells on them at the time the
current lease was entered into with the landowner. A number of
these wells remain unplugged or were improperly plugged by a
prior landowner or operator. Many of the former operators of
these wells have ceased operations and cannot be located or do
not have the financial resources to plug these wells. We believe
that we are not responsible for plugging an abandoned well on
one of our leases, unless we have used, attempted to use or
invaded the abandoned well bore in our operations on the land or
have otherwise agreed to assume responsibility for plugging the
wells. The law is unsettled in the State of Kansas as to who has
the responsibility to plug such abandoned wells and the KCC has
issued a Show Cause Order in February 2007 requiring our
operating company, Quest Cherokee, to demonstrate why it should
not be held responsible for plugging 22 abandoned and unplugged
oil wells on land covered by a gas lease that is owned and
operated by Quest Cherokee in Wilson County, Kansas, and upon
which Quest Cherokee has drilled and is operating a gas well. If
it is ultimately determined that we are responsible for plugging
all of the wells located on our leased acreage that were
abandoned by former operators, the costs for plugging and
abandoning those wells would increase our costs and decrease our
cash available for distribution. At this time, we are unable to
determine the total number of wells located on our leased
acreage that have been abandoned by prior operators.
We may
face unanticipated water disposal costs.
We are subject to regulation that restricts our ability to
discharge water produced as part of our CBM gas production
operations. Coal beds frequently contain water that must be
removed in order for the gas to detach from the coal and flow to
the well bore, and our ability to remove and dispose of
sufficient quantities of water from the coal seam will determine
whether we can produce gas in commercial quantities. The
produced water must be transported from the lease and injected
into disposal wells. The availability of disposal wells with
sufficient
40
capacity to receive all of the water produced from our wells may
affect our ability to produce our wells. Also, the cost to
transport and dispose of that water, including the cost of
complying with regulations concerning water disposal, may reduce
our profitability.
Where water produced from our projects fail to meet the quality
requirements of applicable regulatory agencies, our wells
produce water in excess of the applicable volumetric permit
limits, the disposal wells fail to meet the requirements of all
applicable regulatory agencies, or we are unable to secure
access to disposal wells with sufficient capacity to accept all
of the produced water, we may have to shut in wells, reduce
drilling activities, or upgrade facilities for water handling or
treatment. The costs to dispose of this produced water may
increase if any of the following occur:
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we cannot obtain future permits from applicable regulatory
agencies;
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water of lesser quality or requiring additional treatment is
produced;
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our wells produce excess water;
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new laws and regulations require water to be disposed in a
different manner; or
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costs to transport the produced water to the disposal wells
increase.
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Shortages
of crews could delay our operations, adversely affect our
ability to increase our reserves and production and reduce our
cash available for distribution.
Higher gas and oil prices generally stimulate increased demand
and result in increased wages for crews and personnel in our
production operations. These types of shortages or wage
increases could increase our costs
and/or
restrict or delay our ability to drill the wells and conduct the
operations that we currently have planned. Any delay in the
drilling of new wells or significant increase in labor costs
could adversely affect our ability to increase our reserves and
production and reduce our revenue and cash available for
distribution. Additionally, higher labor costs could cause
certain of our projects to become uneconomic and therefore not
be implemented, reducing our production and cash available for
distribution.
We
depend on two customers for sales of all of our gas. To the
extent these customers reduce the volumes of gas they purchase
from us and are not replaced by new customers, our revenues and
cash available for distribution could decline.
During the year ended December 31, 2007, we sold
approximately 79% of our gas to ONEOK and 21% of our gas to
Tenaska under sale and purchase contracts, which have indefinite
terms but may be terminated by either party on
30 days notice, other than with respect to pending
transactions, or less following an event of default. If either
of these customers were to reduce the volume of gas it purchases
from us, our revenue and cash available for distribution may
decline to the extent we are not able to find new customers for
our production.
We are
exposed to trade credit risk in the ordinary course of our
business activities.
We are exposed to risks of loss in the event of nonperformance
by our customers and by counterparties to our derivative
contracts. Some of our customers and counterparties may be
highly leveraged and subject to their own operating and
regulatory risks. Even if our credit review and analysis
mechanisms work properly, we may experience financial losses in
our dealings with other parties. Any increase in the nonpayment
or nonperformance by our customers
and/or
counterparties could reduce our ability to make distributions to
our unitholders.
Certain
of our undeveloped leasehold acreage is subject to leases that
may expire in the near future.
As of December 31, 2007, we held gas leases on
approximately 164,869 net acres in the Cherokee Basin that
are still within their original lease term and are not currently
held by production. Unless we establish commercial production on
the properties subject to these leases during their term, these
leases will expire. Leases covering approximately 4,928 net
acres are scheduled to expire before December 31, 2008 and
an additional 80,843 net acres are scheduled to expire
before December 31, 2009. If our leases expire, we will
lose our right to develop the related properties. We typically
acquire a three-year primary term when the original lease is
acquired, with an option to
41
extend the term for up to three additional years, if the primary
three-year term reaches expiration without a well being drilled
to establish production for holding the lease.
Our
identified drilling location inventories will be developed over
several years, making them susceptible to uncertainties that
could materially alter the occurrence or timing of their
drilling, resulting in temporarily lower cash from operations,
which may impact our ability to pay distributions.
Our management has specifically identified drilling locations
for our future multi-year drilling activities on our existing
acreage. We have identified, as of December 31, 2007,
approximately 800 gross proved undeveloped drilling
locations and approximately 1,300 additional gross potential
drilling locations. These identified drilling locations
represent a significant part of our future development drilling
program for the Cherokee Basin. Our ability to drill and develop
these locations depends on a number of factors, including the
availability of capital, seasonal conditions, regulatory
approvals, gas prices, costs and drilling results. In addition,
no proved reserves are assigned to any of the approximately
1,300 potential drilling locations we have identified and
therefore, there may exist greater uncertainty with respect to
the likelihood of drilling and completing successful commercial
wells at these potential drilling locations. Our final
determination of whether to drill any of these drilling
locations will be dependent upon the factors described above as
well as, to some degree, the results of our drilling activities
with respect to our proved drilling locations. Because of these
uncertainties, we do not know if the numerous drilling locations
we have identified will be drilled within our expected timeframe
or will ever be drilled or if we will be able to produce gas
from these or any other potential drilling locations. As such,
our actual drilling activities may materially differ from those
presently identified, which could have a significant adverse
effect on our financial condition and results of operations.
We may
incur losses as a result of title deficiencies in the properties
in which we invest.
If an examination of the title history of a property reveals
that a gas or oil lease has been purchased in error from a
person who is not the owner of the mineral interest desired, our
interest would be worthless. In such an instance, the amount
paid for such gas or oil lease or leases would be lost. It is
our practice, in acquiring gas and oil leases, or undivided
interests in gas and oil leases, not to incur the expense of
retaining lawyers to examine the title to the mineral interest
to be placed under lease or already placed under lease. Rather,
we rely upon the judgment of gas and oil lease brokers or
landmen who perform the fieldwork in examining records in the
appropriate governmental office before attempting to acquire a
lease in a specific mineral interest. Prior to drilling a gas or
oil well, however, it is the normal practice in the gas and oil
industry for the person or company acting as the operator of the
well to obtain a preliminary title review of the spacing unit
within which the proposed gas or oil well is to be drilled to
ensure there are no obvious deficiencies in title to the well.
Frequently, as a result of such examinations, certain curative
work must be done to correct deficiencies in the marketability
of the title, and such curative work entails expense. The work
might include obtaining affidavits of heirship or causing an
estate to be administered. Our failure to obtain these rights
may adversely impact our ability in the future to increase
production and reserves.
On a small percentage of our acreage (less than 1.0%), the land
owner in the past transferred the rights to the coal underlying
their land to a third party. With respect to those properties we
have obtained gas and oil leases from the owners of the oil,
gas, and minerals other than coal underlying those lands. In
Oklahoma and Kansas, the law is unsettled as to whether the
owner of the gas rights or the coal rights is entitled to the
CBM gas. We are currently involved in litigation with the owner
of the coal rights on these lands to determine who has the
rights to the CBM gas. In the event that the courts were to
determine that the owner of the coal rights is entitled to
extract the CBM gas, we would lose these leases and the
associated wells and reserves. In addition, we may be required
to reimburse the owner of the coal rights for some of the gas
produced from those wells. For additional information regarding
these legal proceedings, please read Environmental Matters
and Regulation under Item 1 of this report and
Legal Proceedings under Item 3 of this report.
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We
rely on our general partner and Quest Energy Service for our
management. If our general partner or Quest Energy Service fails
to or inadequately performs, our costs will increase and reduce
our cash from operations and our ability to make cash
distributions to you.
We rely on our general partner and Quest Energy Service for our
management. We also expect that our general partner will provide
us with assistance in hedging our production and acquisition
services in respect of opportunities for us to acquire
long-lived, stable and proved gas and oil reserves. Our Parent
and its affiliates have no obligation to present us with
potential acquisitions outside the Cherokee Basin, and, if they
fail to do so, we will need to either seek acquisitions on our
own or retain a third party to seek acquisitions on our behalf.
In the long term, without further acquisitions, we will not be
able to replace or grow our reserves, which would reduce our
cash from operations and our ability to make cash distributions
to you.
We
depend on a limited number of key management personnel, who
would be difficult to replace.
Our operations and activities are dependent to a significant
extent on the efforts and abilities of management and key
employees of our Parent, including our Chief Executive Officer
Jerry Cash, Chief Operating Officer David Lawler and Chief
Financial Officer David Grose. We maintain no key person
insurance for either Messrs. Cash, Lawler or Grose. The
loss of any member of our management or other key employees
could negatively impact our ability to execute our strategy.
The
amount of cash distributions that we will be able to distribute
to unitholders will be reduced by the costs associated with
being a public company, other general and administrative
expenses and reserves that our general partner believes prudent
to maintain for the proper conduct of our business and for
future distributions.
Before we can pay distributions to our unitholders, we must
first pay or reserve cash for our expenses, including capital
expenditures and the costs of being a public company and other
operating expenses, and we may reserve cash for future
distributions during periods of limited cash flows. The amount
of cash we have available for distribution to our unitholders
will be affected by our level of reserves and expenses,
including the costs associated with being a public company.
If our
general partner fails to develop or maintain an effective system
of internal controls, then we may not be able to accurately
report our financial results or prevent fraud. As a result,
current and potential unitholders could lose confidence in our
financial reporting, which would harm our business and the
trading price of our common units.
Our general partner has sole responsibility for conducting our
business and for managing our operations. Effective internal
controls are necessary for our general partner, on our behalf,
to provide reliable financial reports, prevent fraud and operate
us successfully as a public company. Although our general
partner has implemented controls to prepare and review our
financial statements, we cannot be certain that its efforts to
develop and maintain its internal controls will be successful,
that it will be able to maintain adequate controls over our
financial processes and reporting in the future or that it will
be able to comply with our obligations under Section 404 of
the Sarbanes-Oxley Act of 2002. Any failure to develop or
maintain effective internal controls, or difficulties
encountered in implementing or improving our general
partners internal controls, could harm our operating
results or cause us to fail to meet our reporting obligations.
Ineffective internal controls also could cause investors to lose
confidence in our reported financial information, which likely
would have a negative effect on the trading price of our common
units.
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Risks
Inherent in an Investment in Us
Our
Parent controls our general partner, which conducts our business
and manages our operations. Our Parent and its affiliates have
conflicts of interest with us and limited fiduciary duties to
us, which may permit them to favor their own interests to your
detriment.
Our Parent owns and controls our general partner. The directors
and officers of our general partner have a fiduciary duty to
manage our general partner in a manner beneficial to our Parent.
Some of our general partners directors and executive
officers are directors or officers of our Parent and Quest
Midstream. Therefore, conflicts of interest may arise between
our Parent and its affiliates, including our general partner, on
the one hand, and us and our unitholders, on the other hand. In
resolving these conflicts of interest, our general partner may
favor its own interests and the interests of its affiliates over
the interests of our unitholders. These conflicts include, among
others, the following situations:
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neither our partnership agreement nor any other agreement
requires our Parent to pursue a business strategy that favors
us. Our Parents directors and officers have a fiduciary
duty to make decisions in the best interests of the owners of
our Parent, who include public shareholders. These decisions may
be contrary to our interests;
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our general partner is allowed to take into account the
interests of parties other than us, such as our Parent, in
resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to our unitholders;
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our general partner determines the amount and timing of
operating expenditures, asset purchases and sales, capital
expenditures, borrowings, repayments of indebtedness, issuance
of additional partnership securities and reserves, each of which
can affect the amount of cash that is distributed to unitholders
and the general partner, including with respect to its incentive
distribution rights, and the ability of the subordinated units
to convert to common units;
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our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is a
maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not
reduce operating surplus. This determination can affect the
amount of cash that is distributed to our unitholders;
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subject to the limitations in our omnibus agreement, our general
partner determines which costs incurred by it and its affiliates
are reimbursable by us;
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our general partner has the ability in certain circumstances to
cause us to borrow funds to pay distributions on its
subordinated units and incentive distribution rights; and
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our general partner controls the interpretation and enforcement
of obligations owed to us by our general partner and its
affiliates, including our omnibus agreement with our Parent, the
midstream services agreement between us and Quest Midstream and
Quest Midstreams midstream omnibus agreement with our
Parent.
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Our
partnership agreement limits our general partners
fiduciary duties to unitholders and restricts the remedies
available to holders of our common units and subordinated units
for actions taken by our general partner that might otherwise
constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
under state law and restrict the remedies available to
unitholders for actions taken by our general partner that might
otherwise constitute breaches of fiduciary duty. For example,
our partnership agreement:
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permits our general partner to make a number of decisions either
in its individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner;
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner and not
involving a vote of unitholders must be on terms no less
favorable to us than those generally being provided to or
available from unrelated third parties or must be fair and
reasonable to us, as determined by our general partner in
good faith and that, in determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us;
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provides that in resolving conflicts of interest, it will be
presumed that in making its decision our general partner or its
conflicts committee acted in good faith, and in any proceeding
brought by or on behalf of any limited partner or us, the person
bringing or prosecuting such proceeding will have the burden of
overcoming such presumption; and
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provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or assignees for any acts or omissions, unless there
has been a final and non-appealable judgment entered by a court
of competent jurisdiction determining that the general partner
or those other persons acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal.
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Each common unitholder is bound by the provisions in the
partnership agreement, including the provisions discussed above.
We do
not have any officers and rely solely on officers of our general
partner and employees of our Parent and its affiliates for the
management of our business.
None of the officers of our general partner are employees of our
general partner. We have entered into a management services
agreement with Quest Energy Service, pursuant to which Quest
Energy Service operates our assets and performs other
administrative services for us such as accounting, corporate
development, finance, land and engineering. Affiliates of our
Parent conduct businesses and activities of their own in which
we have no economic interest, including businesses and
activities relating to our Parent and Quest Midstream. As a
result, there could be material competition for the time and
effort of the officers and employees who provide services to our
general partner, our Parent and its affiliates. In the event
that the Pinnacle acquisition is consummated, our Parent will
substantially increase its operations, which could result in
increased competition for the time and effort of such officers
and employees. If the officers of our general partner and the
employees of our Parent and their affiliates do not devote
sufficient attention to the management and operation of our
business, our financial results may suffer and our ability to
make distributions to our unitholders may be reduced.
Unitholders
have limited voting rights, are not entitled to elect our
general partner or the directors of our general
partner.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will not elect our general partner or our general partners
board of directors, and will have no right to elect our general
partner or our general partners board of directors on an
annual or other continuing basis. The board of directors of our
general partner, including the independent directors, will be
chosen by our Parent. Since our Parent also holds 57% of our
aggregate outstanding common and subordinated units, the public
unitholders will not have an ability to influence any operating
decisions or to prevent us from entering into any transactions.
Furthermore, the goals and objectives of our Parent and our
general partner relating to us may not be consistent with those
of a majority of the public unitholders.
45
Even
if holders of our common units are dissatisfied, they cannot
initially remove our general partner without its
consent.
Unitholders will be unable initially to remove our general
partner without its consent because our general partner and its
affiliates own sufficient units to be able to prevent its
removal. The vote of the holders of at least
66
2
/
3
%
of all outstanding units (including units held by our general
partner and its affiliates) voting together as a single class is
required to remove the general partner. Our general partner and
its affiliates own 57% of our aggregate outstanding common and
subordinated units. Also, if our general partner is removed
without cause during the subordination period and units held by
our general partner and its affiliates are not voted in favor of
that removal, all remaining subordinated units will
automatically convert into common units and any existing
arrearages on our common units will be extinguished. A removal
of our general partner under these circumstances would adversely
affect our common units by prematurely eliminating their
distribution and liquidation preference over our subordinated
units, which would otherwise have continued until we had met
certain distribution and performance tests.
Cause is narrowly defined to mean that a court of competent
jurisdiction has entered a final, non-appealable judgment
finding the general partner liable for actual fraud or willful
or wanton misconduct in its capacity as our general partner.
Cause does not include most cases of charges of poor management
of the business, so the removal of the general partner because
of the unitholders dissatisfaction with our general
partners performance in managing our partnership will most
likely result in the termination of the subordination period and
conversion of all subordinated units to common units.
As a result of these limitations, the price at which the common
units will trade could be diminished because of the absence or
reduction of a takeover premium in the trading price.
Our
Parent may engage in competition with us.
Our Parent and its affiliates may engage in competition with us
outside the Cherokee Basin. Pursuant to the omnibus agreement,
our Parent and its subsidiaries agreed to give us a right to
purchase any natural gas or oil wells or other natural gas or
oil rights and related equipment and facilities that they
acquire within the Cherokee Basin, but not including any
midstream or downstream assets. Our Parent may acquire, develop
or dispose of additional oil or gas properties or other assets
outside of the Cherokee Basin in the future, without any
obligation to offer us the opportunity to acquire any of those
assets.
If our Parent does engage in competition with us it could have
an adverse impact on our results of operations and ability to
make distributions to our unitholders. For a description of the
non-competition provisions of the omnibus agreement, please read
Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Omnibus Agreement and
Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Management Services Agreement, in
each case, under Item 13 of this report.
We are
restricted from engaging in businesses other than the
exploration and development of gas and oil.
We will be subject to the midstream omnibus agreement dated as
of December 22, 2006, but effective as of December 1,
2006, among Quest Midstream, Quest Midstreams general
partner, Quest Midstreams operating subsidiary and our
Parent so long as we are an affiliate of our Parent and our
Parent or any of its affiliates controls Quest Midstream. Except
for certain limited exceptions, the midstream omnibus agreement
restricts us from engaging in the following businesses (each of
which is referred to in this report as a Restricted
Business):
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the gathering, treating, processing and transporting of gas in
North America;
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the transporting and fractionating of gas liquids in North
America;
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any other midstream activities, including but not limited to
crude oil storage, transportation, gathering and terminaling;
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constructing, buying or selling any assets related to the
foregoing businesses; and
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any line of business other than those described in the preceding
bullet points that generates qualifying income,
within the meaning of Section 7704(d) of the Code, other
than any business that is primarily engaged in the exploration
for and production of oil or gas and the sale and marketing of
gas and oil derived from such exploration and production
activities.
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These provisions will limit our flexibility to diversify into
businesses other than the exploration and development of oil and
gas, which may limit our ability to enter into different and
potentially more profitable lines of business, and thus,
adversely affect our ability to make distributions to our
unitholders.
Our
general partner has incentive distribution rights, which may
incentivize it to cause us to distribute cash needed to develop
our properties.
Our general partner has all of the incentive distribution rights
entitling it to receive up to 23% of our cash distributions
above certain target distribution levels in addition to its 2%
general partner interest. This increased sharing in our
distributions creates a conflict of interest for the general
partner in determining whether to distribute cash to our
unitholders or reserve it for reinvestment in the business and
whether to borrow to pay distributions to our unitholders. Our
general partner may have an incentive to distribute more cash
than it would if its only economic interest in us were its 2%
general partner interest. Furthermore, because of the commodity
price sensitivity of our business, the general partner may
receive incentive distributions due solely to increases in
commodity prices as opposed to growth through development
drilling or acquisitions.
Each
quarter our general partner is required to deduct estimated
maintenance capital expenditures from operating surplus, which
may result in less cash available to unitholders than if actual
maintenance capital expenditures were deducted.
Our partnership agreement requires our general partner to deduct
our estimated, rather than actual, maintenance capital
expenditures from operating surplus each quarter in an effort to
reduce fluctuations in operating surplus. The amount of
estimated maintenance capital expenditures deducted from
operating surplus is subject to review and change by the
conflicts committee at least once a year. In years when
estimated maintenance capital expenditures are higher than
actual maintenance capital expenditures, the amount of cash
available for distribution to unitholders will be lower than if
actual maintenance capital expenditures were deducted from
operating surplus. On the other hand, if our general partner
underestimates the appropriate level of estimated maintenance
capital expenditures, we will have more cash available for
distribution from operating surplus in the short term, including
on the general partners incentive distribution rights, but
will have less cash available for distribution from operating
surplus in future periods when we have to increase our estimated
maintenance capital expenditures to account for our previous
underestimation.
Cost
reimbursements due our general partner and its affiliates for
services provided, which will be determined by our general
partner, will be substantial and will reduce our cash available
for distribution to you.
Prior to making any distribution on our common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf, as determined by our general
partner. These expenses will include all costs incurred by our
general partner and its affiliates in managing and operating us.
There is no limit on the amount of expenses for which our
general partner and its affiliates may be reimbursed. Payments
for these services will reduce the amount of cash available for
distribution to unitholders. Please read Certain
Relationships and Related Party Transactions
Agreements Governing the Transactions Omnibus
Agreement and Certain Relationships and Related
Party Transactions Agreements Governing the
Transactions Management Services Agreement, in
each case, under Item 13 of this report.
Our
general partners interest in us and control of our general
partner may be transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does
47
not restrict the ability of the owner of our general partner
from transferring all or a portion of its ownership interest in
our general partner to a third party. The new owner of our
general partner would then be in a position to replace the board
of directors and officers of our general partner with its own
choices and thereby influence the decisions taken by the board
of directors and officers of our general partner.
We may
issue additional units, including units that are senior to the
common units, without approval of our unitholders, which would
dilute the existing ownership interests of our
unitholders.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. In addition, we
may issue an unlimited number of units that are senior to the
common units in right of distribution, liquidation and voting.
The issuance by us of additional common units or other equity
securities of equal or senior rank will have the following
effects:
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our unitholders proportionate ownership interest in us
will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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because a lower percentage of total outstanding units will be
subordinated units, the risks that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Our
general partner may elect to cause us to issue Class B
units to it in connection with a resetting of the target
distribution levels related to our general partners
incentive distribution rights without the approval of the
conflicts committee of our general partner or holders of our
common units and subordinated units. This may result in lower
distributions to holders of our common units in certain
situations.
Our general partner has the right, at a time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled for
each of the prior four consecutive fiscal quarters, to reset the
initial cash target distribution levels at higher levels based
on the distribution at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution amount will be reset to an amount
equal to the average cash distribution amount per common unit
for the two fiscal quarters immediately preceding the reset
election (such amount is referred to as the reset minimum
quarterly distribution) and the target distribution levels
will be reset to correspondingly higher levels based on
percentage increases above the reset minimum quarterly
distribution amount.
In connection with resetting these target distribution levels,
our general partner will be entitled to receive Class B
units. The Class B units will be entitled to the same cash
distributions per unit as our common units and will be
convertible into an equal number of common units. The number of
Class B units to be issued will be equal to that number of
common units whose aggregate quarterly cash distributions
equaled the average of the distributions to our general partner
on the incentive distribution rights in the prior two quarters.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when it is experiencing, or may be
expected to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued our Class B units, which are
entitled to receive cash distributions from us on the same
priority as our common units, rather than retain the right to
receive incentive distributions based on the initial target
distribution levels. As a result, a reset election may cause our
common unitholders to experience dilution in the amount of cash
distributions that they would have otherwise received had we not
issued new Class B units to our general partner in
connection with resetting the target distribution levels related
to our general partners incentive distribution rights.
48
Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
Our partnership agreement restricts unitholders voting
rights by providing that any units held by a person that owns
20% or more of any class of units then outstanding, other than
our general partner, its affiliates, their transferees and
persons who acquired such units with the prior approval of the
board of directors of our general partner, cannot vote on any
matter. Our partnership agreement also contains provisions
limiting the ability of unitholders to call meetings or to
acquire information about our operations, as well as other
provisions limiting the unitholders ability to influence
the manner or direction of management.
The
NASDAQ Global Market does not require a listed limited
partnership like us to comply with some of its listing
requirements with respect to corporate governance
requirements.
Because we are a limited partnership, the NASDAQ Global Market
does not require us to have a majority of independent directors
on the board of directors of our general partner or to establish
a compensation committee or a nominating and corporate
governance committee. Accordingly, you will not have the same
protections afforded to shareholders of companies that are
subject to all of the NASDAQ Global Market corporate governance
requirements.
Our
partnership agreement requires that we distribute all of our
available cash, which could limit our ability to grow our
reserves and production.
Our partnership agreement provides that we will distribute all
of our available cash each quarter. As a result, we will be
dependent on the issuance of additional common units and other
partnership securities and borrowings to finance our growth. A
number of factors will affect our ability to issue securities
and borrow money to finance growth, as well as the costs of such
financings, including:
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general economic and market conditions, including interest
rates, prevailing at the time we desire to issue securities or
borrow funds;
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conditions in the gas and oil industry;
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the market price of, and demand for, our common units;
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our results of operations and financial condition; and
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prices for gas and oil.
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Our
general partner has a limited call right that may require you to
sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of
the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, our
unitholders may be required to sell their common units at an
undesirable time or price and may not receive any return on
their investment. Our unitholders may also incur a tax liability
upon a sale of their units. Our general partner and its
affiliates own approximately 26% of our outstanding common
units. At the end of the subordination period, assuming no
additional issuances of common units, our general partner and
its affiliates will own approximately 57% of our aggregate
outstanding common units.
The
liability of our unitholders may not be limited if a court finds
that unitholder action constitutes control of our
business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in Kansas and Oklahoma. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership have
49
not been clearly established in some of the other states in
which we may do business. Our unitholders could be liable for
any and all of our obligations as if they were a general partner
if a court or government agency determined that:
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we were conducting business in a state but had not complied with
that particular states partnership statute; or
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a unitholders right to act with other unitholders to
remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions
under our partnership agreement constitute control
of our business.
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Unitholders
may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Sections 17-607
and
17-804
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to unitholders if the distribution would
cause our liabilities to exceed the fair value of our assets.
Delaware law provides that for a period of three years from the
date of the impermissible distribution, limited partners who
received the distribution and who knew at the time of the
distribution that it violated Delaware law will be liable to the
limited partnership for the distribution amount. Substituted
limited partners are not liable for the obligations of the
assignor to make contributions to the partnership that are known
to the substituted limited partner of units at the time it
became a limited partner and for unknown obligations if the
liabilities could be determined from our partnership agreement.
Common
units held by persons who are not Eligible Holders will be
subject to the possibility of redemption.
If we become subject to U.S. laws with respect to the
ownership interests in oil and gas leases on federal lands, our
general partner has the right under our partnership agreement to
institute procedures, by giving notice to each of our
unitholders, that would require transferees of common units and,
upon the request of our general partner, existing holders of our
common units to certify that they are Eligible Holders. As used
herein, an Eligible Holder means a person or entity qualified to
hold an interest in oil and gas leases on federal lands. As of
the date hereof, Eligible Holder means: (1) a citizen of
the United States, (2) a corporation organized under the
laws of the United States or of any state thereof, (3) a
public body, including a municipality or (4) an association
of United States citizens, such as a partnership or limited
liability company, organized under the laws of the United States
or of any state thereof, but only if such association does not
have any direct or indirect foreign ownership, other than
foreign ownership of stock in a parent corporation organized
under the laws of the United States or of any state thereof.
Onshore mineral leases or any direct or indirect interest
therein may be acquired and held by aliens only through stock
ownership, holding or control in a corporation organized under
the laws of the United States or of any state thereof. If these
certification procedures are implemented, unitholders who are
not persons or entities who meet the requirements to be an
Eligible Holder will not receive distributions or allocations of
income and loss on their units, and we will have the right to
redeem the common units held by persons or entities who are not
Eligible Holders at the then-current market price of the units.
The redemption price would be paid in cash or by delivery of a
promissory note, as determined by our general partner.
If we
distribute cash from capital surplus, which is analogous of a
return of capital, our minimum quarterly distribution rate will
be reduced proportionately, and the distribution thresholds
after which the incentive distribution rights entitle our
general partner to an increased percentage of distributions will
be proportionately decreased.
Our cash distribution will be characterized as coming from
either operating surplus or capital surplus. Operating surplus
generally means amounts we receive from operating sources, such
as sale of our gas and oil production, less operating
expenditures, such as production costs and taxes, and less
estimated average capital expenditures, which are generally
amounts we estimate we will need to spend in the future to
maintain our production levels over the long term. Capital
surplus generally means amounts we receive from non-operating
sources such as sales of properties and issuances of debt and
equity securities. Cash representing capital surplus, therefore,
is analogous to a return of capital. Distributions of capital
surplus are made to our unitholders and our general partner in
proportion to their percentage interests in us, or 98% to our
unitholders and 2% to our general
50
partner, and will result in a decrease in our minimum quarterly
distribution and a lower threshold for distributions on the
incentive distribution rights held by our general partner.
Our partnership agreement allows us to add to operating surplus
up to $25.9 million. As a result, a portion of this amount,
which is analogous to a return of capital, may be distributed to
our general partner as the holder of the incentive distribution
rights, rather than to holders of common units as a return of
capital.
An
increase in interest rates may cause the market price of our
common units to decline.
Like all equity investments, an investment in our common units
is subject to certain risks. In exchange for accepting these
risks, investors may expect to receive a higher rate of return
than would otherwise be obtainable from lower-risk investments.
Accordingly, as interest rates rise, the ability of investors to
obtain higher risk-adjusted rates of return by purchasing
government-backed debt securities may cause a corresponding
decline in demand for riskier investments generally, including
yield-based equity investments such as publicly traded limited
partnership interests. Reduced demand for our common units
resulting from investors seeking other more favorable investment
opportunities may cause the trading price of our common units to
decline.
Tax Risks
to Common Unitholders
Our
tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to a
material amount of entity-level taxation by individual states.
If the IRS were to treat us as a corporation or if we were to
become subject to a material amount of entity-level taxation for
state tax purposes, then our cash available for distribution to
unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS on
this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%
and would likely pay state income tax at varying rates.
Distributions to our unitholders would generally be taxed again
as corporate distributions, and no income, gains, losses or
deductions would flow through to our unitholders. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to unitholders would be substantially reduced.
Therefore, treatment of us as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to the unitholders, likely causing a substantial
reduction in the value of our common units.
Current law may change so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to entity-level taxation. For example, at the federal level,
legislation has been proposed that would eliminate partnership
tax treatment for certain publicly traded partnerships. Although
such legislation would not apply to us as currently proposed, it
could be amended prior to enactment in a manner that does apply
to us. We are unable to predict whether any of these changes, or
other proposals will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common
units. At the state level, because of widespread state budget
deficits and other reasons, several states are evaluating ways
to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of
taxation. Imposition of such a tax on us by any state will
reduce the cash available for distribution to unitholders. Our
partnership agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal, state or local income
tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on us.
51
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury regulations, and, accordingly,
our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among
our unitholders.
Our
unitholders may be required to pay taxes on their share of our
income even if they do not receive any cash distributions from
us.
Our unitholders will be treated as partners to whom we will
allocate taxable income which could be different in amount than
the cash we distribute. As a result, our unitholders will be
required to pay any federal income taxes and, in some cases,
state and local income taxes on their share of our taxable
income even if they receive no cash distributions from us. Our
unitholders may not receive cash distributions from us equal to
their share of our taxable income or even equal to the actual
tax liability that results from their share of our taxable
income.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely affected, and the
cost of any contest will reduce our cash available for
distribution to unitholders.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
report or from the positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take.
A court may not agree with some or all of our counsels
conclusions or positions we take. Any contest with the IRS may
materially and adversely impact the market for our common units
and the price at which they trade. In addition, our costs of any
contest with the IRS will reduce our cash available for
distribution and thus will be borne indirectly by our
unitholders and our general partner.
Tax
gain or loss on disposition of our common units could be more or
less than expected.
If our unitholders sell their common units, they will recognize
a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Prior
distributions to our unitholders in excess of the total net
taxable income they were allocated for a common unit, which
decreased their tax basis in that common unit, will, in effect,
become taxable income to them if the common unit is sold at a
price greater than their tax basis in that common unit, even if
the price they receive is less than their original cost. A
substantial portion of the amount realized, whether or not
representing gain, may be ordinary income. If our unitholders
sell their units, they may incur a tax liability in excess of
the amount of cash they receive from the sale. If the IRS
successfully contests some tax positions we take, unitholders
could recognize more gain on the sale of units than would be the
case if those positions were sustained, without the benefit of
decreased income in prior years.
Tax-exempt
entities and foreign persons face unique tax issues from owning
our common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), other retirement
plans and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file
52
United States federal tax returns and pay tax on their
share of our taxable income. If you are a tax-exempt entity or a
foreign person, you should consult your tax advisor before
investing in our common units.
We
will treat each purchaser of our common units as having the same
tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could
adversely affect the value of the common units.
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform to all aspects of existing Treasury
Regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to
unitholders. It also could affect the timing of these tax
benefits or the amount of gain from the sale of common units and
could have a negative impact on the value of our common units or
result in audits of, and adjustments to, unitholders tax
returns.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have terminated our partnership for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits
within a twelve-month period. For example, an exchange of 50% of
our capital and profits could occur if, in any twelve-month
period, holders of our subordinated and common units sell at
least 50% of the interests in our capital and profits. Our
termination would, among other things, result in the closing of
our taxable year for all unitholders, which could result in us
filing two tax returns (and unitholders receiving two
Schedule K-1s)
for one fiscal year. Our termination could also result in a
deferral of depreciation deductions allowable in computing our
taxable income. If this occurs, you will be allocated an
increased amount of federal taxable income for the year in which
we are considered to be terminated and for future years as a
percentage of the cash distributed to you with respect to such
periods. Although the amount of the increase cannot be estimated
because it depends upon numerous factors including the timing of
the termination, the amount could be material. Our termination
currently would not affect our classification as a partnership
for federal income tax purposes, but instead, we would be
treated as a new partnership for tax purposes. If we were
treated as a new partnership, we would be required to make new
tax elections and could be subject to penalties if we were
unable to determine that a termination occurred.
We may
adopt certain valuation methodologies that may result in a shift
of income, gain, loss and deduction between the holders of
incentive distribution rights and the unitholders. The IRS may
challenge this treatment, which could adversely affect the value
of our common units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and the
holders of the incentive distribution rights. Our methodology
may be viewed as understating the value of our assets. In that
case, there may be a shift of income, gain, loss and deduction
between certain unitholders and the holders of the incentive
distribution rights, which may be unfavorable to such
unitholders. Moreover, subsequent purchasers of common units may
have a greater portion of their Internal Revenue Code
Section 743(b) adjustment allocated to our tangible assets
and a lesser portion allocated to our intangible assets. The IRS
may challenge our methods, or our allocation of the
Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and
deduction between the holders of the incentive distribution
rights and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
Unitholders
likely will be subject to state and local taxes and return
filing requirements.
In addition to federal income taxes, unitholders will likely be
subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various
53
jurisdictions in which we conduct business or own property, now
or in the future, even if they do not live in any of those
jurisdictions. Unitholders will likely be required to file
foreign, state and local income tax returns and pay state and
local income taxes in some or all of these jurisdictions.
Further, they may be subject to penalties for failure to comply
with those requirements. We currently own assets and conduct
business in Kansas and Oklahoma. As we make acquisitions or
expand our business, we may own assets or conduct business in
additional states that impose a personal income tax. It is the
unitholders responsibility to file all United States
federal, state and local tax returns. Our counsel has not
rendered an opinion on the foreign, state or local tax
consequences of an investment in our common units.
|
|
Item 1B.
|
Unresolved
Staff Comments.
|
None.
Item 3.
Legal
Proceedings.
Quest Cherokee and our indirectly owned subsidiary, Quest
Cherokee Oilfield Service, LLC, are currently parties to various
legal and governmental proceedings arising out of our operations
in the normal course of business. The following is a summary of
our material legal proceedings:
Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc.,
Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream
Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc.
(now STP Cherokee, LLC) have been named Defendants in a
lawsuit filed by Plaintiffs, Eddie R. Hill,
et al
. in the
District Court for Craig County, Oklahoma (Case
No. CJ-2003-30).
Plaintiffs are royalty owners who are alleging underpayment of
royalties owed to them. Plaintiffs also allege, among other
things, that Defendants have engaged in self-dealing and
breached fiduciary duties owed to Plaintiffs, and that
Defendants have acted fraudulently toward the Plaintiffs.
Plaintiffs also allege that the gathering fees and related
charges should not be deducted in paying royalties.
Plaintiffs claims relate to a total of 84 wells
located in Oklahoma and Kansas. Plaintiffs are seeking
unspecified actual and punitive damages. Defendants intend to
defend vigorously against Plaintiffs claims.
STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem
Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service,
LLC (improperly named Quest Energy Services, LLC) have been
named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick
and Suzan M. Kirkpatrick in the District Court for Craig County
(Case
No. CJ-2005-143).
Plaintiffs allege that STP, Inc.,
et al.
, sold natural
gas from wells owned by the Plaintiffs without providing the
requisite notice to Plaintiffs. Plaintiffs further allege that
Defendants failed to include deductions on the check stubs of
Plaintiffs in violation of state law and that Defendants
deducted for items other than compression in violation of the
lease terms. Plaintiffs assert claims of actual and constructive
fraud and further seek an accounting stating that if Plaintiffs
have suffered any damages for failure to properly pay royalties,
Plaintiffs have a right to recover those damages. Plaintiffs
have not quantified their alleged damages. Discovery is ongoing
and Defendants intend to defend vigorously against
Plaintiffs claims.
Quest Cherokee Oilfield Services, LLC has been named in this
lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana
Jara De Trigoso in the District Court of Oklahoma County,
Oklahoma (Case
No. CJ-2007-11079).
Plaintiffs allege that Plaintiff Segundo Trigoso was injured
while working for Defendant on September 29, 2006 and that
such injuries were intentionally caused by Defendant. Plaintiffs
seek unspecified damages for physical injuries, emotional
injuries, loss of consortium and pain and suffering. Plaintiffs
also seek punitive damages. Defendant intends to defend
vigorously against Plaintiffs claims.
Quest Cherokee and Bluestem were named as defendants in a
lawsuit (Case
No. 04-C-100-PA)
filed by plaintiff Central Natural Resources, Inc. on
September 1, 2004 in the District Court of Labette County,
Kansas. Central Natural Resources owns the coal underlying
numerous tracts of land in Labette County, Kansas. Quest
Cherokee has obtained oil and gas leases from the owners of the
oil, gas, and minerals other than coal underlying some of that
land and has drilled wells that produce coal bed methane gas on
that land. Bluestem purchases and gathers the gas produced by
Quest Cherokee. Plaintiff alleges that it is entitled to the
coal bed methane gas produced and revenues from these leases and
that Quest Cherokee is a trespasser. Plaintiff is seeking quiet
title and an equitable accounting for the revenues from the coal
bed methane gas produced. Plaintiff has alleged that Bluestem
converted the gas and seeks an accounting for all gas purchased
by Bluestem from the wells in issue. Quest
54
Cherokee contends it has valid leases with the owners of the
coal bed methane gas rights. The issue is whether the coal bed
methane gas is owned by the owner of the coal rights or by the
owners of the gas rights. If Quest Cherokee prevails on that
issue, then the plaintiffs claims against Bluestem fail.
All issues relating to ownership of the coal bed methane gas and
damages have been bifurcated. Cross motions for summary judgment
on the ownership of the coal bed methane were filed by Quest
Cherokee and the plaintiff, with summary judgment being awarded
in Quest Cherokees favor. The plaintiff has appealed the
summary judgment and that appeal is pending. Quest Cherokee
intends to defend vigorously against these claims.
Quest Cherokee was named as a defendant in a lawsuit (Case
No. CJ-06-07)
filed by plaintiff Central Natural Resources, Inc. on
January 17, 2006, in the District Court of Craig County,
Oklahoma. Central Natural Resources owns the coal underlying
approximately 2,250 acres of land in Craig County,
Oklahoma. Quest Cherokee has obtained oil and gas leases from
the owners of the oil, gas, and minerals other than coal
underlying those lands, and has drilled and completed
20 wells that produce coal bed methane gas on those lands.
Plaintiff alleges that it is entitled to the coal bed methane
gas produced and revenues from these leases and that Quest
Cherokee is a trespasser. Plaintiff seeks to quiet its alleged
title to the coal bed methane and an accounting of the revenues
from the coal bed methane gas produced by Quest Cherokee. Quest
Cherokee contends it has valid leases from the owners of the
coal bed methane gas rights. The issue is whether the coal bed
methane gas is owned by the owner of the coal rights or by the
owners of the gas rights. Quest Cherokee has answered the
petition and discovery is ongoing. Quest Cherokee intends to
defend vigorously against these claims.
Quest Cherokee was named as a defendant in a lawsuit (Case
No. 05 CV 41) filed by Labette Energy, LLC in the
District Court of Labette County, Kansas. Plaintiff claims to
own a 3.2 mile gas gathering pipeline in Labette County,
Kansas, and that Quest Cherokee used that pipeline without
plaintiffs consent. Plaintiff also contends that the
defendants slandered its alleged title to that pipeline and
suffered damages from the cancellation of their proposed sale of
that pipeline. Plaintiff claims that they were damaged in the
amount of $202,375. Discovery in that case is ongoing and Quest
Cherokee intends to defend vigorously against the
plaintiffs claims.
Quest Cherokee is a counterclaim defendant in a lawsuit (Case
No. 2006 CV 74) filed by Quest Cherokee in District
Court of Labette County, Kansas. Quest Cherokee filed that
lawsuit seeking a declaratory judgment that several oil and gas
leases owned by Quest Cherokee are valid and in effect. In the
counterclaim, defendants allege that those leases have expired
by their terms and have been forfeited by Quest Cherokee.
Defendants seek a declaration that those leases are null and
void, statutory damages of $100, and their attorneys fees.
Discovery in that case is ongoing. Quest Cherokee intends to
vigorously defend against those counterclaims.
Quest Cherokee was named as a defendant in a class action
lawsuit (Case
No. 07-1225-MLB)
filed by several royalty owners in the U.S. District Court
for the District of Kansas. The case was filed by the named
plaintiffs on behalf of a putative class consisting of all Quest
Cherokees royalty and overriding royalty owners in the
Kansas portion of the Cherokee Basin. Plaintiffs contend that
Quest Cherokee failed to properly make royalty payments to them
and the putative class by, among other things, paying royalties
based on reduced volumes instead of volumes measured at the
wellheads, by allocating expenses in excess of the actual costs
of the services represented, by allocating production costs to
the royalty owners, by improperly allocating marketing costs to
the royalty owners, and by making the royalty payments after the
statutorily proscribed time for doing so without providing the
required interest. Quest Cherokee has answered the complaint and
denied plaintiffs claims. Discovery in that case is
ongoing. Quest Cherokee intends to defend vigorously against
these claims.
Quest Cherokee has been named as a defendant in several lawsuits
in which the plaintiff claims that an oil and gas lease owned
and operated by Quest Cherokee has either expired by their terms
or, for various reasons, have been forfeited by Quest Cherokee.
Those lawsuits are pending in the District Courts of Labette,
Montgomery, and Wilson Counties, Kansas. Quest Cherokee has
drilled wells on some of the oil and gas leases in issue and
some of those oil and gas leases do not have a well located
thereon but have been unitized with other oil and gas leases
upon which a well has been drilled. As of February 28,
2008, the total amount of acreage covered by the leases at issue
in these lawsuits was approximately 7,090 acres. Discovery
in those cases is ongoing. Quest Cherokee intends to vigorously
defend against those claims.
Quest Cherokee was named in an Order to Show Cause issued by the
Kansas Corporation Commission (the KCC) (KCC Docket
No. 07-CONS-155-CSHO)
filed on February 23, 2007. The KCC has ordered Quest
55
Cherokee to demonstrate why it should not be held responsible
for plugging 22 abandoned oil wells on a gas lease owned and
operated by Quest Cherokee in Wilson County, Kansas. Quest
Cherokee denies that it is legally responsible for plugging the
wells in issue and intends to vigorously defend against the
KCCs claims.
From time to time, we may be subject to legal proceedings and
claims that arise in the ordinary course of our business.
Although no assurance can be given, management believes, based
on its experiences to date, that the ultimate resolution of such
items will not have a material adverse impact on our business,
financial position or results of operations. Like other natural
gas and oil producers and marketers, our operations are subject
to extensive and rapidly changing federal and state
environmental regulations governing air emissions, wastewater
discharges, and solid and hazardous waste management activities.
Therefore it is extremely difficult to reasonably quantify
future environmental related expenditures.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security
Holders.
|
No matter was submitted to a vote of the holders of our units
during the fourth quarter of 2007.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity
Securities.
|
Market
Information
Our common units began trading on the NASDAQ Global Market under
the symbol QELP commencing with our initial public
offering on November 9, 2007. The following table sets
forth the range of the daily high and low sales prices per
common unit and cash distributions to common unitholders for
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range
|
|
|
Cash Distribution
|
|
|
|
High
|
|
|
Low
|
|
|
per Common Unit (1)
|
|
|
Fourth Quarter
|
|
$
|
16.50
|
|
|
$
|
13.90
|
|
|
$
|
0.2043
|
|
|
|
|
(1)
|
|
On January 21, 2008, the board of directors of our general
partner declared a cash distribution for the fourth quarter of
2007. The distribution was based on an initial quarterly
distribution of $0.40 per unit, prorated for the period from and
including November 15, 2007, the closing date of our
initial public offering, through December 31, 2007. The
distribution was paid on February 14, 2008 to unitholders
of record at the close of business on February 7, 2008.
|
Record
Holders
At the close of business on March 25, 2008, based upon
information received from our transfer agent and brokers and
nominees, we had five (5) common unitholders of record. This
number does not include owners for whom common units may be held
in street names.
Cash
Distributions to Unitholders
We intend to make cash distributions to unitholders on a
quarterly basis, although there is no assurance as to the future
cash distributions since they are dependent upon future
earnings, cash flows, capital requirements, financial condition
and other factors. Our cash distribution policy is subject to
restrictions on distributions under our credit facility. Our
credit facility contains material financial tests and covenants
that we must satisfy.
Our partnership agreement requires that, within 45 days
after the end of each quarter, we distribute all of our
available cash (as defined in our partnership agreement) to
unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of
the quarter:
|
|
|
|
|
less
the amount of cash reserves established by our
general partner to:
|
|
|
|
|
|
provide for the proper conduct of our business, including
reserves for future capital expenditures and our anticipated
future credit needs;
|
56
|
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters;
|
|
|
|
|
|
plus
, all additional cash and cash equivalents on hand on
the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of
the quarter. Working capital borrowings are generally borrowings
that are made under a credit facility, commercial paper facility
or similar financing arrangement, and in all cases are used
solely for working capital purposes or to pay distributions to
partners and with the intent of the borrower to repay such
borrowings within 12 months other than from additional
working capital borrowings.
|
Our general partner is entitled to 2% of all quarterly
distributions that we make prior to our liquidation. The general
partners 2% interest in these distributions will be
reduced if we issue additional units in the future and our
general partner does not contribute a proportionate amount of
capital to us to maintain its 2% general partner interest. Our
general partner also currently holds incentive distribution
rights that entitle it to receive increasing percentages, up to
a maximum of 25%, of the cash we distribute from operating
surplus (as defined in our partnership agreement) in excess of
$0.46 per unit per quarter.
During the subordination period, the common units will have the
right to receive distributions of available cash from operating
surplus each quarter in an amount equal to the minimum quarterly
distribution of $0.40 per common unit, plus any arrearages in
the payment of the minimum quarterly distribution on the common
units from prior quarters, before any distributions of available
cash from operating surplus may be made on the subordinated
units. These units are deemed subordinated because
for a period of time, referred to as the subordination period,
the subordinated units will not be entitled to receive any
distributions until the common units have received the minimum
quarterly distribution plus any arrearages from prior quarters.
Furthermore, no arrearages will be paid on the subordinated
units. The purpose of the subordinated units is to increase the
likelihood that during the subordination period there will be
available cash to be distributed on the common units.
The subordination period will extend until the first day of any
quarter beginning after December 31, 2012 that each of the
following tests are met:
|
|
|
|
|
distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and general
partner units equaled or exceeded the minimum quarterly
distribution for each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date;
|
|
|
|
the adjusted operating surplus (as defined in our partnership
agreement) generated during each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that
date equaled or exceeded the sum of the minimum quarterly
distributions on all of the outstanding common units,
subordinated units and general partner units during those
periods on a fully diluted basis; and
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|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
When the subordination period expires, each outstanding
subordinated unit will convert into one common unit and will
then participate pro rata with the other common units in
distributions of available cash. In addition, if the unitholders
remove our general partner other than for cause and units held
by our general partner and its affiliates are not voted in favor
of such removal:
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|
|
|
the subordination period will end and each subordinated unit
will immediately convert into one common unit;
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|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
the general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests.
|
If the tests for ending the subordination period are satisfied
for any three consecutive, non-overlapping four-quarter periods
ending on or after December 31, 2010, 25% of the
subordinated units will convert into an equal
57
number of common units. Similarly, if those tests are also
satisfied for any three consecutive, non-overlapping
four-quarter periods ending on or after December 31, 2011,
an additional 25% of the subordinated units will convert into an
equal number of common units. The second early conversion of
subordinated units may not occur, however, until at least one
year following the end of the period for the first early
conversion of subordinated units.
In addition to the early conversion of subordinated units
described above, all of the subordinated units will convert into
an equal number of common units on the first day of any quarter
beginning after December 31, 2010 that each of the
following tests are met:
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|
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|
distributions of available cash from operating surplus on each
outstanding common unit, subordinated unit and the 2% general
partner interest equaled or exceeded $2.00 (125% of the
annualized minimum quarterly distribution) for each of the two
consecutive, non-overlapping four-quarter periods immediately
preceding that date;
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|
the adjusted operating surplus generated during each of the two
consecutive, non-overlapping four-quarter periods immediately
preceding that date equaled or exceeded the sum of a
distribution of $2.00 per common unit (125% of the annualized
minimum quarterly distribution) on all of the outstanding common
and subordinated units and the 2% general partner interest
during those periods on a fully diluted basis; and
|
|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
We will make distributions of available cash from operating
surplus for any quarter during the subordination period in the
following manner:
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|
|
|
|
first, 98% to the common unitholders, pro rata, and 2% to the
general partner, until we distribute for each outstanding common
unit an amount equal to the minimum quarterly distribution for
that quarter;
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|
|
second, 98% to the common unitholders, pro rata, and 2% to the
general partner, until we distribute for each outstanding common
unit an amount equal to any arrearages in payment of the minimum
quarterly distribution on the common units for any prior
quarters during the subordination period;
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|
|
third, 98% to the subordinated unitholders, pro rata, and 2% to
the general partner, until we distribute for each subordinated
unit an amount equal to the minimum quarterly distribution for
that quarter; and
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|
thereafter, cash in excess of the minimum quarterly
distributions is distributed to the unitholders and the general
partner based on the percentages below (which results in our
general partner receiving incentive distributions if the amount
we distribute with respect to one quarter exceeds specified
target levels shown below):
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Total Quarterly
|
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Marginal Percentage Interest in Distributions
|
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Distributions Target
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Limited
|
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General
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Amount
|
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Partner
|
|
|
Partner
|
|
|
Minimum quarterly distribution
|
|
$0.40
|
|
|
98
|
%
|
|
|
2
|
%
|
First target distribution
|
|
Up to $0.46
|
|
|
98
|
%
|
|
|
2
|
%
|
Second target distribution
|
|
Above $0.46, up to $0.50
|
|
|
85
|
%
|
|
|
15
|
%
|
Thereafter
|
|
Above $0.50
|
|
|
75
|
%
|
|
|
25
|
%
|
58
Securities
Authorized For Issuance Under Equity Compensation
Plans
We have one equity compensation plan for our employees,
consultants and non-employee directors pursuant to which unit
awards may be granted. No awards were granted under our
long-term incentive plan in 2007. The following is a summary of
the common units remaining available for future issuance under
such plan as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to be
|
|
|
|
|
|
Under Equity
|
|
|
|
Issued Upon
|
|
|
Weighted-Average
|
|
|
Compensation Plans
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
(Excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Securities
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Reflected in Column
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
(a))
|
|
|
|
(a)
|
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|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
2,115,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
2,115,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For a description of our equity compensation plan, please see
the discussion under Item 11 of this report.
Unregistered
Sales of Equity Securities
In connection with our formation in July 2007, we issued a 2%
general partnership interest to our general partner for $20 and
a 98% limited partnership interest to our Parent for $980. Our
Parent contributed $1,000 to our general partner in exchange for
100% of the member interests in our general partner. In
connection with the closing of our initial public offering on
November 15, 2007, we issued (i) 3,201,521 common
units and 8,857,981 subordinated units to our Parent in exchange
for its contribution of its ownership interest in Quest Cherokee
to us, and (ii) 431,827 general partner units and incentive
distribution rights (which represent the right to receive
increasing percentages of quarterly distributions in excess of
specified amounts) to our general partner in exchange for its
contribution of its ownership interest in Quest Cherokee to us.
Each subordinated unit will convert into one common unit as
described above. Each of these transactions was exempt from
registration under Section 4(2) of the Securities Act of
1933. There were no other sales of our unregistered securities
during 2007.
Purchases
of Equity Securities
There were no purchases of our common units made by or on behalf
of us or certain affiliated purchasers during the fourth quarter
of 2007.
59
|
|
Item 6.
|
Selected
Financial
Data.
|
The following table sets forth selected consolidated financial
data of us and the Predecessor for the periods and as of the
dates indicated. The selected financial data for the period from
November 15, 2007 through December 31, 2007 are
derived from our audited financial statements. The selected
financial data for the period from January 1, 2007 through
November 14, 2007 and as of November 14, 2007 and for
the years ended and as of December 31, 2006 and 2005, the
seven month transition period ended December 31, 2004 and
the fiscal years ended May 31, 2004 and 2003 are derived
from the audited financial statements of the Predecessor. The
data are derived from our audited consolidated/carve out
financial statements revised to reflect the reclassification of
certain items. Comparability between years is affected by
(1) changes in the annual average prices for oil and gas,
(2) increased production from drilling and development
activity, (3) significant acquisitions that were made
during the fiscal year ended May 31, 2004, (4) the
change in the fiscal year end on December 31, 2004, and
(5) our initial public offering effective November 15,
2007.
The selected financial data should be read in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operation and our
consolidated/carve out financial statements, including the
notes, appearing in Items 7 and 8 of this report.
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|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15
|
|
|
January 1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
|
|
|
|
|
|
7 Mos Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
Fiscal Year Ended May 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
(Consolidated)
|
|
|
(Carve out)
|
|
|
(Carve out)
|
|
|
(Carve out)
|
|
|
(Carve out)
|
|
|
(Carve out)
|
|
|
(Carve out)
|
|
|
|
($ in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
15,842
|
|
|
$
|
97,193
|
|
|
$
|
65,551
|
|
|
$
|
44,565
|
|
|
$
|
24,201
|
|
|
$
|
28,147
|
|
|
$
|
8,345
|
|
Other revenue/expense
|
|
|
22
|
|
|
|
(45
|
)
|
|
|
(83
|
)
|
|
|
387
|
|
|
|
37
|
|
|
|
(904
|
)
|
|
|
(908
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
15,864
|
|
|
|
97,148
|
|
|
|
65,468
|
|
|
|
44,952
|
|
|
|
24,238
|
|
|
|
27,243
|
|
|
|
7,437
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
3,579
|
|
|
|
24,416
|
|
|
|
21,208
|
|
|
|
14,388
|
|
|
|
5,389
|
|
|
|
5,003
|
|
|
|
1,979
|
|
Transportation expense
|
|
|
4,342
|
|
|
|
24,836
|
|
|
|
17,278
|
|
|
|
7,038
|
|
|
|
3,196
|
|
|
|
1,869
|
|
|
|
644
|
|
General and administrative
|
|
|
1,562
|
|
|
|
10,272
|
|
|
|
8,149
|
|
|
|
4,068
|
|
|
|
2,328
|
|
|
|
2,264
|
|
|
|
711
|
|
Provision for impairment of gas and oil properties
|
|
|
|
|
|
|
|
|
|
|
30,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
5,046
|
|
|
|
30,672
|
|
|
|
25,521
|
|
|
|
20,121
|
|
|
|
6,954
|
|
|
|
6,698
|
|
|
|
1,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
14,529
|
|
|
|
90,196
|
|
|
|
102,875
|
|
|
|
45,615
|
|
|
|
17,867
|
|
|
|
15,834
|
|
|
|
4,912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
1,335
|
|
|
|
6,952
|
|
|
|
(37,407
|
)
|
|
|
(663
|
)
|
|
|
6,371
|
|
|
|
11,409
|
|
|
|
2,525
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in derivative fair value
|
|
|
(6,082
|
)
|
|
|
(420
|
)
|
|
|
6,410
|
|
|
|
(4,668
|
)
|
|
|
(1,487
|
)
|
|
|
(2,013
|
)
|
|
|
(4,867
|
)
|
Gain (loss) on sale of assets
|
|
|
(18
|
)
|
|
|
(310
|
)
|
|
|
(7
|
)
|
|
|
12
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
(3
|
)
|
Interest expense, net
|
|
|
(13,746
|
)
|
|
|
(25,413
|
)
|
|
|
(16,545
|
)
|
|
|
(19,873
|
)
|
|
|
(7,702
|
)
|
|
|
(6,403
|
)
|
|
|
(438
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(19,846
|
)
|
|
|
(26,143
|
)
|
|
|
(10,142
|
)
|
|
|
(24,529
|
)
|
|
|
(9,189
|
)
|
|
|
(8,422
|
)
|
|
|
(5,308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of accounting change
|
|
|
(18,511
|
)
|
|
|
(19,191
|
)
|
|
|
(47,549
|
)
|
|
|
(25,192
|
)
|
|
|
(2,818
|
)
|
|
|
2,987
|
|
|
|
(2,783
|
)
|
Cumulative effect of accounting change, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(18,511
|
)
|
|
|
(19,191
|
)
|
|
$
|
(47,549
|
)
|
|
$
|
(25,192
|
)
|
|
$
|
(2,818
|
)
|
|
$
|
2,959
|
|
|
$
|
(2,783
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net (loss)
|
|
$
|
(370
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net (loss)
|
|
$
|
(18,141
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
$
|
(6.80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
$
|
(6.80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per unit
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(13,732
|
)
|
|
$
|
22,829
|
|
|
$
|
11,183
|
|
|
$
|
584
|
|
|
$
|
18,778
|
|
|
$
|
15,701
|
|
|
$
|
3,306
|
|
Net cash used in investing activities
|
|
|
(7,603
|
)
|
|
|
(98,490
|
)
|
|
|
(117,194
|
)
|
|
|
(51,645
|
)
|
|
|
(28,075
|
)
|
|
|
(125,482
|
)
|
|
|
(8,397
|
)
|
Net cash provided by (used in) financing activities
|
|
|
31,505
|
|
|
|
54,327
|
|
|
|
124,818
|
|
|
|
47,141
|
|
|
|
26,280
|
|
|
|
111,060
|
|
|
|
7,203
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
359,246
|
|
|
|
|
|
|
$
|
311,718
|
|
|
$
|
217,650
|
|
|
$
|
178,332
|
|
|
$
|
149,651
|
|
|
$
|
23,264
|
|
Long-term debt, net of current maturities
|
|
|
94,042
|
|
|
|
|
|
|
|
225,245
|
|
|
|
75,889
|
|
|
|
148,747
|
|
|
|
126,766
|
|
|
|
10,575
|
|
Partners equity (deficit)
|
|
|
228,760
|
|
|
|
|
|
|
|
51,091
|
|
|
|
69,547
|
|
|
|
(3,877
|
)
|
|
|
(1,730
|
)
|
|
|
6,521
|
|
60
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operation.
|
You should read the following discussion of the financial
condition and results of operations for the Predecessor and us
in conjunction with the historical financial statements and
accompanying notes of the Predecessor and the financial
statements for Quest Energy Partners, L.P. included in
Financial Statements and Supplementary Data under
Item 8 of this report.
Overview
We are a Delaware limited partnership formed in July 2007 by our
Parent to acquire, exploit and develop oil and natural gas
properties. Effective November 15, 2007, we consummated the
initial public offering of 9,100,000 common units. In connection
with the closing of our offering, we entered into a contribution
agreement with our general partner, our Parent, Quest Cherokee
and a couple of our Parents subsidiaries, pursuant to
which, among other things, Quest Cherokee (which owned all of
the Cherokee Basin gas and oil leases) and its subsidiary, Quest
Cherokee Oilfield Service, LLC (QCOS) (which owned
all of the Cherokee Basin field equipment and vehicles), were
contributed to us.
As of December 31, 2007, our properties had 211.1 Bcfe
of net proved reserves, of which approximately 99% were CBM and
66.9% were proved developed. We operate over 99% of our existing
wells, with an average net working interest of 58% and an
average net revenue interest of approximately 82%. We believe we
are the largest producer of natural gas in the Cherokee Basin
with an average net daily production of 46.7 Mmcfe for the
year ended December 31, 2007. Our estimated net proved
reserves at December 31, 2007 had estimated future net
revenues discounted at 10%, which we refer to as the
standardized measure, of $322.5 million. Our
reserves are long-lived, with an average proved
reserve-to-production ratio of 12.3 years (8.12 years
for our proved developed properties) as of December 31,
2007. Our typical Cherokee Basin CBM well has a predictable
production profile and a standard economic life of approximately
15 years.
At December 31, 2007, we had an interest in 2,254 natural
gas and oil leases on approximately 583,000 gross acres,
located in the Cherokee Basin. Management believes that the
proximity of the 1,994 miles of Quest Midstream owned gas
gathering pipeline network to these natural gas and oil leases
will enable us to develop new producing wells on many of our
undeveloped properties. We have currently identified
approximately 2,100 additional gross natural gas well
drilling sites on our undeveloped acreage, of which 800 are
classified as proved undeveloped. With approximately
325 wells planned to be drilled during each of 2008 and
2009, we are positioned for significant growth in natural gas
production, revenues and net income. However, no assurance can
be given that we will be able to achieve our anticipated rate of
growth or that adequate sources of capital will be available.
The results of our drilling and well development program for
calendar year 2007 included the drilling of 575 new gas
wells (gross), the connecting of 575 new gas wells (gross) to
Quest Midstreams gas gathering system, and the
recompletion of 50 wells from single seam to multi-seam
wells.
In early February 2008, we purchased 1,200 acres in
Seminole County, Oklahoma from Landmark Energy for
$9.5 million. The oil producing properties have estimated
reserves of 712,000 Bbl, all of which are proved developed
producing.
Our
Initial Public Offering
Effective November 15, 2007, we completed our initial
public offering of 9.1 million common units at a price of
$18.00 per unit. Total proceeds from the sale of the common
units in the initial public offering were $163.8 million,
before underwriting discounts, a structuring fee and offering
costs, of approximately $10.6 million, $0.4 million
and $1.5 million, respectively. At the closing of our
initial public offering, our Parent transferred their ownership
interest in Quest Cherokee and QCOS in exchange for 3,201,521
common units and 8,857,981 subordinated units and a 2% general
partner interest. On November 9, 2007, the
Partnerships common units began trading on the NASDAQ
Global Market under the symbol QELP. We used the net
proceeds of $151.2 million to repay a portion of our
outstanding indebtedness.
61
2008
Outlook
For 2008, we have budgeted approximately $41.0 million to
drill and complete an estimated 325 gross wells and
recomplete an estimated 52 gross wells, as well as an
additional $37.5 million for acreage, equipment and vehicle
replacement and purchases and salt water disposal facilities. We
have identified our drilling locations for 2008 and many of
these wells will be drilled on locations that are classified as
containing proved reserves in our December 31, 2007 reserve
report. As of December 31, 2007, we had an inventory of
approximately 212 drilled CBM wells awaiting connection to the
gathering system of Quest Midstream. It is our intention to
focus on the development of CBM reserves that can be immediately
served by Quest Midstreams gathering system.
Our acreage is currently being developed utilizing primarily
160-acre
spacing. However, several of our competitors are currently
developing their CBM reserves in the Cherokee Basin on
80-acre
spacing. We are currently conducting a pilot program to test the
development of a portion of our acreage using
80-acre
spacing. If our pilot project is successful, we could
significantly increase the number of CBM drilling locations
which are present on our acreage.
Gas prices have been volatile over the last three years. We
anticipate a continued favorable commodity price environment for
2008. Significant factors that will impact near-term gas prices
include the following:
|
|
|
|
|
the domestic and foreign supply of gas;
|
|
|
|
the price and quantity of imports of foreign natural gas;
|
|
|
|
overall domestic and global economic conditions;
|
|
|
|
the consumption pattern of industrial consumers, electricity
generators and residential users;
|
|
|
|
weather conditions;
|
|
|
|
the level of domestic natural gas inventories;
|
technological advances affecting energy consumption;
|
|
|
|
|
domestic and foreign governmental regulations;
|
|
|
|
proximity and capacity of gas pipelines and other transportation
facilities; and
|
|
|
|
the price and availability of alternative fuels.
|
A substantial portion of our estimated gas production from our
proved developed producing reserves is currently hedged through
December 2010, and we intend to continue to enter into commodity
derivative transactions to mitigate the impact of price
volatility on our gas and oil revenues.
We believe that current gas prices will continue to cause
relatively high levels of gas-related drilling in the United
States as producers seek to increase their level of gas
production. Although the number of gas wells drilled in the
United States has increased overall in recent years, a
corresponding increase in production has not been realized,
primarily as a result of smaller discoveries and the decline in
production from existing wells. We believe that an increase in
United States drilling activity, additional sources of supply
such as liquefied natural gas, and imports of natural gas will
be required for the gas industry to meet the expected increased
demand for, and to compensate for the slowing production of, gas
in the United States.
We expect to fund our 2008 capital expenditures utilizing a
combination of cash flow from operations, additional borrowings
and/or
the
issuance of debt or equity. We also estimate that we will have
sufficient cash flow from operations after funding maintenance
capital expenditures, but not including expansion capital
expenditures, to enable us to make our initial quarterly
distribution to unitholders for each quarter for the twelve
months ending December 31, 2008. Please read
Liquidity and Capital Resources below
and Market for Registrants Common Equity Related to
Unitholder Matters and Issuer Purchases of Equity
Securities Cash Distributions to Unitholders
under Item 5 of this report.
62
We intend to pursue acquisition opportunities, but expect to
confront intense competition for these assets. We believe that
our structure as a pass-through vehicle for tax purposes will
allow us to have a lower cost of capital for acquisition
opportunities than many of our taxable competitors.
Factors
That Significantly Affect Comparability of Our Results
Our future results of operations and cash flows could differ
materially from the historical results of the Predecessor due to
a variety of factors, including the following:
Outstanding Indebtedness.
The Predecessor had
significantly more indebtedness ($260.0 million as of
November 14, 2007) than the $94 million of
indebtedness that we had at December 31, 2007. In addition,
the average interest rate on the indebtedness of the Predecessor
for the period from January 1, 2007 through
November 14, 2007 was 11.2% as compared to the interest
rate at December 31, 2007 under our current credit facility
of 7.75% (LIBOR plus 1.5%).
Purchase of Derivatives.
For the years ended
December 31, 2005, 2006 and 2007, fixed price contracts
hedged approximately 89.0%, 61.0% and 63.2%, respectively, of
the Predecessors gas production. We have entered into
derivative contracts with respect to approximately 80% of our
estimated proved developed producing production through the
fourth quarter of 2010 in order to achieve more predictable cash
flows and to reduce our exposure to short-term fluctuations in
gas prices and interest rates. As of December 31, 2007, we
had fixed price swaps and collars covering 40% and 40%,
respectively, of our estimated net gas production from proved
developed producing reserves in 2008. In addition, for 2009 and
2010, we have fixed price swaps covering 80% and 80%,
respectively, of our estimated net gas production from proved
developed producing reserves. Because a significant portion of
the estimated increase in our net production will come from the
development of new wells, our derivative contracts cover a
smaller percentage of our total estimated production. For
example, the derivative contracts for 2008 cover approximately
58% of our total estimated net production for 2008. By removing
a significant portion of price volatility of our future gas
production we have mitigated, but not eliminated, the potential
effects of changing gas prices on our cash flows from operations
for those periods.
Midstream Services Agreement.
Prior to the
formation of Quest Midstream in December 2006, a wholly-owned
subsidiary of our Parent provided us with gas gathering,
treating, dehydration and compression services pursuant to a gas
transportation agreement that was entered into in December 2003.
Since these services were being provided by one wholly owned
subsidiary of our Parent to another wholly-owned subsidiary, no
amendments were made to this prior contract to reflect increases
in the costs of providing these services. As part of the
formation of Quest Midstream, our Parent and Quest Midstream
entered into the midstream services agreement, which provided
for negotiated fees for these services that were significantly
higher than those that had been previously paid.
Under the midstream services agreement, Quest Midstream was paid
$0.50 per MMBtu of gas for gathering, dehydration and treating
services and $1.10 per MMBtu of gas for compression services
during 2007. These fees are subject to annual adjustment based
on changes in gas prices and the producer price index. Such fees
will never be reduced below these initial rates and are subject
to renegotiation upon the exercise of each five-year extension
period. Under the terms of some of our gas leases, we may not be
able to charge the full amount of these fees to royalty owners,
which would increase the average fees per MMBtu that we
effectively pay under the midstream services agreement. For
2008, the fees will be $0.51 per MMBtu of gas for gathering,
dehydration and treating services and $1.13 per MMBtu of gas for
compression services.
For more information about the midstream services agreement,
please read Business Gas Gathering under
Item 1 of this report.
Results
of Operations
The discussion of the results of operations and period-to-period
comparisons presented below includes the historical results of
the Predecessor. As discussed above under
Factors That Significantly Affect
Comparability
63
of Our Results, the Predecessors historical results
of operations and period-to-period comparisons of its results
may not be indicative of our future results.
Years
Ended December 31, 2007 and 2006
Our results of operations for the year ended December 31,
2007 are derived from the combination of the results of the
operations of the Predecessor for the period from
January 1, 2007 through November 14, 2007 and the
results of our operations for the period from November 15,
2007 through December 31, 2007.
Overview.
The following table summarizes the
results of operations for the years ended December 31, 2007
and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Increase/(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
113,035
|
|
|
$
|
65,551
|
|
|
$
|
47,484
|
|
|
|
72.4
|
%
|
Other revenue/(expense)
|
|
$
|
(23
|
)
|
|
$
|
(83
|
)
|
|
$
|
60
|
|
|
|
72.3
|
%
|
Oil and gas production costs
|
|
$
|
27,995
|
|
|
$
|
21,208
|
|
|
$
|
6,787
|
|
|
|
32.0
|
%
|
Transportation expense
|
|
$
|
29,178
|
|
|
$
|
17,278
|
|
|
$
|
11,900
|
|
|
|
68.9
|
%
|
Depreciation, depletion and amortization
|
|
$
|
35,718
|
|
|
$
|
25,521
|
|
|
$
|
10,197
|
|
|
|
40.0
|
%
|
General and administrative expenses
|
|
$
|
11,834
|
|
|
$
|
8,149
|
|
|
$
|
3,685
|
|
|
|
45.22
|
%
|
Change in derivative fair value
|
|
$
|
(6,502
|
)
|
|
$
|
6,410
|
|
|
$
|
(12,912
|
)
|
|
|
(201.4
|
)%
|
Impairment charge
|
|
$
|
|
|
|
$
|
30,719
|
|
|
$
|
(30,719
|
)
|
|
|
(100.0
|
)%
|
Interest expense
|
|
$
|
39,575
|
|
|
$
|
16,935
|
|
|
$
|
22,640
|
|
|
|
133.7
|
%
|
Production.
The following table presents the
primary components of revenues (gas and oil production and
average gas and oil prices), as well as the average costs per
Mcfe, for the years ended December 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Increase/(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
17,148
|
|
|
|
12,341
|
|
|
|
4,807
|
|
|
|
39.0
|
%
|
Average daily production (MMcfe/d)
|
|
|
47.0
|
|
|
|
33.8
|
|
|
|
13.2
|
|
|
|
39.0
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
6.17
|
|
|
$
|
5.95
|
|
|
$
|
0.22
|
|
|
|
3.6
|
%
|
Including hedges
|
|
|
6.59
|
|
|
|
5.31
|
|
|
|
1.27
|
|
|
|
24.1
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
1.63
|
|
|
$
|
1.84
|
|
|
$
|
(0.21
|
)
|
|
|
(11.4
|
)%
|
Transportation expense
|
|
$
|
1.69
|
|
|
$
|
1.40
|
|
|
$
|
0.29
|
|
|
|
20.7
|
%
|
Depreciation, depletion and amortization
|
|
|
2.10
|
|
|
|
2.05
|
|
|
|
0.05
|
|
|
|
2.4
|
%
|
Oil and Gas Sales.
Oil and gas sales of
$113.0 million for the year ended December 31, 2007
represents an increase of 73% when compared to oil and gas sales
of $65.6 million for the year ended December 31, 2006.
The increase in oil and gas sales from $65.6 million for
the year ended December 31, 2006 to $113.0 million for
the year ended December 31, 2007 resulted from the
additional wells completed during the past twelve months. The
additional wells completed contributed to the production of
17,148 Mmcfe of net gas for the year ended
December 31, 2007, as compared to 12,341 net Mmcfe
produced for the year ended December 31, 2006. Our product
prices before hedge settlements on an equivalent basis (mcfe)
increased from $5.95 per Mcfe average for the 2006 period to
$6.17 per Mcfe average for the 2007 period. Accounting for hedge
settlements, the product prices increased from $5.31 per Mcfe
average for the 2006 period to $6.59 per Mcfe average for the
2007 period.
64
Other Revenue/(Expense).
Other expense for the
year ended December 31, 2007 was $23,000 as compared to
other expense of $83,000 for the year ended December 31,
2006, that was due to a reduction in overhead and pumper fees.
Operating Expenses.
Operating expenses, which
consist of oil and gas production costs and transportation
expense, were $57.2 million for the year ended
December 31, 2007, as compared to $38.5 million for
the year ended December 31, 2006, an increase of
$18.7 million, or 48.6%. Oil and gas production costs for
the year ended December 31, 2007 were $28.0 million as
compared to $21.2 million for the year ended
December 31, 2006, an increase of $6.8 million, or
32%. Production costs, excluding gross production and ad valorem
taxes, were $1.27 per Mcfe for 2007 compared to $1.29 per Mcfe
for the year ended December 31, 2006. Production costs,
inclusive of gross production and ad valorem taxes, were $1.63
per Mcfe for the 2007 period as compared to $1.84 per Mcfe for
the year ended December 31, 2006 period, representing an
11% decrease. This decrease was a result of the higher
production volumes for the year ended December 31, 2007 and
the benefits from certain cost cutting programs started during
the third quarter of 2007.
Transportation expense increased from $1.40 per Mcfe for 2006 to
$1.69 per Mcfe for 2007. This increase resulted from the
midstream services agreement with Quest Midstream that became
effective December 1, 2006, which provided for a fixed
transportation fee that was higher than the fees in the year
earlier period.
Depreciation, Depletion and Amortization.
We
are subject to variances in our depletion rates from period to
period, including the periods described below. These variances
result from changes in our oil and gas reserve quantities,
production levels, product prices and changes in the depletable
cost basis of our gas and oil properties. Our depletion of gas
and oil properties as a percentage of oil and gas sales was 32%
in the year ended December 31, 2007 compared to 39% in
2006. Increases in our depletable basis and production volumes
caused depletion expense to increase $10.2 million to
$35.7 million in 2007 compared to $25.5 million in
2006. Depreciation and amortization expense was $327,000 in the
year ended December 31, 2007 compared to $209,000 in 2006.
The increase of $118,000, or 56%, is due to additional vehicles,
equipment, and facilities acquired during 2007. Depreciation,
depletion and amortization expense was $2.10 per Mcfe in 2007
compared to $2.05 per Mcfe in 2006.
General and Administrative Expenses.
General
and administrative expenses increased to approximately
$11.8 million for the year ended December 31, 2007
from $8.1 million in the year ended December 31, 2006
due to an increase in board fees, professional fees, Nasdaq
listing fees, travel expenses for presentations to increase our
visibility with investors, larger corporate offices, increased
staffing to support the higher levels of development and
operational activity and the added resources to enhance our
internal controls. General and administrative expenses per Mcfe
of gas produced was $0.69 for the year ended December 31,
2007 compared to $0.66 for the year ended December 31, 2006.
Change in Derivative Fair Value.
Change in
derivative fair value was a non-cash loss of $6.5 million
for the year ended December 31, 2007, which included an
$11.3 million loss attributable to the change in fair value
for certain derivative contracts that did not qualify as cash
flow hedges pursuant to SFAS 133 and a gain of
$4.8 million relating to hedge ineffectiveness. Change in
derivative fair value was a non-cash gain of $6.4 million
for the year ended December 31, 2006, which included a
$12.2 million gain attributable to the change in fair value
for certain derivative contracts that did not qualify as cash
flow hedges pursuant to SFAS 133, settlements due to
ineffective cash flow hedges of $10.2 million and a gain of
$4.4 million relating to hedge ineffectiveness. Amounts
recorded in this caption represent non-cash gains and losses
created by valuation changes in derivatives that are not
entitled to receive hedge accounting. All amounts recorded in
this caption are ultimately reversed in this caption over the
respective contract term.
Impairment Charge.
In the year ended
December 31, 2006, we recognized a $30.7 million
provision for impairment of oil and gas properties from a full
cost pool ceiling write-down, primarily as a result of declines
in estimated reserves due to the prevailing market prices of oil
and gas at the measurement date.
65
Interest Expense.
Interest expense increased
to approximately $39.6 million for the year ended
December 31, 2007 from $16.9 million for the year
ended December 31, 2006 (inclusive of a $9.5 million
write-off of debt issue costs realized in connection with the
refinancing of our credit facilities in 2007). Excluding the
write-off of debt issue costs in 2007, the approximate
$13.2 million increase in interest expense in 2007 was due
to higher average outstanding borrowings and the loan prepayment
penalties.
Years
Ended December 31, 2006 and 2005
Overview.
The following table summarizes the
results of operations for the fiscal years ended
December 31, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Increase/(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
65,551
|
|
|
$
|
44,565
|
|
|
$
|
20,986
|
|
|
|
47.1
|
%
|
Other revenue/(expense)
|
|
$
|
(83
|
)
|
|
$
|
387
|
|
|
$
|
(470
|
)
|
|
|
121.4
|
%
|
Oil and gas production costs
|
|
$
|
21,208
|
|
|
$
|
14,388
|
|
|
$
|
6,820
|
|
|
|
47.4
|
%
|
Transportation expense
|
|
$
|
17,278
|
|
|
$
|
7,038
|
|
|
$
|
10,240
|
|
|
|
145.5
|
%
|
Depreciation, depletion and amortization
|
|
$
|
25,521
|
|
|
$
|
20,121
|
|
|
$
|
5,400
|
|
|
|
26.8
|
%
|
General and administrative expenses
|
|
$
|
8,149
|
|
|
$
|
4,068
|
|
|
$
|
4,081
|
|
|
|
100.3
|
%
|
Change in derivative fair value
|
|
$
|
6,410
|
|
|
$
|
(4,668
|
)
|
|
$
|
11,078
|
|
|
|
237.3
|
%
|
Impairment charge
|
|
$
|
30,719
|
|
|
$
|
|
|
|
$
|
30,719
|
|
|
|
100.0
|
%
|
Interest expense
|
|
$
|
16,935
|
|
|
$
|
19,919
|
|
|
$
|
(2,984
|
)
|
|
|
(15.0
|
)%
|
Production.
The following table presents the
primary components of revenues (gas and oil production and
average gas and oil prices), as well as the average costs per
Mcfe, for the fiscal years ended December 31, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Increase/(Decrease)
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
12,341
|
|
|
|
9,620
|
|
|
|
2,721
|
|
|
|
28.3
|
%
|
Average daily production (MMcfe/d)
|
|
|
33.8
|
|
|
|
26.4
|
|
|
|
7.4
|
|
|
|
28.0
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
5.95
|
|
|
$
|
7.45
|
|
|
$
|
(1.50
|
)
|
|
|
(20.1
|
)%
|
Including hedges
|
|
|
5.31
|
|
|
|
4.63
|
|
|
|
0.68
|
|
|
|
14.7
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
1.84
|
|
|
$
|
1.50
|
|
|
$
|
0.34
|
|
|
|
22.7
|
%
|
Transportation expense
|
|
$
|
1.40
|
|
|
$
|
0.73
|
|
|
$
|
0.67
|
|
|
|
91.8
|
%
|
Depreciation, depletion and amortization
|
|
|
2.05
|
|
|
|
2.14
|
|
|
|
(0.09
|
)
|
|
|
(4.2
|
)%
|
Oil and Gas Sales.
Oil and gas sales were
$65.6 million for the year ended December 31, 2006 as
compared to $44.6 million for the year ended
December 31, 2005, an increase of $21.0 million, or
47.1%. The increase resulted from the additional wells completed
during 2006. The additional wells completed contributed to the
production of 12,341 Mmcfe net gas for the year ended
December 31, 2006, as compared to 9,620 Mmcfe produced
for the year ended December 31, 2005. Our product prices
before hedge settlements on an equivalent basis (Mcfe) decreased
from $7.45 per Mcfe on average for the 2005 period to $5.95 per
Mcfe on average for the 2006 period. Accounting for hedge
settlements, the product prices increased from $4.63 per Mcfe on
average for the 2005 period to $5.31 per Mcfe on average for the
2006 period.
66
Other Revenue/(Expense).
Other expense for the
year ended December 31, 2006 was $83,000 that resulted from
an adjustment of overhead fees and pumper fees as compared to
other revenue of $387,000 for the year ended December 31,
2005, that was primarily the result of an adjustment of overhead
fees.
Operating Expenses.
Operating expenses, which
consist of oil and gas production costs and transportation
expense, were $38.5 million for the year ended
December 31, 2006 as compared to $21.4 million for the
year ended December 31, 2005, an increase of
$17.1 million, or 79.6%. Oil and gas production costs for
the year ended December 31, 2006 were $21.2 million as
compared to $14.4 million for the year ended
December 31, 2005, an increase of $6.8 million, or
47.4%. Production costs, excluding gross production and ad
valorem taxes, were $1.28 per Mcfe for 2006 compared to $0.98
for the year ended December 31, 2005. Production costs,
inclusive of gross production and ad valorem taxes, were $1.84
per Mcfe for the 2006 period as compared to $1.50 per Mcfe for
the year ended December 31, 2005 period, representing a 23%
increase. This increase was a result of increased property taxes
on wells in the State of Kansas, increased gross production
taxes from increased production volumes, decreased field payroll
allocated to capital expenditures and an increase in our
treating program to reduce pump failures.
Transportation expense increased from $0.73 per Mcf for 2005 to
$1.40 per Mcf for 2006. This increase resulted from increases in
compression rental and property taxes assessed on pipelines and
related equipment.
Depreciation, Depletion and
Amortization.
Depreciation, depletion and
amortization costs increased to $25.5 million in 2006 from
$20.1 million in 2005 as a result of the increased number
of producing wells developed, the higher volumes of gas and oil
produced and the resulting increased depletion rate.
General and Administrative Expenses.
General
and administrative expenses increased by $4.1 million, or
100.3%, to $8.1 million for the year ended
December 31, 2006 from $4.1 million in the year ended
December 31, 2005 due to an increase in professional fees,
travel expenses, increased staffing to support the higher levels
of development and operational activity and the added resources
to enhance our internal controls and financial reporting.
General and administrative expenses per Mcfe of gas produced was
$0.70 for the year ended December 31, 2006 compared to
$0.50 for the year ended December 31, 2005.
Interest Expense.
Interest expense decreased
by $3.0 million, or 15.0%, to $16.9 million for the
year ended December 31, 2006 from $19.9 million for
the year ended December 31, 2005 (inclusive of a
$4.3 million write-off of debt issue costs realized in
connection with the refinancing of our credit facilities in
2005). Excluding the write-off of debt issue costs in 2005, the
approximate $3.0 million increase in interest expense in
2006 was due to higher average outstanding borrowings, partially
offset by lower average interest rates under our credit
facilities that were entered into in November 2005.
Change in Derivative Fair Value.
Change in
derivative fair value was a non-cash gain of $6.4 million
for the year ended December 31, 2006, which included a
$12.2 million gain attributable to the change in fair value
for certain derivative contracts that did not qualify as cash
flow hedges pursuant to SFAS 133 and a gain of
$4.4 million relating to hedge ineffectiveness. Change in
derivative fair value was a non-cash net loss of
$4.7 million for the year ended December 31, 2005,
which included a $0.9 million net gain attributable to the
change in fair value for certain cash flow hedges that did not
meet the effectiveness guidelines of SFAS 133 for the
period, a $103,000 net gain attributable to the reversal of
contract fair value gains and losses recognized in earnings
prior to actual settlement, and a loss of $5.7 million
relating to hedge ineffectiveness. Amounts recorded in this
caption represent non-cash gains and losses created by valuation
changes in derivatives that are not entitled to receive hedge
accounting. All amounts recorded in this caption are ultimately
reversed in this caption over the respective contract term.
Impairment Charge.
In the year ended
December 31, 2006 we recognized a $30.7 million
provision for impairment of oil and gas properties from a full
cost pool ceiling write-down, primarily as a result of declines
in estimated reserves due to the prevailing market prices of oil
and gas at the measurement date.
67
Liquidity
and Capital Resources
Liquidity
Our primary sources of liquidity are cash generated from our
operations, amounts available under our revolving credit
facility described below and funds from future private and
public equity and debt offerings.
At December 31, 2007, Quest Energy had $66 million of
availability under its revolving credit facility, which was
available to fund the drilling and completion of additional gas
wells, the recompletion of single seam wells into multi-seam
wells, the acquisition of additional acreage, equipment and
vehicle replacement and purchases and the construction of salt
water disposal facilities.
Our partnership agreement requires that we distribute our
available cash. In making cash distributions, our general
partner will attempt to avoid large variations in the amount we
distribute from quarter to quarter. In order to facilitate this,
our partnership agreement permits our general partner to
establish cash reserves to be used to pay distributions for any
one or more of the next four quarters. In addition, our
partnership agreement allows our general partner to borrow funds
to make distributions.
Because of the seasonal nature of gas and oil, we may make
short-term working capital borrowings in order to level out our
distributions during the year. In addition, a substantial
portion of our production is hedged. We are generally required
to settle our commodity hedges on either the 5th or
25th day of each month. As is typical in the gas and oil
business, we do not generally receive the proceeds from the sale
of the hedged production around the 25th day of the
following month. As a result, when gas and oil prices increase
and are above the prices fixed in our derivative contracts, we
will be required to pay the hedge counterparty the difference
between the fixed price in the hedge and the market price before
we receive the proceeds from the sale of the hedged production.
If this were to occur, we may make working capital borrowings to
fund our distributions. Because we will distribute our available
cash, we will not have those amounts available to reinvest in
our business to increase our reserves and production. Because we
will distribute a substantial amount of our cash flows (after
making principal and interest payments on our indebtedness)
rather than reinvest those cash flows in our business, we may
not grow as quickly as other companies or at all.
Future
Capital Expenditures
We plan to make substantial capital expenditures in the future
for the acquisition, exploitation and development of gas and oil
properties. During 2008, we intend to focus on drilling and
completing up to 325 new wells in the Cherokee Basin. Management
currently estimates that it will require for 2008 and 2009
capital investments of:
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$41.0 million to drill and complete these wells and
recomplete an estimated 52 gross wells in the Cherokee
Basin; and
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$37.5 million for acreage, equipment and vehicle
replacement and purchases and salt water disposal facilities in
the Cherokee Basin.
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Our capital expenditures will consist of the following:
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maintenance capital expenditures, which are those capital
expenditures required to maintain our production levels and
asset base over the long term; and
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expansion capital expenditures, which are those capital
expenditures that we expect will increase our production of our
gas and oil properties, our asset base over the long term.
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We intend to finance future maintenance capital expenditures
generally from cash flow from operations and expansion capital
expenditures generally with borrowings under our new credit
facility
and/or
the
issuance of debt or equity.
In the event we make one or more acquisitions and the amount of
capital required is greater than the amount we have available
for acquisitions at that time, we would reduce the expected
level of capital expenditures
and/or
seek
additional capital. If we seek additional capital for that or
other reasons, we may do so through traditional reserve base
borrowings, joint venture partnerships, production payment
financings, asset sales, offerings of debt or equity
68
securities or other means. We cannot assure unitholders that
needed capital will be available on acceptable terms or at all.
Our ability to raise funds through the incurrence of additional
indebtedness will be limited by covenants in our anticipated
credit facility. If we are unable to obtain funds when needed or
on acceptable terms, we may not be able to complete acquisitions
that may be favorable to us or finance the capital expenditures
necessary to replace our reserves.
Cash
Flows
Cash Flows from Operating Activities.
Net cash
provided by operating activities totaled $9.1 million for
the year ended December 31, 2007 as compared to net cash
provided by operations of $11.2 million for the year ended
December 31, 2006. This decrease resulted from a net loss
of $37.7 million, a change in derivative fair value, an
increase in accounts receivable and accounts payable and an
increase in revenue payable and other receivables.
Cash Flows Used in Investing Activities.
Net
cash used in investing activities totaled $106.1 million
for the year ended December 31, 2007 as compared to
$117.2 million for the year ended December 31, 2006.
During the year ended December 31, 2007, a total of
approximately $106.1 million of capital expenditures was
invested as follows: $89.4 million was invested in new
natural gas wells and properties, $13.2 million in
acquiring leasehold and $3.5 million in other additional
capital items.
Cash Flows from Financing Activities.
Net cash
provided by financing activities totaled $85.8 million for
the year ended December 31, 2007 as compared to
$124.8 million for the year ended December 31, 2006.
Credit
Facility
Please read Note 4. Long-Term Debt to the notes to our
consolidated/carve out financial statements in Item 8 of
this report for a description of our credit facility and other
long-term indebtedness.
Contractual
Obligations
Future payments due on our contractual obligations as of
December 31, 2007 are as follows:
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Payments Due by Period
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Less Than
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1-3
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4-5
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More Than
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Total
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1 Year
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Years
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Years
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5 Years
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(In thousands)
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Revolving Credit Facility
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$
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94,000
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$
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$
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$
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94,000
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$
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Notes Payable
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708
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666
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30
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12
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Interest expense obligation(1)
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35,356
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7,304
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14,583
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13,465
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4
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Drilling contractor
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4,241
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4,241
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Asset retirement obligations
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1,700
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1,700
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Derivatives
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13,827
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8,241
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5,586
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Total
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$
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149,832
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$
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20,452
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$
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20,199
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$
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107,477
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$
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1,704
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(1)
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The interest payment obligation was computed using the LIBOR
interest rate as of December 31, 2007. If the interest rate
were to change 1%, then the interest payment obligation would
change by $4.6 million.
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In addition, we entered into a management services agreement
with Quest Energy Service, pursuant to which Quest Energy
Service, through its affiliates and employees, carry out the
directions of our general partner and provide us with legal,
accounting, finance, tax, property management, engineering and
risk management services. Quest Energy Service may additionally
provide us with acquisition services in respect of opportunities
for us to acquire long-lived, stable and proved gas and oil
reserves.
Off-Balance
Sheet Arrangements
We do not have any off-balance sheet arrangements.
69
Critical
Accounting Policies and Estimates
Readers of this report and users of the information contained in
it should be aware of how certain events may impact our
financial results based on the accounting policies in place. The
two policies we consider to be the most significant are
discussed below.
The selection and application of accounting policies is an
important process that changes as our business changes and as
accounting rules are developed. Accounting rules generally do
not involve a selection among alternatives, but involve an
implementation and interpretation of existing rules and the use
of judgment to the specific set of circumstances existing in our
business.
The sensitivity analyses used below are not intended to provide
a reader with our predictions of the variability of the
estimates used. Rather, the sensitivities used are included to
allow the reader to understand a general cause and effect of
changes in estimates.
Accounting
for Derivative Instruments and Hedging Activities
We use commodity price and financial risk management instruments
to mitigate our exposure to price fluctuations in gas and oil
and changes in interest rates. Recognized gains and losses on
derivative contracts are reported as a component of the related
transaction. Results of gas and oil derivative transactions are
reflected in oil and gas sales, and results of interest rate
hedging transactions are reflected in interest expense. The
changes in the fair value of derivative instruments not
qualifying for designation as either cash flow or fair value
hedges that occur prior to maturity are reported currently in
the statement of operations as unrealized gains (losses) within
oil and gas sales or interest expense. Cash flows from
derivative instruments are classified in the same category
within the statement of cash flows as the items being hedged, or
on a basis consistent with the nature of the instruments.
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities
(SFAS 133), establishes
accounting and reporting standards requiring that derivative
instruments (including certain derivative instruments embedded
in other contracts) be recorded at fair value and included in
the balance sheet as assets or liabilities. The accounting for
changes in the fair value of a derivative instrument depends on
the intended use of the derivative and the resulting
designation, which is established at the inception of a
derivative. For derivative instruments designated as cash flow
hedges, changes in fair value, to the extent the hedge is
effective, are recognized in other comprehensive income until
the hedged item is recognized in earnings. Any change in the
fair value resulting from ineffectiveness, as defined by
SFAS 133, is recognized immediately in oil and gas sales.
For derivative instruments designated as fair value hedges (in
accordance with SFAS 133), changes in fair value, as well
as the offsetting changes in the estimated fair value of the
hedged item attributable to the hedged risk, are recognized
currently in earnings. Differences between the changes in the
fair values of the hedged item and the derivative instrument, if
any, represent gains or losses on ineffectiveness and are
reflected currently in interest expense. Hedge effectiveness is
measured at least quarterly based on the relative changes in
fair value between the derivative contract and the hedged item
over time. Changes in fair value of contracts that do not
qualify as hedges or are not designated as hedges are also
recognized currently in earnings.
One of the primary factors that can have an impact on our
results of operations is the method used to value our
derivatives. We have established the fair value of all
derivative instruments using estimates determined by our
counterparties and subsequently confirmed the fair values
internally using established index prices and other sources.
These values are based upon, among other things, futures prices,
volatility, time to maturity and credit risk. The values we
report in our financial statements change as these estimates are
revised to reflect actual results, changes in market conditions
or other factors, many of which are beyond our control.
Another factor that can impact our results of operations each
period is our ability to estimate the level of correlation
between future changes in the fair value of the hedge
instruments and the transactions being hedged, both at inception
and on an ongoing basis. This correlation is complicated since
energy commodity prices, the primary risk we hedge, have quality
and location differences that can be difficult to hedge
effectively. The factors underlying our estimates of fair value
and our assessment of correlation of our hedging derivatives are
impacted by actual results and changes in conditions that affect
these factors, many of which are beyond our control.
70
Due to the volatility of gas and oil prices and, to a lesser
extent, interest rates, our financial condition and results of
operations can be significantly impacted by changes in the
market value of our derivative instruments. As of
December 31, 2005, 2006 and 2007, the net market value of
our derivatives was a liability of $61.7 million, an asset
of $2.9 million and a liability of $5.5 million,
respectively. With respect to our derivative contracts relating
to periods after December 31, 2007, an increase or decrease
in natural gas prices of $0.10 per MMBtu would decrease or
increase the estimated fair value of our derivative contracts by
approximately $3.1 million.
Gas
and Oil Properties
The accounting for our business is subject to special accounting
rules that are unique to the gas and oil industry. There are two
allowable methods of accounting for oil and gas business
activities: the successful efforts method and the full-cost
method. We follow the full-cost method of accounting under which
all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize
internal costs that can be directly identified with our
acquisition, exploration and development activities and do not
include any costs related to production, general corporate
overhead or similar activities.
Under the successful efforts method, geological and geophysical
costs and costs of carrying and retaining undeveloped properties
are charged to expense as incurred. Costs of drilling
exploratory wells that do not result in proved reserves are
charged to expense. Depreciation, depletion, amortization and
impairment of gas and oil properties are generally calculated on
a well by well or lease or field basis versus the aggregated
full cost pool basis. Additionally, gain or loss is
generally recognized on all sales of gas and oil properties
under the successful efforts method. As a result, our financial
statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of
capitalized costs as well as a higher gas and oil depreciation,
depletion and amortization rate, and we will not have
exploration expenses that successful efforts companies
frequently have.
Under the full-cost method, capitalized costs are amortized on a
composite unit-of-production method based on proved gas and oil
reserves. Depreciation, depletion and amortization expense is
also based on the amount of estimated reserves. If we maintain
the same level of production year over year, the depreciation,
depletion and amortization expense may be significantly
different if our estimate of remaining reserves changes
significantly. Proceeds from the sale of properties are
accounted for as reductions of capitalized costs unless such
sales involve a significant change in the relationship between
costs and the value of proved reserves or the underlying value
of unproved properties, in which case a gain or loss is
recognized. The costs of unproved properties are excluded from
amortization until the properties are evaluated. We review all
of our unevaluated properties quarterly to determine whether or
not and to what extent proved reserves have been assigned to the
properties, and otherwise if impairment has occurred.
Unevaluated properties are assessed individually when individual
costs are significant.
We review the carrying value of our gas and oil properties under
the full-cost accounting rules of the Securities and Exchange
Commission on a quarterly basis. This quarterly review is
referred to as a ceiling test. Under the ceiling test,
capitalized costs, less accumulated amortization and related
deferred income taxes, may not exceed an amount equal to the sum
of the present value of estimated future net revenues (adjusted
for cash flow hedges) less estimated future expenditures to be
incurred in developing and producing the proved reserves, less
any related income tax effects. In calculating future net
revenues, current prices and costs used are those as of the end
of the appropriate quarterly period. Such prices are utilized
except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts,
including the effects of derivatives qualifying as cash flow
hedges. Two primary factors impacting this test are reserve
levels and current prices, and their associated impact on the
present value of estimated future net revenues. Revisions to
estimates of gas and oil reserves
and/or
an
increase or decrease in prices can have a material impact on the
present value of estimated future net revenues. Any excess of
the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess
above the ceiling is not expensed (or is reduced) if, subsequent
to the end of the period, but prior to the release of the
financial statements, gas and oil prices increase sufficiently
such that an excess above the ceiling would have been eliminated
(or reduced) if the increased prices were used in the
calculations.
The process of estimating gas and oil reserves is very complex,
requiring significant decisions in the evaluation of available
geological, geophysical, engineering and economic data. The data
for a given property may also change
71
substantially over time as a result of numerous factors,
including additional development activity, evolving production
history and a continual reassessment of the viability of
production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time
to time. Although every reasonable effort is made to ensure that
reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in
available data for various properties increase the likelihood of
significant changes in these estimates.
As of December 31, 2007, approximately 100% of our proved
reserves were evaluated by independent petroleum engineers. All
reserve estimates are prepared based upon a review of production
histories and other geologic, economic, ownership and
engineering data.
In addition, the prices of gas and oil are volatile and change
from period to period. Price changes directly impact the
estimated revenues from our properties and the associated
present value of future net revenues. Such changes also impact
the economic life of our properties and thereby affect the
quantity of reserves that can be assigned to a property.
For example, if gas prices at December 31, 2007 had been
$1.00 less per Mcf, then the standardized measure of our proved
reserves as of December 31, 2007 would have decreased by
$125.2 million, from $322.5 million to
$197.3 million and our proved reserves would have decreased
by 10.8 Bcfe from 211.1 Bcfe to 200.1 Bcfe.
Recent
Accounting Pronouncements
The Financial Accounting Standards Board (FASB)
recently issued the following standards which we reviewed to
determine the potential impact on our financial statements upon
adoption.
In February 2006, the FASB issued Statement No. 155,
Accounting for Certain Hybrid Financial
Instruments
(SFAS No. 155),
which amends FASB Statements No. 133 and 140.
SFAS No. 155 permits fair value remeasurement for any
hybrid financial instrument containing an embedded derivative
that would otherwise require bifurcation, and broadens a
Qualified Special Purpose Entitys permitted holdings to
include passive derivative financial instruments that pertain to
other derivative financial instruments. SFAS No. 155
is effective for all financial instruments acquired, issued or
subject to a remeasurement event occurring after the beginning
of an entitys first fiscal year beginning after
September 15, 2006. Management adopted
SFAS No. 155 on January 1, 2007 and the initial
adoption of this statement did not have a material impact on our
financial position, results of operations, or cash flows.
In March 2006, the FASB issued SFAS No. 156,
Accounting for Servicing of Financial Asset
(SFAS No. 156). This Statement amends
SFAS No. 140 and addresses the recognition and
measurement of separately recognized servicing assets and
liabilities, such as those common with mortgage securitization
activities, and provides an approach to simplify efforts to
obtain hedge-like (offset) accounting by permitting a servicer
that uses derivative financial instruments to offset risks on
servicing to report both the derivative financial instrument and
related servicing asset or liability by using a consistent
measurement attribute fair value. Management plans
to adopt SFAS No. 156 on January 1, 2008 and it
is anticipated that the initial adoption of this statement will
not have a material impact on our financial position, results of
operations, or cash flows.
In June 2006, the FASB issued Interpretation 48,
Accounting for Uncertainty in Income Taxes
,
an
interpretation of FASB Statement of Financial Accounting
Standards No. 109
(FIN 48).
FIN 48 provides guidance for recognizing and measuring
uncertain tax positions, as defined in SFAS 109,
Accounting for Income Taxes
. FIN 48 prescribes a
threshold condition that a tax position must meet for any of the
benefit of the uncertain tax position to be recognized in the
financial statements. Guidance is also provided regarding
de-recognition, classification and disclosure of these uncertain
tax positions. FIN 48 is effective for fiscal years
beginning after December 15, 2006. Management adopted
FIN 48 on January 1, 2007 and the initial adoption of
FIN 48 did not have a material impact on our financial
position, results of operations or cash flows.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157,
Fair Value
Measurements
(SFAS No. 157).
SFAS No. 157 addresses how companies should measure
fair value when they are required to use a fair value measure
for recognition or disclosure purposes under generally accepted
accounting principles. SFAS No. 157 defines fair
value, establishes a framework for measuring fair value and
expands the
72
required disclosures about fair value measurements.
SFAS No. 157 was originally effective for fiscal years
beginning after November 15, 2007, with earlier adoption
permitted.
On February 6, 2008, the FASB issued Financial Staff
Position
FAS 157-2,
Effective Date of FASB Statement No. 157.
This Staff Position delays the effective date of
SFAS No. 157 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or
disclosed at fair value in the financial statements on a
recurring basis (at least annually). The delay is intended to
allow the FASB and constituents additional time to consider the
effect of various implementation issues that have arisen, or
that may arise, from the application of SFAS No. 157.
The remainder of SFAS No. 157 was adopted by us
effective for fiscal years beginning after November 15,
2007. The adoption of SFAS No. 157 did not have an
impact on our financial position, results of operations or cash
flows.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 158,
Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans
(SFAS No. 158), an
amendment of FASB Statements No. 87, 88, 106 and 132(R).
SFAS No. 158 requires (a) recognition of the
funded status (measured as the difference between the fair value
of the plan assets and the benefit obligation) of a benefit plan
as an asset or liability in the employers statement of
financial position, (b) measurement of the funded status as
of the employers fiscal year-end with limited exceptions,
and (c) recognition of changes in the funded status in the
year in which the changes occur through comprehensive income.
The requirement to recognize the funded status of a benefit plan
and the disclosure requirements are effective as of the end of
the fiscal year ending after December 15, 2006. The
requirement to measure the plan assets and benefit obligations
as of the date of the employers fiscal year-end statement
of financial position is effective for fiscal years ending after
December 15, 2008. Management adopted
SFAS No. 158 on December 31, 2006 and the
adoption of SFAS No. 158 did not have a material
impact on our financial position, results of operations or cash
flows.
In September 2006, the Securities Exchange Commission issued
Staff Accounting Bulletin No. 108
(SAB No. 108). SAB No. 108
addresses how the effects of prior year uncorrected
misstatements should be considered when quantifying
misstatements in current year financial statements.
SAB No. 108 requires companies to quantify
misstatements using a balance sheet and income statement
approach and to evaluate whether either approach results in
quantifying an error that is material in light of relevant
quantitative and qualitative factors. When the effect of initial
adoption is material, companies will record the effect as a
cumulative effect adjustment to beginning of year retained
earnings and disclose the nature and amount of each individual
error being corrected in the cumulative adjustment.
SAB No. 108 became effective beginning January 1,
2007 and its adoption did not have a material impact on our
financial position, results of operations or cash flows.
In February 2007, the FASB issued Statement of Financial
Accounting Standards No. 159,
The Fair Value
Option for Financial Assets and Financial Liabilities
(SFAS No. 159), an amendment of FASB
Statement No. 115. SFAS No. 159 addresses how
companies should measure many financial instruments and certain
other items at fair value. The objective is to mitigate
volatility in reported earnings caused by measuring related
assets and liabilities differently without having to apply
complex hedge accounting provisions. SFAS No. 159 is
effective for fiscal years beginning after November 15,
2007, with earlier adoption permitted. SFAS No. 159
has been adopted and did not have a material impact on our
financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141R
(revised 2007),
Business Combinations.
Although this statement amends and replaces
SFAS No. 141, it retains the fundamental requirements
in SFAS No. 141 that (i) the purchase method of
accounting be used for all business combinations; and
(ii) an acquirer be identified for each business
combination. SFAS No. 141R defines the acquirer as the
entity that obtains control of one or more businesses in the
business combination and establishes the acquisition date as the
date that the acquirer achieves control. This Statement applies
to all transactions or other events in which an entity (the
acquirer) obtains control of one or more businesses (the
acquiree), including combinations achieved without the transfer
of consideration; however, this Statement does not apply to a
combination between entities or businesses under common control.
Significant provisions of SFAS No. 141R concern
principles and requirements for how an acquirer
(i) recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree; (ii) recognizes
and measures the goodwill acquired in the business combination
or a gain from a bargain purchase; and (iii) determines
what information to disclose to enable users of the financial
73
statements to evaluate the nature and financial effects of the
business combination. This Statement applies prospectively to
business combinations for which the acquisition date is on or
after the beginning of the first annual reporting period
beginning on or after December 15, 2008 with early adoption
not permitted. Management is assessing the impact of the
adoption of SFAS No. 141R.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 160,
Noncontrolling
Interests in Consolidated Financial Statements, an amendment of
ARB No. 51
(SFAS No. 160).
The objective of this statement is to improve the relevant,
comparability, and transparency of the financial information
that a reporting entity provides in its consolidated financial
statements related to noncontrolling or minority interests. The
effective date for this Statement is for fiscal years, and
interim periods within those fiscal years, beginning on or after
December 15, 2008 with earlier adoption being prohibited.
Adoption of this Statement will change the method in which
minority interests are reflected on our consolidated financial
statements and will add some additional disclosures related to
the reporting of minority interests. Management is assessing the
impact of the adoption of SFAS No. 160.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161,
Disclosures about Derivative
Instruments and Hedging Activities
(SFAS No. 161). The objective of this
statement is to improve financial reporting about derivative
instruments and hedging activities by requiring enhanced
disclosures to enable investors to better understand their
effects on an entitys financial position, financial
performance, and cash flows. The effective date for this
statement is for financial statements issued for fiscal years
and interim periods beginning after November 15, 2008, with
early application encouraged. Management is assessing the impact
of the adoption of SFAS No. 161.
Forward-Looking
Statements
This report, including information included or incorporated by
reference in this report, contains forward-looking statements
that are subject to a number of risks and uncertainties, many of
which are beyond our control, which may include statements about:
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the volatility of gas and oil prices;
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discovery, estimation, development and replacement of gas and
oil reserves;
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|
cash flow, liquidity and financial condition;
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|
business and financial strategy;
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|
amount, nature and timing of capital expenditures, including
future development costs;
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|
availability and terms of capital;
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|
timing and amount of future production of gas and oil;
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|
availability of drilling and production equipment, labor and
other services;
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|
operating costs and other expenses;
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|
prospect development and property acquisitions;
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|
marketing of gas and oil;
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|
competition in the gas and oil industry;
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the impact of weather and the occurrence of natural disasters
such as fires;
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governmental regulation of the gas and oil industry;
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|
developments in oil-producing and gas-producing
countries; and
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|
strategic plans, expectations and objectives for future
operations.
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74
All of these types of statements, other than statements of
historical fact included in this report, are forward-looking
statements. In some cases, you can identify forward-looking
statements by terminology such as may,
will, could, should,
expect, plan, project,
intend, anticipate, believe,
estimate, predict,
potential, pursue, target,
continue, the negative of such terms or other
comparable terminology.
The forward-looking statements contained in this report are
largely based on our expectations, which reflect estimates and
assumptions made by our management. These estimates and
assumptions reflect our best judgment based on currently known
market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently
uncertain and involve a number of risks and uncertainties that
are beyond our control. In addition, managements
assumptions about future events may prove to be inaccurate.
Management cautions all readers that the forward-looking
statements contained in this report are not guarantees of future
performance, and we cannot assure any reader that such
statements will be realized or the forward-looking events and
circumstances will occur. Actual results may differ materially
from those anticipated or implied in the forward-looking
statements due to factors listed under Risk Factors
in Item 1A of this report. All forward-looking statements
speak only as of the date of this report. We do not intend to
publicly update or revise any forward-looking statements as a
result of new information, future events or otherwise. These
cautionary statements qualify all forward-looking statements
attributable to us or persons acting on our behalf.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market
Risk.
|
See Notes 6 and 7 to our consolidated/carve out financial
statements which are included in Item 8 of this report and
incorporated herein by reference.
75
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
CONSOLIDATED FINANCIAL STATEMENTS
To the Partners of
Quest Energy Partners, L.P.
We have audited the accompanying consolidated balance sheet of
Quest Energy Partners, L.P. and subsidiaries (the
Partnership) as of December 31, 2007, and the
related consolidated statements of operations, cash flows and
partners equity for period from November 15, 2007
through December 31, 2007. These consolidated financial
statements are the responsibility of the Partnerships
management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). The
Partnership is not required to have, nor were we engaged to
perform, an audit of its internal control over financial
reporting. Our audit included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Partnerships internal control over financial
reporting. Accordingly, we express no such opinion. An audit
also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the consolidated financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the
consolidated financial position of the Partnership as of
December 31, 2007, and the consolidated results of its
operations and its cash flows for period from November 15,
2007 through December 31, 2007, in conformity with
accounting principles generally accepted in the United States of
America.
/s/ Murrell, Hall, McIntosh & Co. PLLP
Oklahoma City, Oklahoma
March 28, 2008
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
CARVE OUT FINANCIAL STATEMENTS
To the Partners of
Quest Energy Partners, L.P.
We have audited the accompanying carve out balance sheets of the
Predecessor as defined in Note 3 to the consolidated/carve
out financial statements, (the Predecessor), as of
December 31, 2006, and the related carve out statements of
operations, cash flows and partners capital for the period
from January 1, 2007 through November 14, 2007 and for
the years ended December 31, 2006 and 2005. These financial
statements are the responsibility of the Predecessors
management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. We were not engaged to perform an
audit of the Predecessors internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Predecessors internal control over financial
reporting. Accordingly, we express no such opinion. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the consolidated financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the carve out
financial position of the Predecessor as of December 31,
2006, and the related carve out statements of operations, cash
flows and partners capital for the period from
January 1, 2007 through November 14, 2007 and for the
years ended December 31, 2006 and 2005, in conformity with
accounting principles generally accepted in the United States of
America.
/s/ Murrell, Hall, McIntosh & Co. PLLP
Oklahoma City, Oklahoma
March 28, 2008
F-3
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
BALANCE
SHEETS
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(consolidated)
|
|
|
(carve out)
|
|
|
|
($ in thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
10,170
|
|
|
$
|
21,334
|
|
Restricted cash
|
|
|
1,205
|
|
|
|
1,150
|
|
Accounts receivable, trade
|
|
|
297
|
|
|
|
10,211
|
|
Due from affiliated companies
|
|
|
12,788
|
|
|
|
|
|
Other current assets
|
|
|
2,923
|
|
|
|
1,053
|
|
Inventory
|
|
|
4,956
|
|
|
|
3,378
|
|
Short-term derivative asset
|
|
|
6,729
|
|
|
|
10,795
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
39,068
|
|
|
|
47,921
|
|
Property and equipment, net of accumulated depreciation of
$6,183 and 5,045
|
|
|
17,063
|
|
|
|
16,054
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Properties being amortized
|
|
|
406,661
|
|
|
|
316,783
|
|
Properties not being amortized
|
|
|
19,328
|
|
|
|
9,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,989
|
|
|
|
326,228
|
|
Less: Accumulated depreciation, depletion, amortization and
impairment
|
|
|
(127,968
|
)
|
|
|
(92,733
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
298,021
|
|
|
|
233,495
|
|
Other assets, net
|
|
|
3,526
|
|
|
|
9,466
|
|
Long-term derivative asset
|
|
|
1,568
|
|
|
|
4,782
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
359,246
|
|
|
$
|
311,718
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
15,195
|
|
|
$
|
13,929
|
|
Revenue payable
|
|
|
|
|
|
|
4,540
|
|
Accrued expenses
|
|
|
5,056
|
|
|
|
2,486
|
|
Current portion of notes payable
|
|
|
666
|
|
|
|
324
|
|
Short-term derivative liability
|
|
|
8,241
|
|
|
|
5,244
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
29,158
|
|
|
|
26,523
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Long-term derivative liability
|
|
|
5,586
|
|
|
|
7,449
|
|
Asset retirement obligation
|
|
|
1,700
|
|
|
|
1,410
|
|
Notes payable
|
|
|
94,708
|
|
|
|
225,569
|
|
Less current maturities
|
|
|
(666
|
)
|
|
|
(324
|
)
|
|
|
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
101,328
|
|
|
|
234,104
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
130,486
|
|
|
|
260,627
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Partners equity:
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
|
50,663
|
|
Common unitholders public; 9,100,000 units issued
and outstanding at December 31, 2007
|
|
|
141,364
|
|
|
|
|
|
Common unitholder affiliate; 3,201,521 units issued
and outstanding at December 31, 2007
|
|
|
22,598
|
|
|
|
|
|
Subordinated unitholder affiliate; 8,857,981 units
issued and outstanding at December 31, 2007
|
|
|
63,235
|
|
|
|
|
|
General partner affiliate; 431,827 units issued and
outstanding at December 31, 2007
|
|
|
3,048
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
|
|
|
(1,485
|
)
|
|
|
428
|
|
|
|
|
|
|
|
|
|
|
Total partners equity
|
|
|
228,760
|
|
|
|
51,091
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity
|
|
$
|
359,246
|
|
|
$
|
311,718
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated/carve out financial statements.
F-4
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
STATEMENTS
OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2007)
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
through
|
|
|
through
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(consolidated)
|
|
|
(carve out)
|
|
|
(carve out)
|
|
|
(carve out)
|
|
|
|
($ in thousands, except per unit data)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
15,842
|
|
|
$
|
97,193
|
|
|
$
|
65,551
|
|
|
$
|
44,565
|
|
Other revenue and expense
|
|
|
22
|
|
|
|
(45
|
)
|
|
|
(83
|
)
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
15,864
|
|
|
|
97,148
|
|
|
|
65,468
|
|
|
|
44,952
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
3,579
|
|
|
|
24,416
|
|
|
|
21,208
|
|
|
|
14,388
|
|
Transportation expense
|
|
|
4,342
|
|
|
|
24,836
|
|
|
|
17,278
|
|
|
|
7,038
|
|
General and administrative expenses
|
|
|
1,562
|
|
|
|
10,272
|
|
|
|
8,149
|
|
|
|
4,068
|
|
Provision impairment of gas properties
|
|
|
|
|
|
|
|
|
|
|
30,719
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
5,046
|
|
|
|
30,672
|
|
|
|
25,521
|
|
|
|
20,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
14,529
|
|
|
|
90,196
|
|
|
|
102,875
|
|
|
|
45,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
1,335
|
|
|
|
6,952
|
|
|
|
(37,407
|
)
|
|
|
(663
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in derivative fair value
|
|
|
(6,082
|
)
|
|
|
(420
|
)
|
|
|
6,410
|
|
|
|
(4,668
|
)
|
Sale of assets
|
|
|
(18
|
)
|
|
|
(310
|
)
|
|
|
(7
|
)
|
|
|
12
|
|
Interest expense
|
|
|
(13,760
|
)
|
|
|
(25,815
|
)
|
|
|
(16,935
|
)
|
|
|
(19,919
|
)
|
Interest income
|
|
|
14
|
|
|
|
402
|
|
|
|
390
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income and expense
|
|
|
(19,846
|
)
|
|
|
(26,143
|
)
|
|
|
(10,142
|
)
|
|
|
(24,529
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(18,511
|
)
|
|
|
(19,191
|
)
|
|
|
(47,549
|
)
|
|
|
(25,192
|
)
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(18,511
|
)
|
|
$
|
(19,191
|
)
|
|
$
|
(47,549
|
)
|
|
$
|
(25,192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net (loss)
|
|
$
|
(370
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net (loss)
|
|
$
|
(18,141
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
$
|
(6.80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
$
|
(6.80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
|
1,150,329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
|
1,116,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated/carve out financial statements.
F-5
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
STATEMENTS
OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31
|
|
|
November 14,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(consolidated)
|
|
|
(carve out)
|
|
|
(carve out)
|
|
|
(carve out)
|
|
|
|
($ in thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
$
|
(18,511
|
)
|
|
$
|
(19,191
|
)
|
|
$
|
(47,549
|
)
|
|
$
|
(25,192
|
)
|
Adjustments to reconcile net (loss) to cash provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion
|
|
|
5,391
|
|
|
|
32,904
|
|
|
|
28,339
|
|
|
|
20,121
|
|
Write down of gas properties
|
|
|
|
|
|
|
|
|
|
|
30,719
|
|
|
|
|
|
Accrued interest subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,765
|
|
Change in derivative fair value
|
|
|
6,082
|
|
|
|
420
|
|
|
|
(16,917
|
)
|
|
|
4,580
|
|
Capital contributions for retirement plan
|
|
|
|
|
|
|
|
|
|
|
428
|
|
|
|
266
|
|
Capital contributions for audit committee fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Capital contributions for director fees
|
|
|
|
|
|
|
|
|
|
|
429
|
|
|
|
|
|
Capital contributions to employees
|
|
|
1
|
|
|
|
12
|
|
|
|
779
|
|
|
|
352
|
|
Amortization of loan origination fees
|
|
|
9,042
|
|
|
|
1,918
|
|
|
|
1,202
|
|
|
|
5,108
|
|
Amortization of gas swap fees
|
|
|
|
|
|
|
187
|
|
|
|
208
|
|
|
|
|
|
Amortization of deferred hedging gains
|
|
|
|
|
|
|
|
|
|
|
(328
|
)
|
|
|
(831
|
)
|
Bad debt expense
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
192
|
|
(Gain) loss on sale of assets
|
|
|
|
|
|
|
328
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
(12
|
)
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
(55
|
)
|
|
|
3,167
|
|
|
|
(4,318
|
)
|
Accounts receivable
|
|
|
|
|
|
|
9,840
|
|
|
|
(219
|
)
|
|
|
(3,455
|
)
|
Other receivables
|
|
|
(36
|
)
|
|
|
110
|
|
|
|
(28
|
)
|
|
|
(15
|
)
|
Other current assets
|
|
|
(1,762
|
)
|
|
|
(108
|
)
|
|
|
|
|
|
|
(1,495
|
)
|
Inventory
|
|
|
(823
|
)
|
|
|
(755
|
)
|
|
|
(1,970
|
)
|
|
|
(1,124
|
)
|
Deposits
|
|
|
|
|
|
|
|
|
|
|
675
|
|
|
|
|
|
Due from related parties
|
|
|
(10,830
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
(2,405
|
)
|
|
|
3,719
|
|
|
|
5,836
|
|
|
|
(1,440
|
)
|
Revenue payable
|
|
|
|
|
|
|
(4,540
|
)
|
|
|
4,540
|
|
|
|
|
|
Accrued expenses
|
|
|
119
|
|
|
|
(1,960
|
)
|
|
|
1,838
|
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(13,732
|
)
|
|
|
22,829
|
|
|
|
11,183
|
|
|
|
584
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equipment, development and leasehold
|
|
|
(7,597
|
)
|
|
|
(95,315
|
)
|
|
|
(111,703
|
)
|
|
|
(46,269
|
)
|
Additions to other property and equipment
|
|
|
(6
|
)
|
|
|
(3,428
|
)
|
|
|
(5,684
|
)
|
|
|
(5,413
|
)
|
Proceeds from sale of property and equipment
|
|
|
|
|
|
|
253
|
|
|
|
193
|
|
|
|
37
|
|
Other assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(7,603
|
)
|
|
|
(98,490
|
)
|
|
|
(117,194
|
)
|
|
|
(51,645
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
94,580
|
|
|
|
35,000
|
|
|
|
203,696
|
|
|
|
59,584
|
|
Repayments of note borrowings
|
|
|
(260,014
|
)
|
|
|
(428
|
)
|
|
|
(54,424
|
)
|
|
|
(86,728
|
)
|
Proceeds from subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,297
|
|
Contributions/distributions QRC
|
|
|
49,415
|
|
|
|
21,298
|
|
|
|
(20,142
|
)
|
|
|
133,658
|
|
Proceeds from issuance of common units
|
|
|
163,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Syndication costs of common units
|
|
|
(12,775
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment of subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(66,398
|
)
|
Refinancing costs RBC
|
|
|
(3,527
|
)
|
|
|
(1,688
|
)
|
|
|
|
|
|
|
|
|
Refinancing costs Guggenheim
|
|
|
|
|
|
|
|
|
|
|
(4,479
|
)
|
|
|
(6,272
|
)
|
Change in other long-term liabilities
|
|
|
26
|
|
|
|
145
|
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
31,505
|
|
|
|
54,327
|
|
|
|
124,818
|
|
|
|
47,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
10,170
|
|
|
|
(21,334
|
)
|
|
|
18,807
|
|
|
|
(3,920
|
)
|
Cash, beginning of period
|
|
|
|
|
|
|
21,334
|
|
|
|
2,527
|
|
|
|
6,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period
|
|
$
|
10,170
|
|
|
$
|
|
|
|
$
|
21,334
|
|
|
$
|
2,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated/carve out financial statements.
F-6
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners Equity
|
|
|
|
|
|
|
|
|
|
Excluding
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Accumulated
|
|
|
|
|
|
|
Other
|
|
|
Other
|
|
|
Total
|
|
|
|
Comprehensive
|
|
|
Comprehensive
|
|
|
Owners
|
|
|
|
Income (Loss)
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
Predecessor (Carve Out):
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1, 2005
|
|
$
|
7,266
|
|
|
$
|
(11,143
|
)
|
|
$
|
(3,877
|
)
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
(25,192
|
)
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
|
|
|
|
|
(36,028
|
)
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
(61,220
|
)
|
Partner contributions
|
|
|
133,658
|
|
|
|
|
|
|
|
133,658
|
|
Contributions for consideration for compensation to employees
|
|
|
427
|
|
|
|
|
|
|
|
427
|
|
Contributions for retirement plan
|
|
|
495
|
|
|
|
|
|
|
|
495
|
|
Contributions for consideration of services
|
|
|
64
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
116,718
|
|
|
|
(47,171
|
)
|
|
|
69,547
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
(47,549
|
)
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
|
|
|
|
|
47,599
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Contributions for consideration pursuant to compensation plan
for non-employee directors
|
|
|
429
|
|
|
|
|
|
|
|
429
|
|
Contributions for consideration for compensation to employees
|
|
|
779
|
|
|
|
|
|
|
|
779
|
|
Contributions for retirement plan
|
|
|
428
|
|
|
|
|
|
|
|
428
|
|
Partner distributions
|
|
|
(20,142
|
)
|
|
|
|
|
|
|
(20,142
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
50,663
|
|
|
|
428
|
|
|
|
51,091
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
(19,191
|
)
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
|
|
|
|
|
(9,437
|
)
|
|
|
|
|
Reclassification adjustment into earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
(28,628
|
)
|
Capital contributions from QRC
|
|
|
21,298
|
|
|
|
|
|
|
|
21,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, November 14, 2007
|
|
$
|
52,770
|
|
|
$
|
(9,009
|
)
|
|
$
|
43,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated/carve out financial statements.
F-7
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
STATEMENTS
OF PARTNERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
General
|
|
|
Other
|
|
|
Total
|
|
|
|
Common
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Comprehensive
|
|
|
Partners
|
|
|
|
Unitholders
|
|
|
Unitholders
|
|
|
Interest
|
|
|
Income
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
Successor (Consolidated):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at November 14, 2007
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Proceeds from initial public offering, net of underwriter
discount
|
|
|
163,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163,800
|
|
Offering costs
|
|
|
(12,775
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,775
|
)
|
Acquisition of the Predecessor
|
|
|
26,001
|
|
|
|
72,635
|
|
|
|
3,506
|
|
|
|
(9,009
|
)
|
|
|
93,133
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
(10,551
|
)
|
|
|
(7,590
|
)
|
|
|
(370
|
)
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,524
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,987
|
)
|
Distributions
|
|
|
(2,513
|
)
|
|
|
(1,810
|
)
|
|
|
(88
|
)
|
|
|
|
|
|
|
(4,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
$
|
163,962
|
|
|
$
|
63,235
|
|
|
$
|
3,048
|
|
|
$
|
(1,485
|
)
|
|
$
|
228,760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated/carve out financial statements.
F-8
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
|
|
1.
|
Formation
of the Partnership and Description of Business
|
Quest Energy Partners, L.P., a Delaware limited partnership (the
Partnership), was formed in July 2007 by Quest
Resource Corporation (together with its subsidiaries,
QRC) to acquire, exploit, and develop oil and
natural gas properties and to acquire, own, and operate related
assets. QRC currently owns all the general and limited partner
interests in the Partnership. Quest Energy GP, LLC (the
General Partner) is the general partner of the
Partnership and owns all of the general partner interests. The
Partnership had an initial public offering of its common units
representing limited partner interests (the
Offering). At the close of the Offering, the
Partnership held gas and oil properties and related assets in
the Cherokee Basin of Kansas and Oklahoma (the Cherokee
Basin Operations) that were owned by Quest Cherokee, LLC,
a wholly-owned subsidiary of QRC. At the closing of the
Offering, QRC contributed Quest Cherokee, LLC to the Partnership
in exchange for general partner units, the incentive
distribution rights, common units and subordinated units in the
Partnership.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Basis
of Presentation
The consolidated financial statements and related notes thereto
include the operations of the Partnership and all of its
subsidiaries from November 15, 2007 through
December 31, 2007 (the Successor). The carve
out financial statements and related notes thereto represent the
carve out financial position, results of operations, cash flows
and changes in partners capital of the Cherokee Basin
Operations of QRC (the Predecessor) and reflect the
operations of Quest Cherokee, LLC and Quest Cherokee Oilfield
Services, LLC, formerly owned by QRC. The carve out financial
statements have been prepared in accordance with
Regulation S-X,
Article 3 General instructions as to financial
statements and Staff Accounting Bulletin (SAB)
Topic 1-B Allocations of Expenses and Related Disclosure
in Financial Statements of Subsidiaries, Divisions or Lesser
Business Components of Another Entity. Certain expenses
incurred by QRC are only indirectly attributable to its
ownership of the Cherokee Basin Operations as QRC owns interests
in midstream assets and other gas and oil properties. As a
result, certain assumptions and estimates were made in order to
allocate a reasonable share of such expenses to the Predecessor,
so that the carve out financial statements reflect substantially
all the costs of doing business. The allocations and related
estimates and assumptions are more fully described in this note
and Note 12. Related Party Transactions below.
All significant intercompany accounts and transactions have been
eliminated in consolidation/carving out. In the notes to
consolidated/carve out financial statements, all dollar and
share amounts in tabulations are in thousands of dollars and
shares, respectively, unless otherwise indicated.
Consolidation
Policy
Investee companies in which the Partnership directly or
indirectly owns more than 50% of the outstanding voting
securities or those in which the Partnership has effective
control over are generally accounted for under the consolidation
method of accounting. Under this method, an Investee
companys balance sheet and results of operations are
reflected within the Partnerships Consolidated Financial
Statements. All significant intercompany accounts and
transactions have been eliminated. Minority interests in the net
assets and earnings or losses of a consolidated Investee are
reflected in the caption Minority interest in the
Consolidated Balance Sheets and Statements of Operations.
Minority interest adjusts the Partnerships consolidated
results of operations to reflect only the Partnerships
share of the earnings or losses of the consolidated Investee
company. Upon dilution of control below 50%, the accounting
method is adjusted to the equity or cost method of accounting,
as appropriate, for subsequent periods.
Financial reporting by the Partnerships subsidiaries is
consolidated into one set of financial statements for the
Partnership.
F-9
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Use of
Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires us to make
estimates and assumptions that affect the amounts reported in
the consolidated/carve out financial statements and accompanying
notes. Actual results could differ from those estimates.
Estimates made in preparing the consolidated/carve out financial
statements include, among other things, estimates of the proved
gas and oil reserve volumes used in calculating depletion,
depreciation and amortization expense; the estimated future cash
flows and fair value of properties used in determining the need
for any impairment write-down; and the timing and amount of
future abandonment costs used in calculating asset retirement
obligations. Future changes in the assumptions used could have a
significant impact on reported results in future periods.
Basis
of Accounting
The Partnerships financial statements are prepared using
the accrual method of accounting. Revenues are recognized when
earned and expenses when incurred.
Revenue
Recognition
Revenue from the sale of oil and natural gas is recognized when
title passes, net of royalties.
Cash
Equivalents
For purposes of the financial statements, the Partnership
considers investments in all highly liquid instruments with
original maturities of three months or less at date of purchase
to be cash equivalents.
Uninsured
Cash Balances
The Partnership maintains its cash balances at several financial
institutions. Accounts at the institutions are insured by the
Federal Deposit Insurance Corporation up to $100,000. The
Partnerships cash balances typically are in excess of this
amount.
Restricted
Cash
Restricted cash represents cash pledged to support reimbursement
obligations under outstanding letters of credit.
Accounts
Receivable
The Partnership conducts all of its operations in the States of
Kansas and Oklahoma and operates exclusively in the natural gas
and oil industry. The Partnerships joint interest and
natural gas and oil sales receivables are generally unsecured;
however, the Partnership has not experienced any significant
losses to date. Receivables are recorded at the estimate of
amounts due based upon the terms of the related agreements.
Management periodically assesses the Partnerships accounts
receivable and establishes an allowance for estimated
uncollectible amounts. Accounts determined to be uncollectible
are charged to operations when that determination is made.
Inventory
Inventory, which is included in current assets, includes tubular
goods and other lease and well equipment which we plan to
utilize in our ongoing exploration and development activities
and is carried at the lower of cost or market using the specific
identification method.
F-10
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Concentration
of Credit Risk
A significant portion of the Partnership and the
Predecessors liquidity was concentrated in cash and
derivative contracts that enable the Partnership to hedge a
portion of its exposure to price volatility from producing
natural gas and oil. These arrangements expose the Partnership
to credit risk from its counterparties. The Partnership and the
Predecessors accounts receivable are primarily from
purchasers of natural gas and oil products. Natural gas sales to
two purchasers (ONEOK Energy Marketing and Trading Company and
Tenaska Marketing Ventures) accounted for 79% and 21%,
respectively, of total natural gas revenues for the year ended
December 31, 2007. For the period from November 15,
2007 through December 31, 2007, natural gas sales to one
purchaser (ONEOK) accounted for approximately 100% of total
revenues. Natural gas sales to one purchaser (ONEOK) accounted
for more than 95% of total natural gas and oil revenues for the
years ended December 31, 2006 and 2005. The industry
concentration has the potential to impact the Partnerships
overall exposure to credit risk, either positively or
negatively, in that the Partnerships customers may be
similarly affected by changes in economic, industry or other
conditions.
Natural
Gas and Oil Properties
The Partnership follows the full cost method of accounting for
natural gas and oil properties, prescribed by the Securities and
Exchange Commission (SEC). Under the full cost
method, all acquisition, exploration, and development costs are
capitalized. The Partnership capitalizes internal costs
including: salaries and related fringe benefits of employees
directly engaged in the acquisition, exploration and development
of natural gas and oil properties, as well as other directly
identifiable general and administrative costs associated with
such activities.
All capitalized costs of natural gas and oil properties,
including estimated future costs to develop proved reserves, are
amortized on the units-of-production method using estimates of
proved reserves. The costs of unproved properties are excluded
from amortization until the properties are evaluated. The
Partnership reviews all of its unevaluated properties quarterly
to determine whether or not and to what extent proved reserves
have been assigned to the properties and otherwise if impairment
has occurred. Unevaluated properties are assessed individually
when individual costs are significant.
The Partnership reviews the carrying value of its oil and
natural gas properties under the full-cost accounting rules of
the Securities and Exchange Commission on a quarterly basis.
This quarterly review is referred to as a ceiling test. Under
the ceiling test, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed
an amount equal to the sum of the present value of estimated
future net revenues (adjusted for cash flow hedges) less
estimated future expenditures to be incurred in developing and
producing the proved reserves, plus the cost of properties not
being amortized, less any related income tax effects. In
calculating future net revenues, current prices and costs used
are those as of the end of the appropriate quarterly period.
Such prices are utilized except where different prices are fixed
and determinable from applicable contracts for the remaining
term of those contracts, including the effects of derivatives
qualifying as cash flow hedges. Two primary factors impacting
this test are reserve levels and current prices, and their
associated impact on the present value of estimated future net
revenues. Revisions to estimates of natural gas and oil reserves
and/or
an
increase or decrease in prices can have a material impact on the
present value of estimated future net revenues. Any excess of
the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess
above the ceiling is not expensed (or is reduced) if, subsequent
to the end of the period, but prior to the release of the
financial statements, oil and natural gas prices increase
sufficiently such that an excess above the ceiling would have
been eliminated (or reduced) if the increased prices were used
in the calculations.
Based on the low natural gas prices on December 31, 2007,
the Partnership would have incurred a non-cash impairment loss
of approximately $14.9 million at December 31, 2007.
However, under the SECs accounting guidance in Staff
Accounting Bulletin Topic 12(D)(e), if natural gas prices
increase sufficiently between the end of a period and the
completion of the financial statements for that period to
eliminate the need for an impairment charge, an issuer is not
required to recognize the non-cash impairment loss in its
financial statements for that period. As of March 1, 2008,
natural gas prices had improved sufficiently to eliminate the
need for an impairment loss at
F-11
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
December 31, 2007 and as a result, no impairment loss is
reflected in the Partnerships financial statements for the
year ended December 31, 2007.
As of December 31, 2006, the Partnerships net book
value of oil and gas properties exceeded the ceiling.
Accordingly, a provision for impairment was recognized in the
fourth quarter of 2006 of $30.7 million. The provision for
impairment is primarily attributable to declines in the
prevailing market prices of oil and gas at the measurement date.
Sales of proved and unproved properties are accounted for as
adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter
the relationship between the capitalized costs and proved
reserves of natural gas and oil, in which case the gain or loss
is recognized in income.
Other
Property and Equipment
Other property and equipment is reviewed on an annual basis for
impairment and as of December 31, 2007, the Partnership had
not identified any such impairment. Repairs and maintenance are
charged to operations when incurred and improvements and
renewals are capitalized.
Other property and equipment are stated at cost. Depreciation is
calculated using the straight-line method for financial
reporting purposes and accelerated methods for income tax
purposes.
The estimated useful lives are as follows:
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Buildings:
25 years;
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Equipment:
10 years; and
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Vehicles:
7 years.
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Debt
Issue Costs
Included in other assets are costs associated with bank credit
facilities. The remaining unamortized debt issue costs at
December 31, 2007 and 2006 totaled $8.5 million and
$9.1 million, respectively, and are being amortized over
the life of the credit facilities. During November 2007, the
Guggenheim credit facilities were repaid, resulting in the
charge of $9.0 million in unamortized loan fees and the
payment of prepayment penalties totaling $4.1 million.
Other
Dispositions
Upon disposition or retirement of property and equipment other
than natural gas and oil properties, the cost and related
accumulated depreciation are removed from the accounts and the
gain or loss thereon, if any, is credited or charged to income.
Marketable
Securities
In accordance with Statement of Financial Accounting Standards
No. 115,
Accounting for Certain Investments in Debt and
Equity Securities
(SFAS No. 115), the
Partnership classifies its investment portfolio according to the
provisions of SFAS 115 as either held to maturity, trading,
or available for sale. At December 31, 2007 and 2006, the
Partnership did not have any investments in its investment
portfolio classified as available for sale and held to maturity.
Income
Taxes
We are not a taxable entity for federal income tax purposes. As
such, we do not directly pay federal income tax. Our taxable
income or loss, which may vary substantially from the net income
or net loss we report in our
F-12
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
consolidated statement of income, is includable in the federal
income tax returns of each partner. The aggregate difference in
the basis of our net assets for financial and tax reporting
purposes cannot be readily determined as we do not have access
to information about each partners tax attributes in us.
Fair
Value of Financial Instruments
The Partnerships financial instruments consist of cash,
receivables, deposits, hedging contracts, accounts payable,
accrued expenses and notes payable. The carrying amount of cash,
receivables, deposits, accounts payable and accrued expenses
approximates fair value because of the short-term nature of
those instruments. The hedging contracts are recorded in
accordance with the provisions of Statement of Financial
Accounting Standards No. 133,
Accounting for Derivative
Instruments and Hedging Activities
. The carrying amounts for
notes payable approximate fair value due to the variable nature
of the interest rates of the notes payable.
Accounting
for Derivative Instruments and Hedging Activities
The Partnership seeks to reduce its exposure to unfavorable
changes in natural gas prices by utilizing energy swaps and
collars (collectively, fixed-price contracts). The
Partnership also enters into interest rate swaps and caps to
reduce its exposure to adverse interest rate fluctuations. The
Partnership has adopted Statement of Financial Accounting
Standards No. 133, as amended by Statement of Financial
Accounting Standards No. 138,
Accounting for Derivative
Instruments and Hedging Activities
, which contains
accounting and reporting guidelines for derivative instruments
and hedging activities. It requires that all derivative
instruments be recognized as assets or liabilities in the
statement of financial position, measured at fair value. The
accounting for changes in the fair value of a derivative depends
on the intended use of the derivative and the resulting
designation. Designation is established at the inception of a
derivative, but re-designation is permitted. For derivatives
designated as cash flow hedges and meeting the effectiveness
guidelines of SFAS No. 133, changes in fair value are
recognized in other comprehensive income until the hedged item
is recognized in earnings. Hedge effectiveness is measured at
least quarterly based on the relative changes in fair value
between the derivative contract and the hedged item over time.
Any change in fair value resulting from ineffectiveness is
recognized immediately in earnings.
Pursuant to the provisions of SFAS No. 133, all
hedging designations and the methodology for determining hedge
ineffectiveness must be documented at the inception of the
hedge, and, upon the initial adoption of the standard, hedging
relationships must be designated anew. Based on the
interpretation of these guidelines by the Predecessor, the
changes in fair value of all of its derivatives during the
period from June 1, 2003 to December 22, 2003 were
required to be reported in results of operations, rather than in
other comprehensive income. Also, all changes in fair value of
the Partnerships interest rate swaps and caps are reported
in results of operations rather than in other comprehensive
income because the critical terms of the interest rate swaps and
caps do not comply with certain requirements set forth in
SFAS 133.
Although the Partnerships fixed-price contracts may not
qualify for special hedge accounting treatment from time to time
under the specific guidelines of SFAS No. 133, the
Partnership has continued to refer to these contracts in this
document as hedges inasmuch as this was the intent when such
contracts were executed, the characterization is consistent with
the actual economic performance of the contracts, and the
Partnership expects the contracts to continue to mitigate its
commodity price and interest rate risks in the future. The
specific accounting for these contracts, however, is consistent
with the requirements of SFAS No. 133. Please read
Note 7. Derivatives below.
The Partnership has established the fair value of all derivative
instruments using estimates determined by its counterparties and
subsequently evaluated internally using established index prices
and other sources. These values are based upon, among other
things, futures prices, volatility, and time to maturity and
credit risk. The values reported in the financial statements
change as these estimates are revised to reflect actual results,
changes in market conditions or other factors.
F-13
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Asset
Retirement Obligations
The Partnership has adopted FASBs Statement of Financial
Accounting Standards No. 143,
Accounting for Asset
Retirement Obligations
(SFAS No. 143).
SFAS No. 143 requires companies to record the fair
value of a liability for an asset retirement obligation in the
period in which it is incurred and a corresponding increase in
the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its present value each period, and
the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs
a gain or loss upon settlement.
The Partnerships asset retirement obligations relate to
the plugging and abandonment of natural gas and oil properties.
Net
Income per Limited Partner Unit
We calculate net income per limited partner unit in accordance
with Emerging Issues Task Force
03-06,
Participating Securities and the Two
Class Method under FASB Statement No. 128
(EITF 03-06).
EITF 03-06
requires that in any accounting period where our aggregate net
income exceeds our aggregate distribution for such period, we
are required to present earnings per unit as if all of the
earnings for the periods were distributed, regardless of whether
those earnings would actually be distributed during a particular
period from an economic or practical perspective.
Business
Segment Reporting
We operate in one reportable segment engaged in the
exploitation, development and production of oil and natural gas
properties and all of our operations are located in the United
States.
Allocation
of Costs
The accompanying carve out financial statements of the
Predecessor have been prepared in accordance with SAB Topic
1-B. These rules require allocations of costs for salaries and
benefits, depreciation, rent, accounting, legal services, and
other general and administrative expenses. QRC has allocated
general and administrative expenses to the Predecessor based on
time and other costs required to properly manage the assets. In
managements estimation, the allocation methodologies used
are reasonable and result in an allocation of the cost of doing
business borne by QRC on behalf of the Predecessor; however,
these allocations may not be indicative of the cost of future
operations or the amount of future allocations.
Audited historical financial statements of the Cherokee Basin
Operations as of December 31, 2006 and for the period from
January 1, 2007 through November 14, 2007, and the
years ended December 31, 2006 and 2005 are presented. The
historical financial statements were prepared as follows:
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Revenues include all revenues earned by the Cherokee Basin
Operations, before elimination of intercompany sales with QRC
and its subsidiaries. Prior to December 1, 2006, pursuant
to a transportation agreement, Bluestem Pipeline, a wholly-owned
subsidiary of QRC, generally charged the Cherokee Basin
Operations transportation fees ranging from $0.78 per thousand
cubic feet (Mcf) to $0.87 per Mcf. Effective
December 1, 2006, pursuant to the midstream services
agreement, the fee for gathering, dehydration and treating
services was $0.50 per MMBtu of gas and $1.10 per MMBtu of gas
for compression services, subject to annual adjustment. Please
read Note 12. Related Party Transactions.
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Certain common expenses of QRCs operations and the
Cherokee Basin Operations were treated as follows:
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general and administrative expenses associated with the pipeline
operations were eliminated;
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F-14
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
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costs associated with the salt water disposal system, which were
previously reported in Bluestem operations prior to the
formation of Quest Midstream Partners, L.P. (Quest
Midstream) in December 2006, were allocated to the
Cherokee Basin Operations; and
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third party costs incurred at the QRC level that are clearly
identifiable as Cherokee Basin Operations costs, such as
insurance premiums related to the Cherokee Basin Operations and
legal fees of outside counsel related to contracts entered into
or claims made by or against the Cherokee Basin Operations and
salaries and benefits of Cherokee Basin Operations executives
paid by QRC, were allocated to the Cherokee Basin Operations.
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Non-producing acreage located outside of the Cherokee Basin and
not transferred to the Partnership was eliminated from the
balance sheet and related expenses were eliminated.
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To the extent that the common expenses described above were
charged to the Cherokee Basin Operations in the past, the
reduction in expenses was retroactively reflected with the
offsetting debit to partners equity.
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Since the Partnership is not subject to entity level income
taxes, no allocation of income taxes or deferred income taxes
was reflected in the financial statements.
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Derivative transactions remained with the Cherokee Basin
Operations.
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Managements estimates of the expenses of the Cherokee
Basin Operations on a stand-alone basis were not expected to be
significantly different from those reflected in the statements.
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Recently
Issued Accounting Standards
The Financial Accounting Standards Board recently issued the
following standards which the Partnership reviewed to determine
the potential impact on our financial statements upon adoption.
In February 2006, the FASB issued Statement No. 155,
Accounting for Certain Hybrid Financial
Instruments
(SFAS No. 155),
which amends FASB Statements No. 133 and 140.
SFAS No. 155 permits fair value remeasurement for any
hybrid financial instrument containing an embedded derivative
that would otherwise require bifurcation, and broadens a
Qualified Special Purpose Entitys permitted holdings to
include passive derivative financial instruments that pertain to
other derivative financial instruments. SFAS No. 155
is effective for all financial instruments acquired, issued or
subject to a remeasurement event occurring after the beginning
of an entitys first fiscal year beginning after
September 15, 2006. Management adopted
SFAS No. 155 on January 1, 2007 and the initial
adoption of this statement did not have a material impact on the
Partnerships financial position, results of operations, or
cash flows.
In March 2006, the FASB issued SFAS No. 156,
Accounting for Servicing of Financial Asset
(SFAS No. 156). This Statement amends
SFAS No. 140 and addresses the recognition and
measurement of separately recognized servicing assets and
liabilities, such as those common with mortgage securitization
activities, and provides an approach to simplify efforts to
obtain hedge-like (offset) accounting by permitting a servicer
that uses derivative financial instruments to offset risks on
servicing to report both the derivative financial instrument and
related servicing asset or liability by using a consistent
measurement attribute fair value. Management plans
to adopt SFAS No. 156 on January 1, 2008 and it
is anticipated that the initial adoption of this statement will
not have a material impact on the Partnerships financial
position, results of operations, or cash flows.
In June 2006, the FASB issued Interpretation 48,
Accounting for Uncertainty in Income Taxes
,
an
interpretation of FASB Statement of Financial Accounting
Standards No. 109
(FIN 48).
FIN 48 provides guidance for recognizing and measuring
uncertain tax positions, as defined in SFAS 109,
Accounting for Income Taxes
. FIN 48 prescribes a
threshold condition that a tax position must meet for any of the
benefit of the uncertain tax position to be recognized in the
financial statements. Guidance is also provided regarding
de-recognition, classification and disclosure of these uncertain
tax positions. FIN 48 is effective for fiscal years
beginning after December 15, 2006.
F-15
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Management adopted FIN 48 on January 1, 2007 and the
initial adoption of FIN 48 did not have a material impact
on our financial position, results of operations or cash flows.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157,
Fair Value
Measurements
(SFAS No. 157).
SFAS No. 157 addresses how companies should measure
fair value when they are required to use a fair value measure
for recognition or disclosure purposes under generally accepted
accounting principles. SFAS No. 157 defines fair
value, establishes a framework for measuring fair value and
expands the required disclosures about fair value measurements.
SFAS No. 157 was originally effective for fiscal years
beginning after November 15, 2007, with earlier adoption
permitted.
On February 6, 2008, the FASB issued Financial Staff
Position
FAS 157-2,
Effective Date of FASB Statement No. 157.
This Staff Position delays the effective date of
SFAS No. 157 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or
disclosed at fair value in the financial statements on a
recurring basis (at least annually). The delay is intended to
allow the FASB and constituents additional time to consider the
effect of various implementation issues that have arisen, or
that may arise, from the application of SFAS No. 157.
The remainder of SFAS No. 157 was adopted by us
effective for fiscal years beginning after November 15,
2007. The adoption of SFAS No. 157 did not have an
impact on our financial position, results of operations or cash
flows.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 158,
Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans
(SFAS No. 158), an
amendment of FASB Statements No. 87, 88, 106 and 132(R).
SFAS No. 158 requires (a) recognition of the
funded status (measured as the difference between the fair value
of the plan assets and the benefit obligation) of a benefit plan
as an asset or liability in the employers statement of
financial position, (b) measurement of the funded status as
of the employers fiscal year-end with limited exceptions,
and (c) recognition of changes in the funded status in the
year in which the changes occur through comprehensive income.
The requirement to recognize the funded status of a benefit plan
and the disclosure requirements are effective as of the end of
the fiscal year ending after December 15, 2006. The
requirement to measure the plan assets and benefit obligations
as of the date of the employers fiscal year-end statement
of financial position is effective for fiscal years ending after
December 15, 2008. SFAS No. 158 has no current
applicability to our financial statements. Management adopted
SFAS No. 158 on December 31, 2006 and the
adoption of SFAS No. 158 did not have a material
impact on our financial position, results of operations or cash
flows.
In September 2006, the Securities Exchange Commission issued
Staff Accounting Bulletin No. 108
(SAB No. 108). SAB No. 108
addresses how the effects of prior year uncorrected
misstatements should be considered when quantifying
misstatements in current year financial statements.
SAB No. 108 requires companies to quantify
misstatements using a balance sheet and income statement
approach and to evaluate whether either approach results in
quantifying an error that is material in light of relevant
quantitative and qualitative factors. When the effect of initial
adoption is material, companies will record the effect as a
cumulative effect adjustment to beginning of year retained
earnings and disclose the nature and amount of each individual
error being corrected in the cumulative adjustment.
SAB No. 108 became effective beginning January 1,
2007 and its adoption did not have a material impact on our
financial position, results of operations or cash flows.
In February 2007, the FASB issued Statement of Financial
Accounting Standards No. 159,
The Fair Value
Option for Financial Assets and Financial Liabilities
(SFAS No. 159), an amendment of FASB
Statement No. 115. SFAS No. 159 addresses how
companies should measure many financial instruments and certain
other items at fair value. The objective is to mitigate
volatility in reported earnings caused by measuring related
assets and liabilities differently without having to apply
complex hedge accounting provisions. SFAS No. 159 is
effective for fiscal years beginning after November 15,
2007, with earlier adoption permitted. SFAS No. 159
has been adopted and did not have a material impact on our
financial position, results of operations or cash flows.
F-16
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
In December 2007, the FASB issued SFAS No. 141R
(revised 2007),
Business Combinations.
Although this statement amends and replaces
SFAS No. 141, it retains the fundamental requirements
in SFAS No. 141 that (i) the purchase method of
accounting be used for all business combinations; and
(ii) an acquirer be identified for each business
combination. SFAS No. 141R defines the acquirer as the
entity that obtains control of one or more businesses in the
business combination and establishes the acquisition date as the
date that the acquirer achieves control. This Statement applies
to all transactions or other events in which an entity (the
acquirer) obtains control of one or more businesses (the
acquiree), including combinations achieved without the transfer
of consideration; however, this Statement does not apply to a
combination between entities or businesses under common control.
Significant provisions of SFAS No. 141R concern
principles and requirements for how an acquirer
(i) recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree; (ii) recognizes
and measures the goodwill acquired in the business combination
or a gain from a bargain purchase; and (iii) determines
what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the
business combination. This Statement applies prospectively to
business combinations for which the acquisition date is on or
after the beginning of the first annual reporting period
beginning on or after December 15, 2008 with early adoption
not permitted. Management is assessing the impact of the
adoption of SFAS No. 141R.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 160,
Noncontrolling
Interests in Consolidated Financial Statements, an amendment of
ARB No. 51
(SFAS No. 160).
The objective of this statement is to improve the relevant,
comparability, and transparency of the financial information
that a reporting entity provides in its consolidated financial
statements related to noncontrolling or minority interests. The
effective date for this Statement is for fiscal years, and
interim periods within those fiscal years, beginning on or after
December 15, 2008 with earlier adoption being prohibited.
Adoption of this Statement will change the method in which
minority interests are reflected on the Partnerships
consolidated financial statements and will add some additional
disclosures related to the reporting of minority interests.
Management is assessing the impact of the adoption of
SFAS No. 160.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161,
Disclosures about Derivative
Instruments and Hedging Activities
(SFAS No. 161). The objective of this
statement is to improve financial reporting about derivative
instruments and hedging activities by requiring enhanced
disclosures to enable investors to better understand their
effects on an entitys financial position, financial
performance, and cash flows. The effective date for this
statement is for financial statements issued for fiscal years
and interim periods beginning after November 15, 2008, with
early application encouraged. Management is assessing the impact
of the adoption of SFAS No. 161.
Reclassifications
Certain reclassifications have been made to the prior
years combined financial statements to conform with the
current period presentation. These reclassifications had no
effect on previously reported results of operations or
partners capital.
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3.
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Initial
Public Offering
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On November 15, 2007, the Partnership completed an initial
public offering of 9,100,000 common units at $18.00 per unit, or
$16.83 per unit after payment of the underwriting discount
(excluding a structuring fee). On November 9, 2007, the
Partnerships common units began trading on the NASDAQ
Global Market under the symbol QELP. Total proceeds
from the sale of the common units in the initial public offering
were $163.8 million, before underwriting discounts, a
structuring fee and offering costs, of approximately
$10.6 million, $0.4 million and $1.5 million,
respectively. The Partnership used the net proceeds of
$151.2 million to repay indebtedness of QRC.
In connection with the closing of the initial public offering,
the Partnership issued 3,201,521 common units, representing
limited partnership interests in the Partnership, and 8,857,981
subordinated units, representing
F-17
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
additional limited partnership interests in the Partnership, to
QRC and 431,827 units representing a 2% general partner
interest in the Partnership to Quest Energy GP.
Additionally, on November 15, 2007:
(a) The Partnership, Quest Energy GP, QRC and certain of
QRCs subsidiaries entered into a Contribution, Conveyance
and Assumption Agreement (the Contribution
Agreement). At the closing of the offering, the following
transactions, among others, occurred pursuant to the
Contribution Agreement:
|
|
|
|
|
the contribution of Quest Cherokee, LLC (Quest
Cherokee) and its subsidiary, Quest Oilfield Service, LLC
(QCOS), to the Partnership;
|
|
|
|
the issuance of 431,827 general partner units and the incentive
distribution rights to Quest Energy GP and the continuation of
its 2.0% general partner interest in the Partnership;
|
|
|
|
the issuance of 3,201,521 common units and 8,857,981
subordinated units to QRC; and
|
|
|
|
QRC and its affiliates on the one hand, and Quest Cherokee and
the Partnership on the other, agreed to indemnify the other
parties from and against all losses suffered or incurred by
reason of or arising out of certain existing legal proceedings.
|
(b) The Partnership, Quest Energy GP and QRC entered into
an Omnibus Agreement, which governs the Partnerships
relationship with QRC and its affiliates regarding the following
matters:
|
|
|
|
|
reimbursement of certain insurance, operating and general and
administrative expenses incurred on behalf of the Partnership;
|
|
|
|
indemnification for certain environmental liabilities, tax
liabilities, tax defects and other losses in connection with
assets;
|
|
|
|
a license for the use of the Quest name and mark; and
|
|
|
|
the Partnerships right to purchase from QRC and its
affiliates certain assets that QRC and its affiliates acquire
within the Cherokee Basin.
|
(c) The Partnership, Quest Energy GP and Quest Energy
Service, LLC (QES) entered into a Management
Services Agreement, under which QES will perform acquisition
services and general and administrative services, such as
accounting, finance, tax, property management, risk management,
land, marketing, legal and engineering to the Partnership, as
directed by Quest Energy GP, for which the Partnership will
reimburse QES on a monthly basis for the reasonable costs of the
services provided.
(d) The Partnership entered into an Assignment and
Assumption Agreement (the Assignment) with Bluestem
Pipeline, LLC (Bluestem) and QRC, whereby QRC
assigned all of its rights in that certain Midstream Services
and Gas Dedication Agreement, dated as of December 22,
2006, but effective as of December 1, 2006, as amended (the
Midstream Services Agreement), to the Partnership,
and the Partnership assumed all of QRCs liabilities and
obligations arising under the Midstream Services Agreement from
and after the assignment. As more fully described in the
Partnerships final prospectus (the Prospectus)
dated November 8, 2007 (File
No. 333-144716)
and filed on November 9, 2007 with the SEC pursuant to
Rule 424(b)(4) under the Securities Act of 1933, under the
Midstream Services Agreement, Bluestem will gather and provide
certain midstream services, including dehydration, treating and
compression, to the Partnership for all gas produced from the
Partnerships wells in the Cherokee Basin that are
connected to Bluestems gathering system.
(e) The Partnership signed an Acknowledgement and Consent
and therefore became subject to that certain Omnibus Agreement
(the Midstream Omnibus Agreement), dated
December 22, 2006, among QRC, Quest Midstream GP, LLC,
Bluestem and Quest Midstream, which is more fully described in
the Partnerships
F-18
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Prospectus. As long as the Partnership is an affiliate of QRC
and QRC or any of its affiliates control Quest Midstream, the
Partnership will be bound by the Midstream Omnibus Agreement.
The Quest Midstream Agreement restricts the Partnership from
engaging in the following businesses, subject to certain
exceptions:
|
|
|
|
|
the gathering, treating, processing and transporting of gas in
North America;
|
|
|
|
the transporting and fractionating of gas liquids in North
America;
|
|
|
|
any other midstream activities, including but not limited to
crude oil storage, transportation, gathering and terminaling;
|
|
|
|
constructing, buying or selling any assets related to the
foregoing businesses; and
|
|
|
|
any line of business other than those described in the preceding
bullet points that generates qualifying income,
within the meaning of Section 7704(d) of the Internal
Revenue Code of 1986, as amended, other than any business that
is primarily engaged in the exploration for and production of
oil or gas and the sale and marketing of gas and oil derived
from such exploration and production activities.
|
(f) Quest Energy GP adopted the Quest Energy Partners, L.P.
Long-Term Incentive Plan (the Plan) for employees,
consultants and directors of Quest Energy GP and its affiliates,
including the Partnership, who perform services for the
Partnership. The Plan provides for the grant of unit awards,
restricted units, phantom units, unit options, unit appreciation
rights, distribution equivalent rights and other unit-based
awards. Subject to adjustment for certain events, an aggregate
of 2,115,950 common units may be delivered pursuant to awards
under the Plan.
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
($ in thousands)
|
|
|
Senior credit facilities
|
|
$
|
94,000
|
|
|
$
|
225,000
|
|
Notes payable to banks and finance companies, secured by
equipment and vehicles, due in installments through October 2013
with interest ranging from 5.5% to 11.5% per annum
|
|
|
708
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
94,708
|
|
|
|
225,569
|
|
Less current maturities
|
|
|
666
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt, net of current maturities
|
|
$
|
94,042
|
|
|
$
|
225,245
|
|
|
|
|
|
|
|
|
|
|
The aggregate scheduled maturities of notes payable and
long-term debt for the five years ending December 31, 2012
and thereafter were as follows as of December 31, 2007:
|
|
|
|
|
2008
|
|
$
|
666,000
|
|
2009
|
|
|
17,000
|
|
2010
|
|
|
7,000
|
|
2011
|
|
|
6,000
|
|
2012
|
|
|
94,006,000
|
|
Thereafter
|
|
|
6,000
|
|
|
|
|
|
|
|
|
$
|
94,708,000
|
|
|
|
|
|
|
F-19
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Credit
Facility
On November 15, 2007, the Partnership entered into an
Amended and Restated Credit Agreement (the Credit
Agreement), as a guarantor, with QRC, as the initial
co-borrower, Quest Cherokee, as the borrower, Royal Bank of
Canada, as administrative agent and collateral agent
(RBC), KeyBank National Association, as
documentation agent and the lenders party thereto. Quest
Cherokee and QRC had previously been parties to the following
credit agreements with Guggenheim Corporate Funding, LLC
(Guggenheim): (i) Amended and Restated Senior
Credit Agreement, dated February 7, 2006, as amended;
(ii) Amended and Restated Second Lien Term Loan Agreement,
dated June 9, 2006, as amended; and (iii) Third Lien
Term Loan Agreement, dated June 9, 2006, as amended
(collectively, the Prior Credit Agreements).
Guggenheim and the lenders under the Prior Credit Agreements
assigned all of their interests and rights (other than certain
excepted interests and rights) in the Prior Credit Agreements to
RBC and the new lenders under the Credit Agreement pursuant to a
Loan Transfer Agreement, dated November 15, 2007, by and
among QRC, Quest Cherokee, Quest Oil & Gas, LLC, QES,
QCOS, Guggenheim, Wells Fargo Foothill, Inc., the lenders under
the Prior Credit Agreements and RBC. The Credit Agreement
amended and restated the Prior Credit Agreements in their
entirety.
The credit facility under the Credit Agreement consists of a
five-year $250 million revolving credit facility.
Availability under the revolving credit facility is tied to a
borrowing base that will be redetermined by RBC and the lenders
every six months taking into account the value of Quest
Cherokees proved reserves. In addition, Quest Cherokee and
RBC each have the right to initiate a redetermination of the
borrowing base between each six-month redetermination. In
connection with the closing of the initial public offering and
the application of the net proceeds thereof, QRC was released as
a borrower under the Credit Agreement. As of December 31,
2007, the borrowing base was $160 million, and the amount
borrowed under the Credit Agreement was $94 million.
Quest Cherokee will pay a quarterly revolving commitment fee
equal to 0.30% to 0.50% (depending on the utilization
percentage) of the actual daily amount by which the lesser of
the aggregate revolving commitment and the borrowing base
exceeds the sum of the outstanding balance of borrowings and
letters of credit under the revolving credit facility.
In general, interest accrues on the revolving credit facility at
either LIBOR plus a margin ranging from 1.25% to 1.875%
(depending on the utilization percentage) or the base rate plus
a margin ranging from 0.25% to 0.875% (depending on the
utilization percentage). The revolving credit facility may be
prepaid, without any premium or penalty, at any time. The base
rate is generally the higher of the federal funds rate plus
0.50% or RBCs prime rate.
The Partnership and QCOS have guaranteed all of Quest
Cherokees obligations under the Credit Agreement. The
revolving credit facility is secured by a first priority lien on
substantially all of the assets of the Partnership, Quest
Cherokee and QCOS.
The Credit Agreement provides that all obligations arising under
the loan documents, including obligations under any hedging
agreement entered into with lenders or their affiliates, will be
secured
pari passu
by the liens granted under the loan
documents.
The Partnership, Quest Cherokee, Quest Energy GP and their
subsidiaries are required to make certain representations and
warranties that are customary for credit agreements of this
type. The Credit Agreement also contains affirmative and
negative covenants that are customary for credit agreements of
this type. The covenants in the Quest Agreement include, without
limitation, delivery of financial statements and other financial
information; notice of defaults and certain other matters;
payment of obligations; preservation of legal existence and good
standing; maintenance of assets and business; maintenance of
insurance; compliance with laws and contractual obligations;
maintenance of books and records; permit inspection rights; use
of proceeds; execution of guaranties by subsidiaries; perfecting
security interests in after-acquired property; curing title
defects; maintaining material leases; operation of properties;
notification of change of purchasers of production; maintenance
of fiscal year; limitations on liens; limitations on
investments; limitations on hedging agreements; limitations on
indebtedness; limitations on lease obligations; limitations on
fundamental changes; limitations on dispositions of assets;
F-20
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
limitations on restricted payments, distributions and
redemptions; limitations on nature of business, capital
expenditures and risk management; limitations on transactions
with affiliates; limitations on burdensome agreements; and
compliance with financial covenants.
The Credit Agreements financial covenants prohibit Quest
Cherokee, the Partnership and any of their subsidiaries from:
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|
|
permitting the ratio (calculated based on the most recently
delivered compliance certificate) of the Partnerships
consolidated current assets (including the unused amount of the
borrowing base, but excluding non-cash assets under
FAS 133) to consolidated current liabilities
(excluding non-cash obligations under FAS 133, asset and
asset retirement obligations and current maturities of
indebtedness under the Credit Agreement) at any fiscal
quarter-end, commencing with the quarter ended December 31,
2007, to be less than 1.0 to 1.0; provided, however, that
current assets and current liabilities will exclude
mark-to-market values of swap contracts, to the extent such
values are included in current assets and current liabilities;
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|
|
permitting the ratio (calculated on the most recently delivered
compliance certificate) of adjusted consolidated EBITDA to
consolidated interest charges at any fiscal quarter-end,
commencing with the quarter ended December 31, 2007, to be
less than 2.5 to 1.0 measured on a rolling four quarter basis;
provided that for the periods ending December 31, 2007,
March 31, 2008, June 30, 2008 and September 30,
2008, the calculations will be done on a pro forma
basis; and
|
|
|
|
permitting the ratio (calculated based on the most recently
delivered compliance certificate) of consolidated funded debt to
adjusted consolidated EBITDA at any fiscal quarter-end,
commencing with the quarter ended December 31, 2007, to be
greater than 3.5 to 1.0 measured on a rolling four quarter
basis; provided that for the periods ending December 31,
2007, March 31, 2008, June 30, 2008 and
September 30, 2008, the calculations will be done on a pro
forma basis.
|
Adjusted consolidated EBITDA is defined in the Credit Agreement
to mean the sum of (i) consolidated EBITDA plus
(ii) the distribution equivalent amount (for each fiscal
quarter of the Partnership, the amount of cash paid to the
members of Quest Energy GPs management group and
non-management directors with respect to restricted common
units, bonus units
and/or
phantom units of the Partnership that are required under GAAP to
be treated as compensation expense prior to vesting (and which,
upon vesting, are treated as limited partner distributions under
GAAP)).
Consolidated EBITDA is defined in the Credit Agreement to mean
for the Partnership and its subsidiaries on a consolidated
basis, an amount equal to the sum of (i) consolidated net
income, (ii) consolidated interest charges, (iii) the
amount of taxes, based on or measured by income, used or
included in the determination of such consolidated net income,
(iv) the amount of depreciation, depletion and amortization
expense deducted in determining such consolidated net income,
and (v) other non-cash charges and expenses, including,
without limitation, non-cash charges and expenses relating to
swap contracts or resulting from accounting convention changes,
of the Partnership and its subsidiaries on a consolidated basis,
all determined in accordance with GAAP.
Consolidated interests charges is defined to mean for the
Partnership and its subsidiaries on a consolidated basis, the
excess of (i) the sum of (a) all interest, premium
payments, fees, charges and related expenses of the Partnership
and its subsidiaries in connection with indebtedness (net of
interest rate swap contract settlements) (including capitalized
interest), in each case to the extent treated as interest in
accordance with GAAP, and (b) the portion of rent expense
of the Partnership and its subsidiaries with respect to such
period under capital leases that is treated as interest in
accordance with GAAP over (ii) all interest income for such
period.
Consolidated funded debt is defined to mean for the Partnership
and its subsidiaries on a consolidated basis, the sum of
(i) the outstanding principal amount of all obligations and
liabilities, whether current or long-term, for borrowed money
(including obligations under the Credit Agreement, but excluding
all reimbursement obligations relating to outstanding but
undrawn letters of credit), (ii) attributable indebtedness
pertaining to capital leases,
F-21
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
(iii) attributable indebtedness pertaining to synthetic
lease obligations, and (iv) without duplication, all
guaranty obligations with respect to indebtedness of the type
specified in subsections (i) through (iii) above.
Events of default under the Credit Agreement are customary for
transactions of this type and include, without limitation,
non-payment of principal when due, non-payment of interest, fees
and other amounts for a period of three business days after the
due date, failure to perform or observe covenants and agreements
(subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, certain acts of
bankruptcy or insolvency, cross defaults to other material
indebtedness, borrowing base deficiencies, and change of
control. Under the Credit Agreement, a change of control means
(i) QRC fails to own or to have voting control over at
least 51% of the equity interest of Quest Energy GP,
(ii) any person acquires beneficial ownership of 51% or
more of the equity interest in the Partnership; (iii) the
Partnership fails to own 100% of the equity interests in Quest
Cherokee, or (iv) QRC undergoes a change in control (the
acquisition by a person, or two or more persons acting in
concert, of beneficial ownership of 50% or more of QRCs
outstanding shares of voting stock, except for a merger with and
into another entity where the other entity is the survivor if
QRCs stockholders of record immediately preceding the
merger hold more than 50% of the outstanding shares of the
surviving entity).
Other
Long-Term Indebtedness
$708,000 of notes payable to banks and finance companies
were outstanding at December 31, 2007 and are secured by
equipment and vehicles, with payments due in monthly
installments through October 2013 with interest rates ranging
from 5.5% to 11.5% per annum.
Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc.,
Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream
Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc.
(now STP Cherokee, LLC) have been named Defendants in a
lawsuit filed by Plaintiffs, Eddie R. Hill,
et al
. in the
District Court for Craig County, Oklahoma (Case
No. CJ-2003-30).
Plaintiffs are royalty owners who are alleging underpayment of
royalties owed to them. Plaintiffs also allege, among other
things, that Defendants have engaged in self-dealing and
breached fiduciary duties owed to Plaintiffs, and that
Defendants have acted fraudulently toward the Plaintiffs.
Plaintiffs also allege that the gathering fees and related
charges should not be deducted in paying royalties.
Plaintiffs claims relate to a total of 84 wells
located in Oklahoma and Kansas. Plaintiffs are seeking
unspecified actual and punitive damages. Defendants intend to
defend vigorously against Plaintiffs claims.
STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem
Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service,
LLC (improperly named Quest Energy Services, LLC) have been
named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick
and Suzan M. Kirkpatrick in the District Court for Craig County
(Case
No. CJ-2005-143).
Plaintiffs allege that STP, Inc.,
et al.
, sold natural
gas from wells owned by the Plaintiffs without providing the
requisite notice to Plaintiffs. Plaintiffs further allege that
Defendants failed to include deductions on the check stubs of
Plaintiffs in violation of state law and that Defendants
deducted for items other than compression in violation of the
lease terms. Plaintiffs assert claims of actual and constructive
fraud and further seek an accounting stating that if Plaintiffs
have suffered any damages for failure to properly pay royalties,
Plaintiffs have a right to recover those damages. Plaintiffs
have not quantified their alleged damages. Discovery is ongoing
and Defendants intend to defend vigorously against
Plaintiffs claims.
Quest Cherokee Oilfield Services, LLC has been named in this
lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana
Jara De Trigoso in the District Court of Oklahoma County,
Oklahoma (Case
No. CJ-2007-11079).
Plaintiffs allege that Plaintiff Segundo Trigoso was injured
while working for Defendant on September 29, 2006 and that
such injuries were intentionally caused by Defendant. Plaintiffs
seek unspecified damages for physical injuries, emotional
injuries, loss of consortium and pain and suffering. Plaintiffs
also seek punitive damages. Defendant intends to defend
vigorously against Plaintiffs claims.
F-22
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Quest Cherokee and Bluestem were named as defendants in a
lawsuit (Case
No. 04-C-100-PA)
filed by plaintiff Central Natural Resources, Inc. on
September 1, 2004 in the District Court of Labette County,
Kansas. Central Natural Resources owns the coal underlying
numerous tracts of land in Labette County, Kansas. Quest
Cherokee has obtained oil and gas leases from the owners of the
oil, gas, and minerals other than coal underlying some of that
land and has drilled wells that produce coal bed methane gas on
that land. Bluestem purchases and gathers the gas produced by
Quest Cherokee. Plaintiff alleges that it is entitled to the
coal bed methane gas produced and revenues from these leases and
that Quest Cherokee is a trespasser. Plaintiff is seeking quiet
title and an equitable accounting for the revenues from the coal
bed methane gas produced. Plaintiff has alleged that Bluestem
converted the gas and seeks an accounting for all gas purchased
by Bluestem from the wells in issue. Quest Cherokee contends it
has valid leases with the owners of the coal bed methane gas
rights. The issue is whether the coal bed methane gas is owned
by the owner of the coal rights or by the owners of the gas
rights. If Quest Cherokee prevails on that issue, then the
plaintiffs claims against Bluestem fail. All issues
relating to ownership of the coal bed methane gas and damages
have been bifurcated. Cross motions for summary judgment on the
ownership of the coal bed methane were filed by Quest Cherokee
and the plaintiff, with summary judgment being awarded in Quest
Cherokees favor. The plaintiff has appealed the summary
judgment and that appeal is pending. Quest Cherokee intends to
defend vigorously against these claims.
Quest Cherokee was named as a defendant in a lawsuit (Case
No. CJ-06-07)
filed by plaintiff Central Natural Resources, Inc. on
January 17, 2006, in the District Court of Craig County,
Oklahoma. Bluestem is not a party to this lawsuit. Central
Natural Resources owns the coal underlying approximately
2,250 acres of land in Craig County, Oklahoma. Quest
Cherokee has obtained oil and gas leases from the owners of the
oil, gas, and minerals other than coal underlying those lands,
and has drilled and completed 20 wells that produce coal
bed methane gas on those lands. Plaintiff alleges that it is
entitled to the coal bed methane gas produced and revenues from
these leases and that Quest Cherokee is a trespasser. Plaintiff
seeks to quiet its alleged title to the coal bed methane and an
accounting of the revenues from the coal bed methane gas
produced by Quest Cherokee. Quest Cherokee contends it has valid
leases from the owners of the coal bed methane gas rights. The
issue is whether the coal bed methane gas is owned by the owner
of the coal rights or by the owners of the gas rights. Quest
Cherokee has answered the petition and discovery is ongoing.
Quest Cherokee intends to defend vigorously against these claims.
Quest Cherokee was named as a defendant in a lawsuit (Case
No. 05 CV 41) filed by Labette Energy, LLC in the
District Court of Labette County, Kansas. Plaintiff claims to
own a 3.2 mile gas gathering pipeline in Labette County,
Kansas, and that Quest Cherokee used that pipeline without
plaintiffs consent. Plaintiff also contends that the
defendants slandered its alleged title to that pipeline and
suffered damages from the cancellation of their proposed sale of
that pipeline. Plaintiff claims that they were damaged in the
amount of $202,375. Discovery in that case is ongoing and Quest
Cherokee intends to defend vigorously against the
plaintiffs claims.
Quest Cherokee is a counterclaim defendant in a lawsuit (Case
No. 2006 CV 74) filed by Quest Cherokee in District
Court of Labette County, Kansas. Quest Cherokee filed that
lawsuit seeking a declaratory judgment that several oil and gas
leases owned by Quest Cherokee are valid and in effect. In the
counterclaim, defendants allege that those leases have expired
by their terms and have been forfeited by Quest Cherokee.
Defendants seek a declaration that those leases are null and
void, statutory damages of $100, and their attorneys fees.
Discovery in that case is ongoing. Quest Cherokee intends to
vigorously defend against those counterclaims.
Quest Cherokee was named as a defendant in a class action
lawsuit (Case
No. 07-1225-MLB)
filed by several royalty owners in the U.S. District Court
for the District of Kansas. The case was filed by the named
plaintiffs on behalf of a putative class consisting of all Quest
Cherokees royalty and overriding royalty owners in the
Kansas portion of the Cherokee Basin. Plaintiffs contend that
Quest Cherokee failed to properly make royalty payments to them
and the putative class by, among other things, paying royalties
based on reduced volumes instead of volumes measured at the
wellheads, by allocating expenses in excess of the actual costs
of the services represented, by allocating production costs to
the royalty owners, by improperly allocating marketing costs to
the royalty owners, and by making the royalty payments after the
statutorily proscribed time for doing so without providing the
required
F-23
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
interest. Quest Cherokee has answered the complaint and denied
plaintiffs claims. Discovery in that case is ongoing.
Quest Cherokee intends to defend vigorously against these claims.
Quest Cherokee has been named as a defendant in several lawsuits
in which the plaintiff claims that an oil and gas lease owned
and operated by Quest Cherokee has either expired by their terms
or, for various reasons, have been forfeited by Quest Cherokee.
Those lawsuits are pending in the District Courts of Labette,
Montgomery, and Wilson Counties, Kansas. Quest Cherokee has
drilled wells on some of the oil and gas leases in issue and
some of those oil and gas leases do not have a well located
thereon but have been unitized with other oil and gas leases
upon which a well has been drilled. As of February 28,
2008, the total amount of acreage covered by the leases at issue
in these lawsuits was approximately 7,090 acres. Discovery
in those cases is ongoing. Quest Cherokee intends to vigorously
defend against those claims.
Quest Cherokee was named in an Order to Show Cause issued by the
Kansas Corporation Commission (the KCC) (KCC Docket
No. 07-CONS-155-CSHO)
filed on February 23, 2007. The KCC has ordered Quest
Cherokee to demonstrate why it should not be held responsible
for plugging 22 abandoned oil wells on a gas lease owned and
operated by Quest Cherokee in Wilson County, Kansas. Quest
Cherokee denies that it is legally responsible for plugging the
wells in issue and intends to vigorously defend against the
KCCs claims.
The Partnership, from time to time, may be subject to legal
proceedings and claims that arise in the ordinary course of its
business. Although no assurance can be given, management
believes, based on its experiences to date, that the ultimate
resolution of such items will not have a material adverse impact
on the Partnerships business, financial position or
results of operations. Like other natural gas and oil producers
and marketers, the Partnerships operations are subject to
extensive and rapidly changing federal and state environmental
regulations governing air emissions, wastewater discharges, and
solid and hazardous waste management activities. Therefore it is
extremely difficult to reasonably quantify future environmental
related expenditures.
The following information is provided regarding the estimated
fair value of the financial instruments, including derivative
assets and liabilities as defined by SFAS 133 that the
Partnership and the Predecessor held as of December 31,
2007 and 2006, respectively, and the methods and assumptions
used to estimate their fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(Dollars in thousands)
|
|
|
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps and caps
|
|
$
|
|
|
|
$
|
|
|
|
$
|
197
|
|
|
$
|
197
|
|
Basis swaps
|
|
$
|
281
|
|
|
$
|
281
|
|
|
$
|
62
|
|
|
$
|
62
|
|
Fixed-price natural gas swaps
|
|
$
|
2,742
|
|
|
$
|
2,742
|
|
|
$
|
2,207
|
|
|
$
|
2,207
|
|
Fixed-price natural gas collars
|
|
$
|
5,274
|
|
|
$
|
5,276
|
|
|
$
|
13,111
|
|
|
$
|
13,111
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
(856
|
)
|
|
$
|
(856
|
)
|
|
$
|
(377
|
)
|
|
$
|
(377
|
)
|
Fixed-price natural gas swaps
|
|
$
|
(5,586
|
)
|
|
$
|
(5,586
|
)
|
|
$
|
|
|
|
$
|
|
|
Fixed-price natural gas collars
|
|
$
|
(7,385
|
)
|
|
$
|
(7,386
|
)
|
|
$
|
(12,316
|
)
|
|
$
|
(12,316
|
)
|
Credit facilities
|
|
$
|
(94,000
|
)
|
|
$
|
(94,000
|
)
|
|
$
|
(225,000
|
)
|
|
$
|
(225,000
|
)
|
Other financing agreements
|
|
$
|
(708
|
)
|
|
$
|
(708
|
)
|
|
$
|
(569
|
)
|
|
$
|
(569
|
)
|
The carrying amount of cash, receivables, deposits, accounts
payable and accrued expenses approximates fair value due to the
short maturity of those instruments. The carrying amounts for
notes payable approximate fair value due to the variable nature
of the interest rates of the notes payable.
F-24
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
The fair value of all derivative instruments as of
December 31, 2007 and 2006 was based upon estimates
determined by the Partnerships counterparties and
subsequently evaluated internally using established index prices
and other sources. These values are based upon, among other
things, futures prices, volatility, and time to maturity and
credit risk. The values reported in the financial statements
change as these estimates are revised to reflect actual results,
changes in market conditions or other factors. See Note 7.
Derivatives.
Derivative assets and liabilities reflected as current in the
December 31, 2007 and 2006 balance sheets represent the
estimated fair value of fixed-price contract and interest rate
cap settlements scheduled to occur over the subsequent
twelve-month period based on market prices for natural gas and
fluctuations in interest rates as of the balance sheet date. The
offsetting increase in value of the hedged future production has
not been accrued in the accompanying balance sheet, creating the
appearance of a working capital deficit from these contracts.
The contract settlement amounts are not due and payable until
the monthly period that the related underlying hedged
transaction occurs. In some cases the recorded liability for
certain contracts significantly exceeds the total settlement
amounts that would be paid to a counterparty based on prices and
interest rates in effect at the balance sheet date due to option
time value. Since the Partnership expects to hold these
contracts to maturity, this time value component has no direct
relationship to actual future contract settlements and
consequently does not represent a liability that will be settled
in cash or realized in any way.
Natural
Gas Hedging Activities
The Partnership seeks to reduce its exposure to unfavorable
changes in natural gas prices, which are subject to significant
and often volatile fluctuation, through the use of fixed-price
contracts. The fixed-price contracts are comprised of energy
swaps and collars. These contracts allow the Partnership to
predict with greater certainty the effective natural gas prices
to be received for hedged production and benefit operating cash
flows and earnings when market prices are less than the fixed
prices provided in the contracts. However, the Partnership will
not benefit from market prices that are higher than the fixed
prices in the contracts for hedged production. Collar structures
provide for participation in price increases and decreases to
the extent of the ceiling and floor prices provided in those
contracts. For the years ended December 31, 2007, 2006 and
2005, fixed-price contracts hedged approximately 63.2%, 61.0%
and 89.0%, respectively, of the Partnerships natural gas
production. As of December 31, 2007, fixed-price contracts
were in place to hedge 32.5 Bcf of estimated future natural
gas production. Of this total volume, 9.4 Bcf are hedged
for 2008, 12.6 Bcf are hedged for 2009 and 10.5 Bcf
thereafter.
For energy swap contracts, the Partnership receives a fixed
price for the respective commodity and pays a floating market
price, as defined in each contract (generally a regional spot
market index or in some cases, NYMEX future prices), to the
counterparty. The fixed-price payment and the floating-price
payment are netted, resulting in a net amount due to or from the
counterparty. Natural gas collars contain a fixed floor price
(put) and ceiling price (call) (generally a regional spot market
index or in some cases, NYMEX future prices). If the market
price of natural gas exceeds the call strike price or falls
below the put strike price, then the Partnership receives the
fixed price and pays the market price. If the market price of
natural gas is between the call and the put strike price, then
no payments are due from either party.
F-25
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
The following table summarizes the estimated volumes, fixed
prices, fixed-price sales and fair value attributable to the
fixed-price contracts as of December 31, 2007. See
Market Risk.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Year Ending
|
|
|
Year Ending
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Total
|
|
|
|
(In thousands, except MMBtu data)
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
2,332,000
|
|
|
|
12,629,000
|
|
|
|
10,499,000
|
|
|
|
25,460,000
|
|
Weighted-average fixed price per MMBtu(1)
|
|
$
|
7.35
|
|
|
$
|
7.70
|
|
|
$
|
7.31
|
|
|
$
|
7.51
|
|
Fixed-price sales
|
|
$
|
17,141
|
|
|
$
|
97,202
|
|
|
$
|
76,779
|
|
|
$
|
191,122
|
|
Fair value, net
|
|
$
|
600
|
|
|
$
|
199
|
|
|
$
|
(4,217
|
)
|
|
$
|
(3,418
|
)
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
7,028,000
|
|
|
|
|
|
|
|
|
|
|
|
7,028,000
|
|
Ceiling
|
|
|
7,028,000
|
|
|
|
|
|
|
|
|
|
|
|
7,028,000
|
|
Weighted-average fixed price per MMBtu(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$
|
6.54
|
|
|
|
|
|
|
|
|
|
|
$
|
6.54
|
|
Ceiling
|
|
$
|
7.54
|
|
|
|
|
|
|
|
|
|
|
$
|
7.54
|
|
Fixed-price sales(2)
|
|
$
|
45,973
|
|
|
|
|
|
|
|
|
|
|
$
|
45,973
|
|
Fair value, net
|
|
$
|
(2,112
|
)
|
|
|
|
|
|
|
|
|
|
$
|
(2,112
|
)
|
Total Natural Gas Contracts:(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
9,360,000
|
|
|
|
12,629,000
|
|
|
|
10,499,000
|
|
|
|
32,488,000
|
|
Weighted-average fixed price per MMBtu(1)
|
|
$
|
6.74
|
|
|
$
|
7.70
|
|
|
$
|
7.31
|
|
|
$
|
7.30
|
|
Fixed-price sales(2)
|
|
$
|
63,114
|
|
|
$
|
97,202
|
|
|
$
|
76,779
|
|
|
$
|
237,095
|
|
Fair value, net
|
|
$
|
(1,512
|
)
|
|
$
|
199
|
|
|
$
|
(4,217
|
)
|
|
$
|
(5,530
|
)
|
|
|
|
(1)
|
|
The prices to be realized for hedged production are expected to
vary from the prices shown due to basis.
|
|
(2)
|
|
Assumes floor prices for gas collar volumes.
|
|
(3)
|
|
Does not include basis swaps with notional volumes by year, as
follows: 2008: 6,276,000 MMBtu.
|
The estimates of fair value of the fixed-price contracts are
computed based on the difference between the prices provided by
the fixed-price contracts and forward market prices as of the
specified date, as adjusted for basis. Forward market prices for
natural gas are dependent upon supply and demand factors in such
forward market and are subject to significant volatility. The
fair value estimates shown above are subject to change as
forward market prices and basis change. See Note 6.
Financial Instruments.
All fixed-price contracts have been approved by the board of
directors of the Predecessor or Quest Energy GP, as appropriate.
The differential between the fixed price and the floating price
for each contract settlement period multiplied by the associated
contract volume is the contract profit or loss. For fixed-price
contracts qualifying as cash flow hedges pursuant to
SFAS 133, the realized contract profit or loss is included
in oil and gas sales in the period for which the underlying
production was hedged. For the years ended December 31,
2007, 2006 and 2005, oil and gas sales included
$6.9 million, $7.9 million and $27.9 million,
respectively, of net losses associated with realized losses
under fixed-price contracts.
For fixed-price contracts qualifying as cash flow hedges,
changes in fair value for volumes not yet settled are shown as
adjustments to other comprehensive income. For those contracts
not qualifying as cash flow hedges, changes in fair value for
volumes not yet settled are recognized in change in derivative
fair value in the statement of operations. The fair value of all
fixed-price contracts are recorded as assets or liabilities in
the balance sheet.
F-26
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Based upon market prices at December 31, 2007, the
estimated amount of unrealized gains for fixed-price contracts
shown as adjustments to other comprehensive income that are
expected to be reclassified into earnings as actual contract
cash settlements are realized within the next 12 months is
$1.7 million.
Interest
Rate Hedging Activities
The Predecessor entered into interest rate caps designed to
hedge the interest rate exposure associated with borrowings
under its credit facilities. All interest rate caps were
approved by the Predecessors board of directors. The
excess, if any, of the floating rate over the interest rate cap
multiplied by the notional amount is the cap gain. This gain is
included in interest expense in the period for which the
interest rate exposure was hedged.
For interest rate caps qualifying as cash flow hedges, changes
in fair value of the derivative instruments are shown as
adjustments to other comprehensive income. For those interest
rate caps not qualifying as cash flow hedges, changes in fair
value of the derivative instruments are recognized in change in
derivative fair value in the statement of operations. All
changes in fair value of the Predecessors interest rate
swaps and caps are reported in results of operations rather than
in other comprehensive income because the critical terms of the
interest rate swaps and caps do not comply with certain
requirements set forth in SFAS 133. The fair value of all
interest rate swaps and caps are recorded as assets or
liabilities in the balance sheet. As of December 31, 2007,
the Partnership did not have interest rate hedging activities.
The last of the Predecessors interest rate cap agreements
expired September 2007.
Change
in Derivative Fair Value
Change in derivative fair value in the statements of operations
for the years ended December 31, 2007, 2006 and 2005 is
comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Change in fair value of derivatives not qualifying as cash flow
hedges
|
|
$
|
(6,308
|
)
|
|
$
|
(2,713
|
)
|
|
$
|
12,233
|
|
|
$
|
879
|
|
Amortization of derivative fair value gains and losses
recognized in earnings prior to actual cash settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103
|
|
Settlements due to ineffective cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(10,234
|
)
|
|
|
|
|
Ineffective portion of derivatives qualifying as cash flow hedges
|
|
|
226
|
|
|
|
2,293
|
|
|
|
4,411
|
|
|
|
(5,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(6,082
|
)
|
|
$
|
(420
|
)
|
|
$
|
6,410
|
|
|
$
|
(4,668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amounts recorded in change in derivative fair value do not
represent cash gains or losses. Rather, they are temporary
valuation swings in the fair value of the contracts. All amounts
initially recorded in this caption are ultimately reversed
within this same caption over the respective contract terms.
Credit
Risk
Energy swaps and collars and interest rate swaps and caps
provide for a net settlement due to or from the respective party
as discussed previously. The counterparties to the derivative
contracts are a financial institution and a major energy
corporation. Should a counterparty default on a contract, there
can be no assurance that we would be able to enter into a new
contract with a third party on terms comparable to the original
contract. The Partnership has not experienced non-performance by
its counterparties.
F-27
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Cancellation or termination of a fixed-price contract would
subject a greater portion of the Partnerships natural gas
production to market prices, which, in a low price environment,
could have an adverse effect on its future operating results.
Cancellation or termination of an interest rate swap or cap
would subject a greater portion of the Partnerships
long-term debt to market interest rates, which, in an
inflationary environment, could have an adverse effect on its
future net income. In addition, the associated carrying value of
the derivative contract would be removed from the balance sheet.
Market
Risk
The differential between the floating price paid under each
energy swap or collar contract and the price received at the
wellhead for our production is termed basis and is
the result of differences in location, quality, contract terms,
timing and other variables. For instance, some of our fixed
price contracts are tied to commodity prices on the New York
Mercantile Exchange (NYMEX), that is, we receive the
fixed price amount stated in the contract and pay to our
counterparty the current market price for gas as listed on the
NYMEX. However, due to the geographic location of our natural
gas assets and the cost of transporting the natural gas to
another market, the amount that we receive when we actually sell
our natural gas is based on the Southern Star Central TX/KS/OK
(Southern Star) first of month index, with a small
portion being sold based on the daily price on the Southern Star
index. The difference between natural gas prices on the NYMEX
and the price actually received by the Partnership is referred
to as a basis differential. Typically, the price for natural gas
on the Southern Star first of the month index is less than the
price on the NYMEX due to the more limited demand for natural
gas on the Southern Star first of the month index. Recently, the
basis differential has been increasingly volatile and has on
occasion resulted in us receiving a net price for our natural
gas that is significantly below the price stated in the fixed
price contract.
The effective price realizations that result from the
fixed-price contracts are affected by movements in this basis
differential. Basis movements can result from a number of
variables, including regional supply and demand factors, changes
in the portfolio of the Partnerships fixed-price contracts
and the composition of its producing property base. Basis
movements are generally considerably less than the price
movements affecting the underlying commodity, but their effect
can be significant. Recently, the basis differential has been
increasingly volatile and has on occasion resulted in the
Partnership receiving a net price for its natural gas that is
significantly below the price stated in the fixed price contract.
Changes in future gains and losses to be realized in natural gas
and oil sales upon cash settlements of fixed-price contracts as
a result of changes in market prices for natural gas are
expected to be offset by changes in the price received for
hedged natural gas production.
F-28
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
|
|
8.
|
Asset
Retirement Obligation
|
If a reasonable estimate of the fair value of an obligation to
perform site reclamation, dismantle facilities or plug and
abandon wells can be made, we record an asset retirement
obligations, or ARO, and capitalize the asset retirement cost in
oil and natural gas properties in the period in which the
retirement obligation is incurred. After recording these
amounts, the ARO is accreted to its future estimated value using
an assumed cost of funds and the additional capitalized costs
are depreciated on a unit-of-production basis. The changes in
the aggregate asset retirement obligations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
2007
|
|
|
2007
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Asset retirement obligation beginning balance
|
|
$
|
1,658
|
|
|
$
|
1,410
|
|
|
$
|
1,150
|
|
Liabilities incurred
|
|
|
26
|
|
|
|
152
|
|
|
|
175
|
|
Liabilities settled
|
|
|
(1
|
)
|
|
|
(6
|
)
|
|
|
(7
|
)
|
Accretion expense
|
|
|
17
|
|
|
|
102
|
|
|
|
92
|
|
Revisions in estimated cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation ending balance
|
|
$
|
1,700
|
|
|
$
|
1,658
|
|
|
$
|
1,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnerships natural gas and oil production is sold
under contracts with various purchasers. Natural gas sales to
two purchasers (ONEOK and Tenaska) accounted for 79% and 21%,
respectively, of total natural gas revenues for the year ended
December 31, 2007. For the period from November 15,
2007 through December 31, 2007, the Partnership sold
approximately 100% of its natural gas to ONEOK. Natural gas
sales to one purchaser approximated 95% of total natural gas and
oil revenues for the years ended December 31, 2006 and 2005.
Issuance
of Units
Effective November 15, 2007, the Partnership completed its
initial public offering of 9.1 million common units at a
price of $18.00 per unit. Total proceeds from the sale of the
common units in the initial public offering were
$163.8 million, before underwriting discounts, a
structuring fee and offering costs, of approximately
$10.6 million, $0.4 million and $1.5 million,
respectively. At the closing of the initial public offering, QRC
transferred its ownership interest in Quest Cherokee, LLC (which
owned all of the Predecessors Cherokee Basin gas and oil
leases) and Quest Cherokee Oilfield Service, LLC (which owned
all of the Cherokee Basin field equipment and vehicles) in
exchange for 3,201,521 common units and 8,857,981 subordinated
units and a 2% general partner interest.
Common
Units
During the subordination period, the common units will have the
right to receive distributions of available cash from operating
surplus each quarter in an amount equal to $0.40 per common unit
plus any arrearages in the payment of the minimum quarterly
distribution on the common units from prior quarters, before any
distributions of available cash from operating surplus may be
made on the subordinated units. The purpose of the subordinated
units is to increase the likelihood that during the
subordination period there will be available cash to be
distributed on the common units.
F-29
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
The subordination period will extend until the first day of any
quarter beginning after December 31, 2012 that each of the
following tests are met:
|
|
|
|
|
distributions of available cash from operating surplus on each
of the outstanding common units and subordinated units equaled
or exceeded the minimum quarterly distribution for each of the
three consecutive, non-overlapping four quarter periods
immediately preceding that date;
|
|
|
|
the adjusted operating surplus (as defined in the
Partnerships partnership agreement) generated during each
of the three consecutive, non-overlapping four quarter periods
immediately preceding that date equaled or exceeded the sum of
the minimum quarterly distributions on all of the outstanding
common and subordinated units during those periods on a fully
diluted basis during those periods; and
|
|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
If the unitholders remove Quest Energy GP other than for cause
and units held by it and its affiliates are not voted in favor
of such removal:
|
|
|
|
|
the subordination period will end and each subordinated unit
will immediately convert into one common unit;
|
|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
Quest Energy GP will have the right to convert its 2% general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests.
|
The common units have limited voting rights as set forth in the
Partnerships partnership agreement.
Pursuant to the partnership agreement, if at any time Quest
Energy GP and its affiliates own more than 80% of the common
units outstanding, Quest Energy GP has the right, but not the
obligation, to call or acquire all, but not less
than all, of the common units held by unaffiliated persons at a
price not less than their then current market value. Quest
Energy GP may assign this call right to any of its affiliates or
to the Partnership.
Subordinated
Units
During the subordination period, the subordinated units have no
right to receive distributions of available cash from operating
surplus until the common units receive distributions of
available cash from operating surplus in an amount equal to the
minimum quarterly distribution of $0.40 per quarter, plus any
arrearages in the payment of the minimum quarterly distribution
on the common units from prior quarters. No arrearages will be
paid to subordinated units.
The subordinated units may convert to common units on a
one-for-one basis when certain conditions as set forth in our
partnership agreement are met. The Partnerships
partnership agreement also sets forth the calculation to be used
to determine the amount and priority of cash distributions that
the common unitholders, subordinated unitholders and Quest
Energy GP will receive.
The subordinated units have limited voting rights as set forth
in the Partnerships partnership agreement.
General
Partner Interest
Quest Energy GP owns a 2% interest in the Partnership. This
interest entitles it to receive distributions of available cash
from operating surplus as discussed further below under Cash
Distributions. The Partnerships partnership agreement sets
forth the calculation to be used to determine the amount and
priority of cash distributions that the common unitholders,
subordinated unitholders and general partner will receive.
The general partner units have the management rights as set
forth in the Partnerships partnership agreement.
F-30
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Allocations
of Net Income
Net income is allocated between Quest Energy GP and the common
and subordinated unitholders in accordance with the provisions
of the Partnerships partnership agreement. Net income is
generally allocated first to Quest Energy GP and the common and
subordinated unitholders in an amount equal to the net losses
allocated to Quest Energy GP and the common and subordinated
unitholders in the current and prior tax years under the
partnership agreement. The remaining net income is allocated to
Quest Energy GP and the common and subordinated unitholders in
accordance with their respective percentage interests of the
general partner units, common units and subordinated units.
Cash
Distributions
The Partnership intends to continue to make regular cash
distributions to unitholders on a quarterly basis, although
there is no assurance as to the future cash distributions since
they are dependent upon future earnings, cash flows, capital
requirements, financial condition and other factors. The
Partnerships credit facility prohibits it from making cash
distributions if any potential default or event of default, as
defined in the credit facility, occurs or would result from the
cash distribution.
Within 45 days after the end of each quarter, the
Partnership will distribute all of its available cash (as
defined in the partnership agreement) to Quest Energy GP and
unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of
the quarter; less the amount of cash reserves established by
Quest Energy GP to provide for the proper conduct of our
business, to comply with applicable law, any of our debt
instruments, or other agreements or to provide funds for
distributions to unitholders and to Quest Energy GP for any one
or more of the next four quarters; plus all cash on hand on the
date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of
the quarter. Working capital borrowings are generally borrowings
that are made under the credit facility and in all cases are
used solely for working capital purposes or to pay distributions
to partners.
The Partnerships partnership agreement requires that the
Partnership make distributions of available cash from operating
surplus for any quarter during the subordination period in the
following manner:
|
|
|
|
|
second
, 98% to the holders of subordinated units and 2%
to Quest Energy GP, until each subordinated unit has received a
minimum quarterly distribution of $0.40;
|
|
|
|
third
, 98% to all unitholders, pro rata, and 2% to Quest
Energy GP, until each unit has received a distribution of $0.46;
|
|
|
|
fourth
, 85% to all unitholders, pro rata, and 15% to
Quest Energy GP, until each unit has received a distribution of
$0.50; and
|
|
|
|
thereafter
, 75% to all unitholders, pro rata, and 25% to
Quest Energy GP.
|
Quest Energy GP is entitled to incentive distributions if the
amount the Partnership distributes with respect to one quarter
exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Quarterly
|
|
Marginal Percentage Interest in Distributions
|
|
|
|
Distributions
|
|
Limited
|
|
|
General
|
|
|
|
Target Amount
|
|
Partner
|
|
|
Partner
|
|
|
Minimum quarterly distribution
|
|
$0.40
|
|
|
98
|
%
|
|
|
2
|
%
|
First target distribution
|
|
Up to $0.46
|
|
|
98
|
%
|
|
|
2
|
%
|
Second target distribution
|
|
Above $0.46, up to $0.50
|
|
|
85
|
%
|
|
|
15
|
%
|
Thereafter
|
|
Above $0.50
|
|
|
75
|
%
|
|
|
25
|
%
|
F-31
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
On January 21, 2008, the board of directors of Quest Energy
GP declared a cash distribution of $0.2043 for the fourth
quarter of 2007. The distribution was based on an initial
quarterly distribution of $0.40 per unit, prorated for the
period from and including November 15, 2007 through
December 31, 2007. The distribution was paid on
February 14, 2008 to unitholders of record as of the close
of business on February 7, 2008. The aggregate amount of
the distribution was $4.4 million.
|
|
11.
|
Net
Income Per Limited Partner Unit
|
The computation of net income per limited partner unit is based
on the weighted average number of common and subordinated units
outstanding during the year. Basic and diluted net income per
limited partner unit is determined by dividing net income, after
deducting the amount allocated to the general partner interest
(including its incentive distribution in excess of its 2%
interest), by the weighted average number of outstanding limited
partner units during the period in accordance with
EITF 03-06.
Other
Comprehensive Income (Loss)
The components of other comprehensive income (loss) and related
tax effects for the period from November 15, 2007 through
December 31, 2007 and the predecessor period from
January 1, 2007 through November 14, 2007 and for the
years ended December 31, 2006 and 2005 are shown as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Tax Effect
|
|
|
Net of Tax
|
|
|
|
(Dollars in thousands)
|
|
|
Successor:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period from November 15, 2007 through
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
$
|
7,524
|
|
|
$
|
|
|
|
$
|
7,524
|
|
Predecessor:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period from January 1, 2007 through
November 14, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
$
|
(9,437
|
)
|
|
$
|
|
|
|
$
|
(9,437
|
)
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
$
|
47,599
|
|
|
$
|
|
|
|
$
|
47,599
|
|
Year Ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
$
|
(36,028
|
)
|
|
$
|
|
|
|
$
|
(36,028
|
)
|
Comprehensive
Income
Statement of Financial Accounting Standards No. 130,
Accounting for Comprehensive Income, requires that
enterprises report a total for comprehensive income. The
difference between the Partnerships net income and the
Partnerships comprehensive income resulted from unrealized
gains or losses on derivatives utilized for hedging the
Partnerships exposure to fluctuating expected future cash
flows produced by price or interest rate risk.
Cumulative revenues, expenses, gains and losses that under
generally accepted accounting principals are included within our
comprehensive income but excluded from our earnings are reported
as accumulated other comprehensive income/(loss) within
Partners Capital in the Partnerships consolidated
balance sheets.
F-32
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Change in derivative fair value in the statements of operations
for the period from November 15, 2007 through
December 31, 2007 and the Predecessor period from
January 1, 2007 through November 14, 2007 and for the
years ended December 31, 2006 and 2005 are shown as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Change in fair value of derivatives not qualifying as cash flow
hedges
|
|
$
|
(6,308
|
)
|
|
$
|
(2,713
|
)
|
|
$
|
12,233
|
|
|
$
|
879
|
|
Amortization of derivative fair value gains and losses
recognized in earnings prior to actual cash settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103
|
|
Settlements due to ineffective cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(10,234
|
)
|
|
|
|
|
Ineffective portion of derivatives qualifying as cash flow hedges
|
|
|
226
|
|
|
|
2,293
|
|
|
|
4,411
|
|
|
|
(5,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(6,082
|
)
|
|
$
|
(420
|
)
|
|
$
|
6,410
|
|
|
$
|
(4,668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
|
Related
Party Transactions
|
The Partnership entered into a management services agreement
with Quest Energy Service, LLC (a wholly-owned subsidiary of
QRC), which carries out the directions of Quest Energy GP.
Pursuant to this agreement, Quest Energy Service provides the
Partnership with legal, accounting, finance, tax, property
management, engineering, risk management and acquisition
services in respect of potential opportunities for the
Partnership to acquire long-lived, stable and proved gas and oil
reserves. Quest Energy Service is reimbursed for its reasonable
costs in providing services to the Partnership and is entitled
to be reimbursed for all direct and indirect expenses incurred
on the Partnerships behalf. For a description of the
services that Quest Energy Service provides to the Partnership
and the Partnerships obligation to reimburse Quest Energy
Service for the costs it incurs in providing those services,
please read Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Management Services Agreement
under Item 13 of this report.
Prior to the formation of Quest Midstream in December 2006, a
wholly-owned subsidiary of QRC provided the Predecessor with gas
gathering, treating, dehydration and compression services
pursuant to a gas transportation agreement that was entered into
in December 2003. Since these services were being provided by
one wholly owned subsidiary of QRC to another wholly-owned
subsidiary, no amendments were made to this prior contract to
reflect increases in the costs of providing these services. As
part of the formation of Quest Midstream, QRC and Quest
Midstream entered into the midstream services agreement, which
provided for negotiated fees for these services that were
significantly higher than those that had been previously paid.
Under the midstream services agreement, Quest Midstream
initially paid $0.50 per MMBtu of gas for gathering, dehydration
and treating services and $1.10 per MMBtu of gas for compression
services. These fees are subject to annual adjustment based on
changes in gas prices and the producer price index. Such fees
will never be reduced below these initial rates and are subject
to renegotiation upon the exercise of each five-year extension
period. Under the terms of some of the Partnerships gas
leases, it may not be able to charge the full amount of these
fees to royalty owners, which would increase the average fees
per MMBtu that the Partnership effectively pays under the
midstream services agreement. For 2008, the fees will be $0.51
per MMBtu of gas for gathering, dehydration and treating
services and $1.13 per MMBtu of gas for compression services.
F-33
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
In addition, Quest Midstream agreed to install the saltwater
disposal lines for the Partnerships gas wells connected to
Quest Midstreams gathering system for a fee of $1.25 per
linear foot and connect such lines to the Partnerships
saltwater disposal wells for a fee of $1,000 per well, subject
to an annual adjustment based on changes in the Employment Cost
Index for Natural Resources, Construction, and Maintenance. For
2008, the fees will be $1.29 per linear foot to install
saltwater disposal lines and $1,030 per well to connect such
lines to the Partnerships saltwater disposal wells.
|
|
13.
|
Supplemental
Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Cash paid for interest
|
|
$
|
4,756
|
|
|
$
|
23,828
|
|
|
$
|
20,418
|
|
|
$
|
10,315
|
|
Cash paid for income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Supplementary
Information:
During the year ended December 31, 2007, non-cash investing
and financing activities were as follows:
1) Issued common units in the Partnership for approximately
$163 million, before expenses.
2) Distributions for the Partnership of $1.9 million
were accrued.
During the year ended December 31, 2006, non-cash investing
and financing activities were as follows:
1) QRC issued stock to its 401(k) plan valued at $607,000
as an employer contribution.
During the year ended December 31, 2005, non-cash investing
and financing activities were as follows:
1) QRC issued stock to its 401(k) plan valued at $495,000
as an employer contribution.
|
|
14.
|
Employee
Benefit Plan With Related Party
|
QRC has adopted a 401(k) profit sharing plan with an effective
date of June 1, 2001. The plan covers all eligible
employees. During the years ended December 31, 2007, 2006
and 2005, employees contributed $864,000, $490,880 and $298,937,
respectively, to the plan and QRC matched the contributions with
cash contributions of $566,000, $372,000, and $350,000,
respectively. QRC contributed 192,753, 51,131 and
49,842 shares of its common stock to the plan. QRC valued
the 2007, 2006 and 2005 common stock contribution at $1,445,647,
$607,000 and $495,000, respectively, of which $709,000, $179,000
and $229,000, respectively, was included in oil and gas
properties. There is a graduated vesting schedule with the
employee becoming fully vested after six years of service.
15. SFAS 69
Supplemental Disclosures (Unaudited)
Net
Capitalized Costs
The Partnerships and the Predecessors aggregate
capitalized costs related to natural gas and oil producing
activities are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Natural gas and oil properties and related lease equipment:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
406,661
|
|
|
$
|
316,783
|
|
Unproved
|
|
|
19,328
|
|
|
|
9,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,989
|
|
|
|
326,228
|
|
Accumulated depreciation, depletion and impairment
|
|
|
(127,968
|
)
|
|
|
(92,733
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
298,021
|
|
|
$
|
233,495
|
|
|
|
|
|
|
|
|
|
|
F-34
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Unproved properties not subject to amortization consisted mainly
of leasehold acquired through acquisitions. The Partnership will
continue to evaluate its unproved properties; however, the
timing of the ultimate evaluation and disposition of the
properties has not been determined.
Costs
Incurred
Costs incurred in natural gas and oil property acquisition,
exploration and development activities that have been
capitalized are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Acquisition of properties proved and unproved
|
|
$
|
|
|
|
$
|
|
|
Development costs
|
|
|
103,076
|
|
|
|
106,021
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
103,076
|
|
|
$
|
106,021
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations for Natural Gas and Oil Producing
Activities
The Partnerships and the Predecessors results of
operations from natural gas and oil producing activities are
presented below for the years ended December 31, 2007, 2006
and 2005. The following table includes revenues and expenses
associated directly with the Partnerships natural gas and
oil producing activities. It does not include any interest costs
and general and administrative costs and, therefore, is not
necessarily indicative of the contribution to consolidated net
operating results of the Partnerships and the
Predecessors natural gas and oil operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
November 15
|
|
|
January 1
|
|
|
|
|
|
|
|
|
|
Through
|
|
|
Through
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
November 14,
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Production revenues
|
|
$
|
15,842
|
|
|
$
|
97,193
|
|
|
$
|
65,551
|
|
|
$
|
44,565
|
|
Production costs
|
|
|
(3,579
|
)
|
|
|
(24,416
|
)
|
|
|
(21,208
|
)
|
|
|
(14,388
|
)
|
Depreciation and depletion
|
|
|
(5,046
|
)
|
|
|
(30,672
|
)
|
|
|
(25,521
|
)
|
|
|
(20,121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,217
|
|
|
|
42,105
|
|
|
|
18,822
|
|
|
|
10,056
|
|
Imputed income tax provision(1)
|
|
|
(2,887
|
)
|
|
|
(16,842
|
)
|
|
|
(7,642
|
)
|
|
|
(3,817
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations for natural gas/oil producing activity
|
|
$
|
4,330
|
|
|
$
|
25,263
|
|
|
$
|
11,180
|
|
|
$
|
6,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The imputed income tax provision is hypothetical (at the
statutory rate) and determined without regard to the
Partnerships deduction for general and administrative
expenses, interest costs and other income tax credits and
deductions, nor whether the hypothetical tax provision will be
payable.
|
F-35
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Natural
Gas and Oil Reserve Quantities
The following schedule contains estimates of proved natural gas
and oil reserves attributable to the Partnership and the
Predecessor. Proved reserves are estimated quantities of natural
gas and oil that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Proved developed reserves are those that are
expected to be recovered through existing wells with existing
equipment and operating methods. Reserves are stated in thousand
cubic feet (mcf) of natural gas and barrels (bbl) of oil.
Geological and engineering estimates of proved natural gas and
oil reserves at one point in time are highly interpretive,
inherently imprecise and subject to ongoing revisions that may
be substantial in amount. Although every reasonable effort is
made to ensure that the reserve estimates are accurate, by their
nature reserve estimates are generally less precise than other
estimates presented in connection with financial statement
disclosures.
|
|
|
|
|
|
|
|
|
|
|
Gas mcf
|
|
|
Oil bbls
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
134,319,300
|
|
|
|
32,269
|
|
Purchase of
reserves-in-place
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
87,002,842
|
|
|
|
|
|
Revisions of previous estimates(1)
|
|
|
(11,000,000
|
)
|
|
|
9,740
|
|
Production
|
|
|
(12,282,142
|
)
|
|
|
(9,737
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
198,040,000
|
|
|
|
32,272
|
|
Purchase of
reserves-in-place
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
26,368,000
|
|
|
|
|
|
Revisions of previous estimates(2)
|
|
|
3,663,000
|
|
|
|
10,807
|
|
Production
|
|
|
(17,148,000
|
)
|
|
|
(6,523
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
210,923,000
|
|
|
|
36,556
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
71,638,250
|
|
|
|
32,269
|
|
Balance, December 31, 2006
|
|
|
122,390,000
|
|
|
|
32,272
|
|
Balance, December 31, 2007
|
|
|
140,966,000
|
|
|
|
36,556
|
|
|
|
|
(1)
|
|
Lower natural gas prices reduced the economic lives of the
underlying natural gas properties and thereby decreased the
estimated future reserves. Higher oil prices increased the
economic lives of the underlying oil properties and thereby
increased the estimated future reserves.
|
|
(2)
|
|
During 2007, higher prices increased the economic lives of the
underlying oil and natural gas properties and thereby increased
the estimated future reserves.
|
F-36
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
Standardized
Measure of Discounted Future Net Cash Flows
The following schedule presents the standardized measure of
estimated discounted future net cash flows from the
Partnerships and the Predecessors proved reserves as
of December 31, 2007, 2006 and 2005. Estimated future cash
flows are based on independent reserve data. Because the
standardized measure of future net cash flows was prepared using
the prevailing economic conditions existing at December 31,
2007, 2006 and 2005, it should be emphasized that such
conditions continually change. Accordingly, such information
should not serve as a basis in making any judgment on the
potential value of the Partnerships and the
Predecessors recoverable reserves or in estimating future
results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Future production revenues(1)
|
|
$
|
1,351,979
|
|
|
$
|
1,197,198
|
|
|
$
|
1,258,579
|
|
Future production costs
|
|
|
(732,486
|
)
|
|
|
(638,844
|
)
|
|
|
(366,474
|
)
|
Future development costs
|
|
|
(119,448
|
)
|
|
|
(126,272
|
)
|
|
|
(122,428
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
500,045
|
|
|
|
432,082
|
|
|
|
769,677
|
|
Effect of discounting future annual cash flows at 10%
|
|
|
(177,508
|
)
|
|
|
(164,010
|
)
|
|
|
(287,132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted net cash flows before hedges
|
|
$
|
322,537
|
|
|
$
|
268,072
|
|
|
$
|
482,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The weighted average natural gas and oil wellhead prices used in
computing the Partnerships and the Predecessors
reserves were $6.21 per mcf and $92.01 per bbl at
December 31, 2007; $6.00 per mcf and $58.06 per bbl at
December 31, 2006; and $9.22 per mcf and $55.69 per bbl at
December 31, 2005.
|
The principal changes in the standardized measure of discounted
future net cash flows relating to proven natural gas and oil
properties were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Sales and transfers of natural gas and oil, net of production
costs
|
|
$
|
(56,499
|
)
|
|
$
|
(25,796
|
)
|
|
$
|
(25,646
|
)
|
Net changes in prices and production costs
|
|
|
23,665
|
|
|
|
(457,808
|
)
|
|
|
171,468
|
|
Acquisitions of natural gas and oil in place less
related production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries, less related production costs
|
|
|
63,057
|
|
|
|
241,621
|
|
|
|
|
|
Revisions of previous quantity estimates less related production
costs
|
|
|
8,915
|
|
|
|
(30,424
|
)
|
|
|
(51,760
|
)(1)
|
Accretion of discount
|
|
|
15,327
|
|
|
|
57,934
|
|
|
|
8,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in standardized measure of discounted future net
cash flows
|
|
$
|
54,465
|
|
|
$
|
(214,473
|
)
|
|
$
|
102,894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes $30.1 million related to increase in future
development costs.
|
F-37
QUEST
ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED/CARVE OUT FINANCIAL
STATEMENTS (Continued)
The following schedule contains a comparison of the standardized
measure of discounted future net cash flows to the net carrying
value of proved natural gas and oil properties at
December 31, 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Standardized measure of discounted future net cash flows, before
hedges
|
|
$
|
322,537
|
|
|
$
|
268,072
|
|
|
$
|
482,545
|
|
Proved natural gas & oil property, net of accumulated
depletion
|
|
|
278,697
|
|
|
|
224,048
|
|
|
|
165,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows in
excess of net carrying value of proved natural gas &
oil properties
|
|
$
|
43,840
|
|
|
$
|
44,024
|
|
|
$
|
317,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership purchased certain oil producing properties in
Seminole County, Oklahoma from a private company for
$9.5 million in a transaction that closed in early February
2008. The Partnership reduced its land budget for 2008 in a
similar amount to retain its total capital budget unchanged. The
properties have estimated proved reserves of
712,000 barrels, all of which are proved developed
producing. In addition, the Partnership entered into crude oil
swaps for approximately 80% of the estimated production from the
propertys proved developed producing reserves at WTI-NYMEX
prices per barrel of oil of approximately $96.00 in 2008, $90.00
in 2009, and $87.50 for 2010. The acquisition was financed with
borrowings under the Partnerships credit facility.
F-38
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial
Disclosure.
|
None.
|
|
Item 9A(T).
|
Controls
and
Procedures.
|
Evaluation
of Disclosure Controls and Procedures.
We have established and maintain a system of disclosure controls
and procedures to provide reasonable assurances that information
required to be disclosed by us in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified in the SECs
rules and forms. Based on the evaluation of our disclosure
controls and procedures as of the end of the period covered by
this report, the principal executive officer and principal
financial officer of our general partner have concluded that our
disclosure controls and procedures as of December 31, 2007
were effective, at a reasonable assurance level, in ensuring
that the information required to be disclosed by us in reports
filed under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified in the rules and
forms of the SEC.
Internal
Controls Over Financial Reporting.
This annual report does not include a report of
managements assessment regarding internal control over
financial reporting or an attestation report of our registered
public accounting firm due to a transition period established by
rules of the SEC for newly public companies.
Changes
in Internal Controls.
There have not been any changes in our internal controls over
financial reporting that occurred during the quarterly period
ended December 31, 2007 that has materially affected, or is
reasonably likely to materially affect, our internal controls
over financial reporting.
|
|
Item 9B.
|
Other
Information.
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate
Governance.
|
Management
As is the case with many publicly traded partnerships, we do not
directly have officers, directors or employees. Our operations
and activities are managed by our general partner, Quest Energy
GP, LLC, which is wholly owned by our Parent. Quest Energy GP
has a board of directors that oversees its management,
operations and activities. We refer to the board of directors of
Quest Energy GP as the board of directors of our general
partner.
Our general partner manages our operations and activities on our
behalf. We have entered into a management services agreement
with Quest Energy Service, LLC, a wholly-owned subsidiary of our
Parent, pursuant to which Quest Energy Service provides us with
legal, accounting, finance, tax, property management,
engineering, risk management and acquisition services in respect
of opportunities for us to acquire long-lived, stable and proved
gas and oil reserves. The management services agreement provides
that employees of Quest Energy Service (including the persons
who are executive officers of our general partner) will devote
such portion of their time as may be needed to conduct our
business and affairs.
Our general partner is not elected by our unitholders and will
not be subject to re-election on a regular basis in the future.
Unitholders will not be entitled to elect the directors of our
general partner or directly or indirectly participate in our
management or operation. As owner of our general partner, our
Parent will have the ability to elect all the members of the
board of directors of our general partner. Our general partner
owes a fiduciary duty to our unitholders, although our
partnership agreement limits such duties and restricts the
remedies available to
76
unitholders for actions taken by our general partner that might
otherwise constitute breaches of fiduciary duties. Our general
partner will be liable, as general partner, for all of our debts
(to the extent not paid from our assets), except for
indebtedness or other obligations that are made expressly
nonrecourse to it. Our general partner therefore may cause us to
incur indebtedness or other obligations that are nonrecourse to
it. Whenever possible, our general partner intends to cause us
to incur indebtedness or other obligations that are nonrecourse
to it.
Directors
and Executive Officers
The following table shows information regarding the current
directors and executive officers of our general partner.
Directors are elected for one-year terms by our Parent, the
owner of our general partner.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Jerry D. Cash(1)
|
|
|
46
|
|
|
Chairman of the Board, Chief Executive Officer, Director
|
David E. Grose
|
|
|
55
|
|
|
Chief Financial Officer
|
David Lawler
|
|
|
40
|
|
|
Chief Operating Officer and Director
|
David Bolton
|
|
|
39
|
|
|
Executive Vice President Land
|
Steve Hochstein
|
|
|
50
|
|
|
Executive Vice President Exploration/A&D
|
Richard Marlin
|
|
|
55
|
|
|
Executive Vice President Engineering
|
Gary Pittman(2)
|
|
|
44
|
|
|
Director
|
Mark Stansberry(2)
|
|
|
52
|
|
|
Director
|
|
|
|
(1)
|
|
Member of the audit committee.
|
|
(2)
|
|
Member of the audit committee, nominating committee and the
conflicts committee.
|
Our general partners directors hold office until the
earlier of their death, resignation, removal or disqualification
or until their successors have been elected. Officers serve at
the discretion of the board of directors. There are no family
relationships among any of our directors or executive officers.
Jerry D. Cash
serves as the Chairman of the Board of
Directors and Chief Executive Officer of our general partner.
Mr. Cash is Chief Executive Officer and a Director of our
Parent. Mr. Cash has been active in the gas and oil
exploration and development business for over 25 years.
Mr. Cash has been the Chairman of the Board of our Parent
since November 2002, when our Parent acquired STP Cherokee, Inc.
Mr. Cash has been Chief Executive Officer since September
2004. From November 2002 until September 2004, he was Co-Chief
Executive Officer of our Parent. From November 2002 until June
2004, he was Chief Financial Officer of our Parent. In 1987,
Mr. Cash formed STP, Inc. and as President directed that
company in the identification and realization of numerous oil,
gas and CBM exploration projects. In November 2002,
Mr. Cash transferred substantially all of the assets of
STP, Inc. to STP Cherokee and sold STP Cherokee to our Parent in
November 2002. From 1980 to 1986, Mr. Cash worked for
Bodard & Hale Drilling Company while pursuing a
petroleum engineering degree at Oklahoma State University and
the University of Oklahoma. During this period, Mr. Cash
drilled several hundred wells throughout Oklahoma. A long-time
resident of Oklahoma, Mr. Cash maintains an active role in
several charitable organizations.
David E. Grose
serves as the Chief Financial Officer of
our general partner. Mr. Grose is Chief Financial Officer
of our Parent, and has held that position since June 2004.
Mr. Grose has 25 years of financial experience,
primarily in the exploration, production, and drilling sectors
of the gas and oil industry. Mr. Grose also has significant
knowledge and expertise in capital development and in the
acquisition of oil & gas companies. From January 2004
to June 2004, Mr. Grose was Chief Financial Officer for
Avalon Corrections, Inc., a corrections company. From June 2002
until December 2003, Mr. Grose was Chief Financial Officer
for Oxley Petroleum Company. From April 1999 to December 2001,
Mr. Grose was Chief Financial Officer for a
telecommunications company. From July 1997 to April 1999,
Mr. Grose was Chief Financial Officer for Bayard Drilling
Technologies, Inc. Prior to that, Mr. Grose was employed by
Alexander Energy Corporation from March 1980 to February 1997,
in various positions, most recently as Chief Financial Officer.
Mr. Grose earned a B.A. in Political Science from Oklahoma
State University in 1974 and an MBA from the University of
Central Oklahoma in 1977.
77
David Lawler
serves as a Director and the Chief Operating
Officer of our general partner. Mr. Lawler has served as
Chief Operating Officer of our Parent since May 2007.
Mr. Lawler has worked in the oil and gas industry for more
than 16 years in various management and engineering
positions including production, drilling, project management and
facilities. Prior to joining our Parent, Mr. Lawler was
employed by Shell Exploration & Production Company
from May 1997 to May 2007 and in his most recent assignment,
served as Engineering and Operations Manager for multiple assets
along the U.S. Gulf Coast from January 2005 to May 2007.
These assets included Shells prolific gas producing assets
located in South Texas as well as offshore sour gas production
facilities near Mobile Bay, Alabama and the Yellowhammer Sulfur
Recovery Plan located in Coden, Alabama. Prior to his role as
Operations Manager, Mr. Lawler progressed through technical
and leadership assignments at Shell, including Executive
Support/Staff Business Analyst (March 2003 to December
2004) and drilling engineering team leader (May 1997 to
February 2003). Prior to joining Shell, Mr. Lawler was
employed by Conoco, Inc. and Burlington Resources in various
domestic engineering and operations positions. Mr. Lawler
graduated from the Colorado School of Mines in 1990 with a
bachelors of science degree in petroleum engineering and
earned his Masters in Business Administration from Tulane
University in 2003.
David Bolton
serves as Executive Vice
President Land of our general partner.
Mr. Bolton has served as Executive Vice
President Land of our Parent since May 2006. Prior
to that, Mr. Bolton was a Land Manager for Continental Land
Resources LLC, an Oklahoma based gas and oil lease broker from
May 2004 to May 2006. Prior to that, Mr. Bolton was a
landman for Continental Land Resources from April 2001 to May
2004. Mr. Bolton was an independent landman from 1995 to
April 2001. Mr. Bolton is a Certified Professional Landman
with over 17 years of experience in various aspects of the
gas and oil industry, and has worked extensively throughout
Oklahoma, Texas, and Kansas. Mr. Bolton holds a Bachelor of
Liberal Studies degree from the University of Oklahoma, attended
the Oklahoma City University School of Law, and is a member of
American Association of Petroleum Landmen, Oklahoma City
Association of Petroleum Landmen, the American Bar Association,
and the Energy Bar Association.
Steve Hochstein
serves as Executive Vice
President Exploration/A&D of our general
partner. Mr. Hochstein joined our Parent in January of 2006
as Manager of New Ventures. He then served as Executive Vice
President Exploration/A&D from March 2007 to
November 2007 and has served as Executive Vice
President Exploration and Resource Development of
our Parent since December 2007. While serving as Manager of New
Ventures, Mr. Hochstein led resource assessment efforts for
several acquisition projects and was responsible for generating
two new resource plays for our Parent. In his new role,
Mr. Hochstein will continue to develop new opportunities
for our Parent and oversee all geologic and reservoir
engineering functions. Before joining our Parent,
Mr. Hochstein served for two years as a partner in Rockport
Energy, a small E&P company. Prior to that,
Mr. Hochstein worked for El Paso Corporation in its
coalbed methane division, serving as technical manager (January
2001 to August 2001), Director of Coalbed Methane (August 2001
to February 2003) and Vice President of CBM/Mid Continent
and Rockies (February 2003 to April 2004). Prior to that,
Mr. Hochstein worked for Sonat Exploration Co. from August
1981 to January 2001 in various positions, most recently as
Manager of Geoscience. Mr. Hochstein has more than
25 years of industry experience and more than 10 years
of unconventional resource experience. Mr. Hochstein holds
a Bachelor of Science in Geologic Sciences from the University
of Texas, Austin, and is a member of the American Association of
Petroleum Geologists.
Richard Marlin
serves as Executive Vice
President Engineering of our general partner.
Mr. Marlin has served as Executive Vice
President Engineering of our Parent since September
2004. Mr. Marlin also was our Parents Chief
Operations Officer from February 2005 through July 2006.
Mr. Marlin was our Parents engineering manager from
November 2002 to September 2004. Prior to that, Mr. Marlin
was the engineering manager for STP from 1999 until STPs
acquisition by our Parent in November 2002. Prior to that,
Mr. Marlin was employed by Parker and Parsley Petroleum as
the Mid-Continent Operations Manager for 12 years.
Mr. Marlin has more than 32 years industry experience
involving all phases of drilling and production in more than
14 states. His experience also involved primary and
secondary operations along with the design and oversight of
gathering systems that move as much as
175 MMcf/d.
Mr. Marlin is a registered Professional Engineer holding
licenses in Oklahoma and Colorado. Mr. Marlin earned a B.S.
in Industrial Engineering and Management from Oklahoma State
University in 1974. Mr. Marlin was a Director of the
Mid-Continent Coal Bed Methane Forum.
78
Gary Pittman
has been a director of our general partner
since November 2007. Mr. Pittman is currently an active
private investor with his own investment company, G.
Pittman & Company, of which he has been president for
the past 15 years, who began his career in private equity
and investment banking. From 1987 to 1995, Mr. Pittman was
Vice President of The Energy Recovery Fund, a $180 million
private equity fund focused on the energy industry.
Mr. Pittman has served as a director of various oil and
natural gas companies, including Flotek Industries, Inc., a
specialty chemical oil service company; Geokinetics, Inc., a
seismic acquisition and processing company; Czar Resources, Ltd,
a Canadian E&P company; and Sub Sea International, an
offshore robotics and diving company. He owned and operated an
oil and gas production and gas gathering company in Montana from
1992 to 1998. Mr. Pittman currently chairs the compensation
committee and serves on the audit committee for Flotek, and
chairs the compensation committee and serves on the audit and
governance committees for Geokinetics. Mr. Pittman holds a
B.A. degree in Economics/Business from Wheaton College and an
MBA from Georgetown University.
Mark Stansberry
has been a director of our general
partner since November 2007. Mr. Stansberry currently
serves as the Chairman and a director of The GTD Group, which
owns and invests in companies including those specializing in
energy consulting and management, environmental, governmental
relations, international trade development and commercial
construction. He has served as Chairman of The GTD Group since
1998. Currently, he serves as Chairman of The Governors
International Team and State Chambers Energy Council in
Oklahoma. He also serves on a number of other boards, including
the Board of Directors of People to People International, and
serves as President of the International Society of The Energy
Advocates. Mr. Stansberry has testified before the
U.S. Senate Energy and Natural Resources Committee and is
the author of the book: The Braking Point: Americas Energy
Dreams and Global Economic Realities. Mr. Stansberry is a
1977 Bachelors of Arts graduate from Oklahoma Christian
University, a graduate of the Fund for American
Studies/Georgetown University, and a graduate of the
Intermediate School of Banking, Oklahoma State University.
Committees
of the Board of Directors
The board of directors of our general partner has established an
audit committee, a nominating committee and a conflicts
committee. There currently are no other committees of the board
of directors of our general partner. Because we are a limited
partnership, the listing standards of the NASDAQ do not require
that we or our general partner have a majority of independent
directors or a nominating or compensation committee of the board
of directors. We are, however, required to have an audit
committee, all of whose members are required to be
independent under NASDAQ standards as described
below, subject to certain transition rules for the first year
following the closing of our initial public offering.
Audit Committee.
The audit committee is
comprised of Gary Pittman, Mark Stansberry and Jerry Cash. The
board of directors of our general partner has determined that
Messrs. Pittman and Stansberry meet the independence
standards, and that each member of the audit committee meets the
experience standards, established by the NASDAQ Global Market
and SEC rules. In addition, the board of directors of our
general partner has determined that Mr. Pittman meets the
SECs definition of an audit committee financial
expert based on his business and experience and background
described above under Directors and Executive
Officers.
The audit committee assists the board of directors in its
oversight of the integrity of our financial statements and our
compliance with legal and regulatory requirements and
partnership policies and controls. The audit committee has the
sole authority to retain and terminate our independent
registered public accounting firm, to approve all auditing
services and related fees and the terms thereof, and to
pre-approve any non-audit services to be rendered by our
independent registered public accounting firm. The audit
committee also is responsible for confirming the independence
and objectivity of our independent registered public accounting
firm. Our independent registered public accounting firm will be
given unrestricted access to the audit committee. The charter
for the audit committee is posted under the
Investors Corporate Governance section
of our website at www.qelp.net
Conflicts Committee.
The board of directors of
our general partner has established a conflicts committee. The
conflicts committee will review specific matters that the board
of directors believes may involve conflicts of interest. At the
request of the board of directors of our general partner, the
conflicts committee will determine if the resolution of the
conflict of interest is fair and reasonable to us (in light of
the totality of the relationships between
79
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us). The members of
the conflicts committee may not be officers or employees of our
general partner or directors, officers or employees of its
affiliates, including our Parent, and must meet the independence
and experience standards established by the NASDAQ Global Market
and SEC rules for service on an audit committee of a board of
directors, and certain other requirements. Each member of the
conflicts committee meets these standards. Any matters approved
by the conflicts committee in good faith will be conclusively
deemed to be fair and reasonable to us, approved by all of our
partners and not a breach by our general partner of any duties
it may owe us or our unitholders.
Unitholder
Communications and Other Information
Unitholders who wish to communicate with the board of directors
of our general partner or any of the directors may do so by mail
in care of Investor Relations at Quest Energy Partners, L.P.,
210 Park Avenue, Suite 2750, Oklahoma City, OK 73102. Such
communications should specify the intended recipient or
recipients. All such communications will be compiled and
submitted to the board or the individual director, as
applicable, on a periodic basis. Commercial solicitations or
communications will not be forwarded.
Our partnership agreement provides that our general partner will
manage and operate us and that, unlike holders of common stock
in a corporation, unitholders have only limited voting rights on
matters affecting our business or governance. Accordingly, we do
not hold annual meetings of unitholders.
Reimbursement
of Expenses of Our General Partner
Our general partner will not receive any management fee or other
compensation for its management of our partnership. However, our
partnership agreement requires us to reimburse our general
partner for all actual direct and indirect expenses it incurs or
actual payments it makes on our behalf and all other expenses
allocable to us or otherwise incurred by our general partner in
connection with operating our business including overhead
allocated to our general partner by its affiliates, including
our Parent. These expenses include salary, bonus, incentive
compensation and other amounts paid to persons who perform
services for us or on our behalf and expenses allocated to our
general partner by its affiliates. We do not expect to incur any
additional fees or to make other payments to these entities in
connection with operating our business. Our general partner is
entitled to determine in good faith the expenses that are
allocable to us. There is no limit on the amount of expenses for
which our general partner and its affiliates may be reimbursed.
We expect that we will reimburse our Parent for at least a
majority of the compensation and benefits paid to the executive
officers of our general partner. In addition, we have entered
into a management services agreement with Quest Energy Service
pursuant to which Quest Energy Service operates our assets and
performs other administrative services for us such as
accounting, corporate development, finance, land, legal and
engineering. We will reimburse Quest Energy Services for its
costs in performing these services, plus related expenses. For
the period from November 15, 2007 to December 31,
2007, we reimbursed our Parent and Quest Energy Service for a
total of $1.8 million in costs and expenses.
Compliance
with Section 16(a) of the Exchange Act
Section 16(a) of the Exchange Act requires executive
officers and directors of our general partner and persons who
beneficially own more than 10% of a class of our equity
securities registered pursuant to Section 12 of the
Exchange Act to file certain reports with the SEC and the NASDAQ
concerning their beneficial ownership of such securities.
Based solely on a review of the copies of reports on
Forms 3, 4 and 5 and amendments thereto furnished to us and
written representations from the executive officers and
directors of our general partner, we believe that during the
period beginning November 7, 2007 and ending
December 31, 2007, the officer and directors of our general
partner and beneficial owners of more than 10% of our equity
securities registered pursuant to Section 12 were in
compliance with the applicable requirements of
Section 16(a), except for our Parent not timely reporting
its acquisition of 3,201,521 common units and 8,857,981
subordinated units.
80
Code of
Ethics
The corporate governance of our general partner is, in effect,
the corporate governance of our partnership, subject in all
cases to any specific unitholder rights contained in our
partnership agreement.
Our general partner has adopted a code of business conduct and
ethics that applies to all officers, directors and employees of
our general partner and its affiliates. A copy of our code of
business conduct is available on our website at qelp.net. Any
substantive amendment to, or waiver from, a provision of our
code of business conduct that applies to our principal executive
officer, principal financial officer, principal accounting
officer, controller, or persons performing similar functions
will be disclosed in a report on
Form 8-K.
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Item 11.
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Executive
Compensation.
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Compensation
Discussion and Analysis
We do not directly employ any of the persons responsible for
managing our business, and we do not have a compensation
committee. Quest Energy GP, our general partner, manages our
operations and activities, and its board of directors and
officers makes decisions on our behalf. The compensation of the
directors and officers of our general partner and of Quest
Energy Services employees that perform services on our
behalf is determined by the Compensation Committee of, and paid
for by, our Parent. The officers and employees of our general
partner may participate in employee benefit plans and
arrangements sponsored by our Parent. Our general partner has
not entered into any employment agreements with any of its
officers.
The Named Executive Officers listed on page 88
(the Named Executive Officers) of our general
partner also serve as executive officers of our Parent, and the
compensation of the Named Executive Officers discussed below
reflects total compensation for services to all of our
Parents affiliates. We reimburse all expenses incurred on
our behalf, including the costs of employee, officer and
director compensation and benefits, as well as all other
expenses necessary or appropriate to the conduct of our
business, pursuant to our Parents allocation methodology
and subject to the terms of the management services agreement
and the omnibus agreement.
Based on the information that we track regarding the amount of
time spent by each of the Named Executive Officers on business
matters relating to us, we estimate that such officers devoted
the following percentage of their time to our business and to
our Parent and its other affiliates, respectively, for 2007:
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Percentage of Time Devoted
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Percentage of Time
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to Business of Our Parent
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Name
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Devoted to Our Business
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and Its Other Affiliates
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Jerry D. Cash
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72
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%
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28
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%
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David E. Grose
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67
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%
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33
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%
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David Lawler
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45
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%
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55
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%
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Richard Marlin
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45
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%
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55
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%
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David Bolton
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58
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%
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42
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%
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Our
Parents Compensation Philosophy
Our Parents compensation philosophy is to manage Named
Executive Officer total compensation at the median level
(50th percentile) relative to companies with which we
compete for talent (which are primarily the peer group
companies). The Compensation Committee of our Parents
Board of Directors (the Committee) compares
compensation levels with a selected cross-industry group of
other natural gas and oil exploration and production companies
of similar size to establish a competitive compensation package.
All compensation determinations are discretionary and, as noted
above, subject to our Parents decision-making authority.
Our
Parents Compensation Methodology
Our Parent has the ultimate decision-making authority with
respect to the total compensation of the Named Executive
Officers. The elements of compensation discussed below, and our
Parents decisions with respect to the levels of such
compensation, is not subject to approval by the board of
directors of our general partner, including the
81
audit and conflicts committees thereof. Awards under our
long-term incentive plan are made by the board of directors of
our general partner or a committee thereof. For 2007, the
decisions regarding the compensation packages of the Named
Executive Officers were made prior to our formation. As a
result, the members of our general partners board of
directors were not able to provide any input to the Committee.
With respect to future compensation decisions, our general
partners board of directors intends to provide input and
suggestions to the Committee.
Role
of the Compensation Committee
The Committee is responsible for reviewing and approving all
aspects of compensation for the Named Executive Officers. In
meeting this responsibility, the Committees policy is to
ensure that Named Executive Officer compensation complies with
all applicable rules and regulations and is designed to achieve
three primary objectives:
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attract and retain well-qualified executives who will lead our
Parent and us and achieve superior performance;
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tie annual incentives to achievement of specific, measurable
short-term corporate goals; and
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align the interests of management with those of the
equityholders to encourage achievement of increases in
equityholder value.
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The Committee retained the independent compensation consulting
firm of Towers Perrin (T-P) in February 2007 to:
(i) assist the Committee in formulating our Parents
compensation policies for 2007 and future years;
(ii) provide advice to the Committee concerning specific
compensation packages and appropriate levels of compensation of
our Parents named executive officers and directors;
(iii) provide advice about competitive levels of
compensation and marketplace trends in the oil and gas industry;
and (iv) review and recommend changes in our Parents
compensation system and programs. As described below, T-P
compiled competitive salary data for thirteen peer group
companies and assisted the Committee in its benchmarking
efforts, among other things. T-P met with members of our
Parents management and had a conference call with the
Committee in order to gather information about our Parent and
its business.
Role
of Management in Compensation Process
Each year the Committee asks the Chief Executive Officer and
Chief Financial Officer to present a proposed compensation plan
for the fiscal year beginning January 1 and ending December 31
(each, a Plan Year), along with supporting and
competitive market data. For 2007, T-P assisted our
Parents management in providing this competitive market
data, primarily through published salary surveys. The
compensation amounts presented to the Committee for the 2007
Plan Year were determined based upon the Chief Executive
Officers negotiations with our Parents named
executive officers (taking into account the T-P competitive
data). The Committee then met with the Chief Executive Officer
to review the proposal and establish the compensation plan, with
members of T-P participating by telephone.
The Committee monitors the performance of the Named Executive
Officers throughout the Plan Year against the targets set for
each performance measure. At the end of the Plan Year, the
Committee meets with the Chief Executive Officer and Chief
Financial Officer to review the final results compared to the
established performance goals before determining the Named
Executive Officers compensation levels for the Plan Year.
During this meeting, the Committee also establishes the Named
Executive Officer compensation plan for the upcoming Plan Year,
based on the Chief Executive Officers recommendations. In
general, the plan must be established within the first
90 days of a Plan Year.
In addition, during 2007, our Parent hired a number of new
executive officers, including David Lawler who was one of the
Named Executive Officers for 2007. The compensation packages for
these new executive officers were negotiated between the Chief
Executive Officer and the executive officers (taking into
account the T-P competitive data). The Committee then met with
the Chief Executive Officer to review and approve the proposed
compensation packages.
82
Performance
Peer Group
In 2007, the Committee retained T-P as its independent
compensation consultant to advise the Committee on matters
related to our Parents overall compensation program. To
assist the Committee in its benchmarking efforts, T-P provided a
compensation analysis and survey data for a peer group of
companies that are similar in scale and scope to our Parent.
With the assistance of T-P, the Committee selected a peer group
consisting of the following thirteen publicly traded
U.S. exploration and production companies: ATP
Oil & Gas Corp., Brigham Exploration, Carrizo
Oil & Gas Inc., Edge Petroleum, Gastar Exploration,
GMX Resources, Goodrich Petroleum, Linn Energy, McMoRan
Exploration, Parallel Petroleum, Toreador Resources Corp. and
Warren Resources. In general, peer group companies were
U.S. energy companies in the exploration and production
sector which had annual revenues ranging from $30 million
to $175 million.
Elements
of our Parents Executive Compensation
Program
Our Parents compensation program for the Named Executive
Officers consists of the following components:
Base Salary:
Base salaries for the Named
Executive Officers are established base on their scope of
responsibilities, taking into account competitive market
compensation paid by other companies in our Parents peer
group. The Committee considers the median salary range for each
Named Executive Officers counterpart, but makes
adjustments to reflect differences in job descriptions and scope
of responsibilities for each Named Executive Officer and to
reflect the Committees philosophy that each Named
Executive Officers total compensation should be at the
median level (50th percentile) relative to our
Parents peer group. The Committee annually reviews base
salaries for the Named Executive Officers and makes adjustments
from time to time to realign their salaries, after taking into
account individual performance, responsibilities, experience,
autonomy, strategic perspectives and marketability, as well as
the recommendations of the Chief Executive Officer.
As part of the Committees review of our Parents
compensation policies during the first quarter of 2007, the
Committee determined, in consultation with T-P, that the base
salaries for the Named Executive Officers were below the median
levels for our Parents peer group. As a result, the base
salaries of the Named Executive Officers were significantly
increased.
Management Annual Incentive Plan:
In 2006, the
Committee established the Quest Resource Corporation Management
Annual Incentive Plan, which we refer to as the Bonus
Plan. The Bonus Plan is intended to recognize value
creation by providing competitive incentives for meeting and
exceeding annual financial and operating performance measurement
targets. By providing market-competitive bonus awards, the
Committee believes the Bonus Plan supports the attraction and
retention of the Named Executive Officer talent critical to
achieving our Parents strategic business objectives. The
Bonus Plan puts a significant portion of total compensation at
risk by linking potential annual compensation to our
Parents achievement of specific performance goals during
the year, which creates a direct connection between the
executives pay and our Parents financial performance.
The awards under the Bonus Plan were paid in a combination of
stock and cash for 2006. For 2007, awards under the Bonus Plan
were payable solely in cash. The Committee anticipates that
future annual bonus awards will also be paid only in the form of
cash awards. The Committee made this change because of the roll
out of our Parents long-term equity incentive plan
described below.
Each year the Committee will establish goals during the first
quarter of the calendar year. The 2007 performance goals for the
Bonus Plan are described below. The amount of the bonus payable
to each participant varies based on the percentage of the
performance goals achieved and the employees position.
More senior ranking management personnel are entitled to bonuses
that are potentially a higher percentage of their base salaries,
reflecting the Committees philosophy that higher ranking
employees should have a greater percentage of their overall
compensation at risk.
Each executive officer and key employee that participates in the
Bonus Plan has a target bonus percentage expressed as a
percentage of base salary based on his or her level of
responsibility. The performance criteria for 2007 includes
minimum performance thresholds required to earn any incentive
compensation, as well as maximum payouts geared towards
rewarding extraordinary performance, thus, actual awards can
range from 0% (if performance is below 60% of target) to 100% of
base salary for the most senior executives (if performance is
150% of
83
target). For 2007, the potential bonus amounts for each of
Messrs. Cash, Grose, and Lawler were as follows: if our
Parent achieved an average of its financial goals of 60%, their
incentive awards would be 22% of base salary. If our Parent
achieved an average of its financial goals of 100%, their
incentive awards would be 42% of base salary. If our Parent
achieved an average of its financial goals of 150%, their
incentive awards would be 99% of base salary. For 2007, the
potential bonus amounts for each of the other Named Executive
Officers were as follows: if our Parent achieved an average of
its financial goals of 60%, their incentive awards would be 7%
of base salary. If our Parent achieved an average of its
financial goals of 100%, their incentive awards would be 27% of
base salary. If our Parent achieved an average of its financial
goals of 150%, their incentive awards would be 73.5% of base
salary.
After the end of the Plan Year, the Committee determines to what
extent our Parent and the participants have achieved the
performance measurement goals. The Committee calculates and
certifies in writing the amount of each participants bonus
based upon the actual achievements and computation formulae set
forth in the Bonus Plan. The Committee has no discretion to
increase the amount of any Named Executive Officers bonus
as so determined, but may reduce the amount of or totally
eliminate such bonus, if it determines, in its absolute and sole
discretion that such reduction or elimination is appropriate in
order to reflect the Named Executive Officers performance
or unanticipated factors. The performance period
(Incentive Period) with respect to which target
awards and bonuses may be payable under the Bonus Plan will
generally be the fiscal year beginning on January 1 and ending
on December 31, but the Committee has the authority to
designate different Incentive Periods.
Bonus Plan 2007 Performance Goals.
The
Committee increased the 2007 performance targets for the Bonus
Plan from the 2006 levels. The Committee eliminated
pipeline operating expense as a performance measure
in 2007, because the midstream pipeline operations were dropped
into Quest Midstream Partners in December 2006. The Committee
established the 2007 performance targets and percentages of
goals achieved for each of the five corporate financial goals
described below:
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Percentage of Goal Achieved
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50%
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100%
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150%
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Performance Measure
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EBITDA (earnings before interest, taxes, depreciation and
amortization)
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$
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34,000,000
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$
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54,000,000
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$
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74,000,000
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Lease operating expense (excluding gross production taxes and ad
valorem taxes)
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$
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1.31/Mcf
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$
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1.23/Mcf
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$
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1.15/Mcf
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Finding and development cost
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$
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1.67/Mcf
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$
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1.50/Mcf
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$
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1.33/Mcf
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Year end proved reserves
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193.5 Bcfe
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215 Bcfe
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236.5 Bcfe
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Production
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16.2 Bcfe
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18.0 Bcfe
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19.8 Bcfe
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Each of the five corporate financial goals were equally
weighted. The amount of the incentive bonus varies depending
upon the average percentage of the financial goals achieved. For
amounts between 50% and 100% and between 100% and 150%, linear
interpolation is used to determine the Percentage of Goal
Achieved. For amounts below 50%, the Percentage of
Goal Achieved is determined using the same scale as
between 50% and 100%. For amounts in excess of 150%, the
Percentage of Goal Achieved is determined using the
same scale as between 100% and 150%. For 2007, no incentive
awards were payable under the Bonus Plan if the average
percentage of the financial goals achieved was less than 60%.
Additionally, no additional incentive awards were payable if the
average percentage of the financial goals achieved exceeds 150%.
For 2007, the average percentage of the financial goals achieved
under the Bonus Plan was 100%.
Mr. Lawler commenced employment as our general
partners chief operating officer in April 2007, and
Mr. Lawler received a pro rata portion equal to
approximately 73% of the bonus for 2007.
Productivity Gain Sharing Payments:
A one-time
cash payment equal to 10% of an individuals monthly base
salary is earned during each month that our Parents CBM
production rate increases by 1,000 Mcf/day over the prior
record. All employees of our Parent are eligible to receive
productivity gain sharing payments. The purpose of these
payments is to incentivize all employees, including the Named
Executive Officers, to continually and immediately focus on
production. The Named Executive Officers received payments equal
to approximately 1.6 additional months of base salary as a
result of this plan, as follows: Jerry Cash $69,167;
David Grose
84
$46,458; David Lawler $26,583; David
Bolton $31,875; and Richard Marlin
$35,113. Our Parents management believes this incentive
plan is unique to it and is not used by the peer group
companies. As a result, the Committee believes these
productivity payments help our Parent attract and retain
talented and highly motivated Named Executive Officers.
Discretionary Bonus Plan:
At the discretion of
the Committee, cash bonuses or deferred compensation plan
contributions may be paid to an executive officer. The purposes
of such bonuses are to recognize a unique circumstance or
performance beyond a contemplated level. The Committee evaluates
such awards within the context of our Parents overall
performance. The determination of the type and amount of each
discretionary bonus is based upon the recommendation of the
Chief Executive Officer, as well as the individual performance
and contribution of the executive officer to our Parents
performance.
Equity
Awards
The Committee believes that the long-term performance of our
Parents executive officers is achieved through ownership
of stock-based awards, such as stock options, which expose
executive officers to the risks of downside stock prices and
provide an incentive for executive officers to build shareholder
value.
Omnibus Stock Award Plan.
Our Parents
2005 Omnibus Stock Award Plan (the Omnibus Plan)
provides for grants of non-qualified stock options, restricted
shares, bonus shares, deferred shares, stock appreciation
rights, performance units and performance shares. On
February 5, 2008, our Parents Board of Directors
approved an amendment to the Omnibus Plan to increase the total
number of shares that may be issued under the Omnibus Plan from
2,200,000 to 5,000,000, subject to stockholder approval. The
Omnibus Plan also permits the grant of incentive stock options.
The objectives of the Omnibus Plan are to strengthen key
employees and non-employee directors commitment to
the success of our Parent, to stimulate key employees and
non-employee directors efforts on its behalf and to help
our Parent attract new employees with the education, skills and
experience we need and retain existing key employees. All of our
Parents equity awards consisting of its common stock are
issued under the Omnibus Plan.
Our Parents Long-Term Incentive
Plan.
For 2007, the Committee added a new
long-term incentive plan for the executive officers of our
Parent under the Omnibus Plan. The new plan is intended to
encourage participants to focus on long-term performance of our
Parent and provide an opportunity for the executive officers to
increase their stake in us our Parent through grants of
restricted stock pursuant to the terms of the Omnibus Plan. The
Committee designed the long-term incentive plan to:
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enhance the link between the creation of stockholder value and
long-term incentive compensation;
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provide an opportunity for increased equity ownership by
executive officers; and
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maintain a competitive level of total compensation.
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The Committee determined the level of awards based on market
data provided by T-P and the recommendations of the Chief
Executive Officer (which in some cases were based on
negotiations with the Named Executive Officers). Award levels
vary among participants based on their position within our
Parent. The awards are subject to the terms of an Award
Agreement which outlines a vesting schedule (at the conclusion
of each year of service, one-third of the award amount vests
with the entire award vested at the end of three years) which is
expected to help retain the Named Executive Officers as any
unvested awards are forfeited if that individual terminates his
employment without good reason. There are no additional
performance criteria that must be met in order for the award to
be earned. The vesting schedule for the awards accelerates if a
Named Executive Officer is terminated without cause by our
Parent or for good reason by the executive officer.
Our Long-Term Incentive Plan.
On
November 14, 2007, our general partner adopted the Quest
Energy Partners, L.P. Long-Term Incentive Plan (the
Plan) for employees, consultants and directors of
our general partner and any of its affiliates who perform
services for us. The Plan consists of the following securities:
options, restricted units, phantom units, unit appreciation
rights, distribution equivalent rights, other unit-based awards
and unit awards. The purpose of awards under the Plan is to
provide additional incentive compensation to employees providing
services to us, and to align the economic interests of such
employees with the interests of our unitholders. The total
number of common units available to be awarded under the Plan is
2,115,950. Common units cancelled,
85
forfeited or withheld to satisfy exercise prices or tax
withholding obligations will be available for delivery pursuant
to other awards. The Plan is administered by the Committee,
provided that administration may be delegated to such other
committee as appointed by our general partners board of
directors. To date, no awards have been made under the Plan
other than to our general partners independent directors.
The plan administrator may terminate or amend the Plan at any
time with respect to any units for which a grant has not yet
been made. The plan administrator also has the right to alter or
amend the Plan or any part of the plan from time to time,
including increasing the number of units that may be granted
subject to the requirements of the exchange upon which the
common units are listed at that time. However, no change in any
outstanding grant may be made that would materially reduce the
rights or benefits of the participant without the consent of the
participant. The Plan will expire on the earliest of
(1) the date units are no longer available under the Plan
for grants, (2) termination of the Plan by the plan
administrator or (3) the date 10 years following its
date of adoption.
Restricted Units.
A restricted unit is
a common unit that vests over a specified period of time and
during that time is subject to forfeiture. The plan
administrator may make grants of restricted units containing
such terms as it shall determine, including the period over
which restricted units will vest. The plan administrator, in its
discretion, may base its determination upon the achievement of
specified financial or other performance objectives. Restricted
units will be entitled to receive quarterly distributions during
the vesting period.
Phantom Units.
A phantom unit entitles
the grantee to receive a common unit upon the vesting of the
phantom unit or, in the discretion of the plan administrator,
cash equivalent to the value of a common unit. The plan
administrator may make grants of phantom units under the Plan
containing such terms as the plan administrator shall determine,
including the period over which phantom units granted will vest.
The plan administrator, in its discretion, may base its
determination upon the achievement of specified financial
objectives.
Unit Options.
The Plan will permit the
grant of options covering common units. The plan administrator
may make grants containing such terms as the plan administrator
shall determine. Unit options must have an exercise price that
is not less than the fair market value of the common units on
the date of grant. In general, unit options granted will become
exercisable over a period determined by the plan administrator.
Unit Appreciation Rights.
The Plan will
permit the grant of unit appreciation rights. A unit
appreciation right is an award that, upon exercise, entitles the
participant to receive the excess of the fair market value of a
common unit on the exercise date over the exercise price
established for the unit appreciation right. Such excess will be
paid in cash or common units. The plan administrator may make
grants of unit appreciation rights containing such terms as the
plan administrator shall determine. Unit appreciation rights
must have an exercise price that is not less than the fair
market value of the common units on the date of grant. In
general, unit appreciation rights granted will become
exercisable over a period determined by the plan administrator.
Distribution Equivalent Rights.
The
plan administrator may, in its discretion, grant distribution
equivalent rights, or DERs, as a stand-alone award or with
respect to phantom unit awards or other award under the Plan.
DERs entitle the participant to receive cash or additional
awards equal to the amount of any cash distributions made by us
during the period the right is outstanding. Payment of a DER
issued in connection with another award may be subject to the
same vesting terms as the award to which it relates or different
vesting terms, in the discretion of the plan administrator.
Other Unit-Based Awards.
The Plan will
permit the grant of other unit-based awards, which are awards
that are based, in whole or in part, on the value or performance
of a common unit. Upon vesting, the award may be paid in common
units, cash or a combination thereof, as provided in the grant
agreement.
Unit Awards.
The Plan will permit the
grant of common units that are not subject to vesting
restrictions. Unit awards may be in lieu of or in addition to
other compensation payable to the individual.
Change in Control; Termination of
Service.
Awards under the Plan will vest
and/or
become exercisable, as applicable, upon a change in
control of us or our general partner, unless provided
otherwise by the plan administrator. The consequences of the
termination of a grantees employment, consulting
arrangement or membership on the board of directors will be
determined by the plan administrator in the terms of the
relevant award agreement.
86
Source of Units.
Common units to be
delivered pursuant to awards under the Plan may be common units
acquired by us in the open market, common units acquired by us
from any other person or any combination of the foregoing. If we
issue new common units upon the grant, vesting or payment of
awards under the Plan, the total number of common units
outstanding will increase.
Benefits
Our Parents employees, including the Named Executive
Officers, who meet minimum service requirements are entitled to
receive medical, dental, life and long-term disability insurance
benefits for themselves (and beginning the first of the
following month after 90 days of employment, 50% coverage
for their dependents). The Named Executive Officers also
participate along with other employees in our Parents
401(k) plan and other standard benefits. Our Parents
401(k) plan provides for matching contributions by our Parent
and permits discretionary contributions by our Parent of up to
10% of a participants eligible compensation. Such benefits
are provided equally to all of our Parents employees,
other than where benefits are provided pro rata based on the
respective Named Executive Officers salary (such as the
level of disability insurance coverage).
Perquisites
Our Parent believe its executive compensation program described
above is generally sufficient for attracting talented executives
and that providing large perquisites is neither necessary nor in
our Parents stockholders best interests. Certain
perquisites are provided to provide job satisfaction and enhance
productivity. For example, our Parent provides an automobile for
Mr. Cash and Mr. Marlin, and on occasion, family
members and acquaintances have accompanied Mr. Cash on
business trips made on private charter flights. The Named
Executive Officers also are eligible to receive gym club
memberships. Mr. Lawler received reimbursement of certain
relocation expenses in connection with his move to Oklahoma City.
Policy
Regarding Hedging Equity Ownership
The Board of Directors of our general partner adopted a policy
that prohibits Named Executive Officers from speculating in our
securities, which includes, but is not limited to, the
following: short selling (profiting if the market price of the
common unit decreases); buying or selling publicly traded
options, including writing covered calls; taking out margin
loans against common unit options: and hedging or any other type
of derivative arrangement that has a similar economic effect
without the full risk or benefit of ownership.
Compensation
Recovery Policies
The Board of Directors of our general partner maintains a policy
that it will evaluate in appropriate circumstances whether to
seek the reimbursement of certain compensation awards paid to a
Named Executive Officer if such person(s) engage in misconduct
that caused or partially caused a restatement of financial
results, in accordance with section 304 of the
Sarbanes-Oxley Act of 2002. If circumstances warrant, we will
seek to claw back appropriate portions of the Named Executive
Officers compensation for the relevant period, as provided
by law.
87
Executive
Compensation and Other Information
The table below sets forth information concerning the total
annual and long-term compensation paid to or earned by the Chief
Executive Officer, the Chief Financial Officer, and the three
other most highly compensated executive officers who were
serving as executive officers as of December 31, 2007 for
services to all of our Parents affiliates.
Summary
Compensation Table
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Non-Equity
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Stock
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Incentive Plan
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All Other
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Name and Principal Position
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Year
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Salary
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Bonus
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Awards(1)
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Compensation(2)
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Compensation(3)
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Total
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Jerry D. Cash
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2007
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$
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525,000
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$
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1,200
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$
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1,814,239
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$
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182,367
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$
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46,913
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(4)
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$
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2,569,719
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Chairman of the Board
and Chief Executive
Officer
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David E. Grose
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2007
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$
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350,000
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$
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1,200
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$
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1,066,130
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$
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124,658
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$
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15,550
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$
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1,557,538
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Chief Financial Officer
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|
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David Lawler
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2007
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$
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268,739
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$
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1,200
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$
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435,494
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$
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27,783
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$
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4,148
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$
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737,364
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Chief Operating Officer
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Richard Marlin
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2007
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$
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248,000
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$
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1,200
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$
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254,720
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$
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80,863
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$
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20,550
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$
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605,333
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Executive VP Engineering
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David Bolton
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2007
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$
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225,000
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$
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1,200
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$
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298,980
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$
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57,038
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$
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14,325
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$
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596,543
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Executive VP Land
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(1)
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Includes expense related to bonus shares, restricted stock
granted in addition to the awards under the Bonus Plan. Expense
for the bonus shares and restricted stock computed in accordance
with the provisions of Statement of Financial Accounting
Standards No. 123 (Revised)
(SFAS No. 123R) and represents the grant
date fair value determined by utilizing the closing stock price
for our Parents common stock, with expense being
recognized ratably over the requisite service period. Also
includes equity portion of the Bonus Plan award earned for 2006.
Twenty-five percent of the bonus shares vested in March 2007 at
the time the Committee determined the amount of the awards based
upon 2006 performance and the remaining portion vests and will
be paid in March of each of the next three years.
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(2)
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Represents the Bonus Plan awards earned for 2007 and paid in
2008 and productivity gain sharing bonus payments earned and
paid in 2007.
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(3)
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Matching and profit sharing contribution by our Parent under the
401(k) savings plan and life insurance premiums. Salary shown
above has not been reduced by pre-tax contributions to the
company-sponsored 401(k) savings plan. For 2007, matching
contributions and profit sharing contribution amounts were as
follows: Mr. Cash $15,500,
Mr. Grose $15,500, Mr. Lawler
$4,131, Mr. Marlin $20,500, and
Mr. Bolton $14,275.
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(4)
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In addition to the items described in (3) above, also
includes expenses related to a company provided automobile
($30,712) and benefits for gym services. On occasion, family
members and acquaintances have accompanied Mr. Cash on
business trips made on private charter flights at no incremental
cost to us.
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88
Grants
of Plan-Based Awards in 2007
No common unit options were granted to any of our Named
Executive Officers during the year ended December 31, 2007.
This table discloses the actual number of restricted stock
awards granted during the last fiscal year and the grant date
fair value of these awards for services to all of our
Parents affiliates.
Grants of
Plan-Based Awards in 2007
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All Other
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Grant Date
|
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|
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Estimated Future Payouts Under
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Stock Awards:
|
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Fair Value of
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|
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Non-Equity Incentive Plan Awards
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Number of
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Stock and
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|
|
Approval
|
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Grant
|
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Threshold
|
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Target
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Maximum
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Shares of
|
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Option
|
Name
|
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Date
|
|
Date
|
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($)
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|
($)
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($)
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Stock (#)
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Awards
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Jerry Cash
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|
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3/30/07
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|
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4/2/07
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(1)
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493,080
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$
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4,329,242
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(2)
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$
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115,500
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$
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220,500
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$
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525,000
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|
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(3)
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$
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69,167
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David Grose
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3/30/07
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4/2/07
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(1)
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|
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105,000
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$
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921,900
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3/30/07
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3/30/07
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70,000
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(4)
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$
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641,900
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(2)
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$
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77,000
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$
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147,000
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$
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350,000
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|
|
|
|
|
|
|
|
|
|
|
|
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(3)
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$
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46,458
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David Lawler
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4/10/07
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|
|
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4/10/07
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(1)
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|
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|
|
|
|
|
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|
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105,000
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|
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$
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926,100
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(2)
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$
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63,800
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|
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$
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121,800
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|
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$
|
290,000
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|
|
|
|
|
|
|
|
|
|
|
|
|
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(3)
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$
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26,583
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Richard Marlin
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2/23/07
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|
|
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3/21/07
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(1)
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45,000
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$
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388,800
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(2)
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$
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17,360
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|
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$
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66,960
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|
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$
|
182,280
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
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$
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35,113
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|
|
|
|
|
|
|
|
|
|
|
|
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Dave Bolton
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|
|
2/23/07
|
|
|
|
3/07/07
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,000
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|
|
$
|
360,450
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|
|
|
|
|
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|
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(2)
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|
$
|
15,750
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|
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$
|
60,750
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|
|
$
|
165,375
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
|
|
|
|
|
|
$
|
31,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Represents shares granted in connection with the execution of
the Named Executive Officers employment agreement in 2007.
Grant date is the date the employment agreements were executed.
Except for Mr. Lawler, one-third of each award vests on
March 16, 2008, 2009 and 2010. For Mr. Lawler,
15,000 shares were immediately vested and
30,000 shares vested on May 1 of each of 2008, 2009 and
2010.
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|
(2)
|
|
Represents an award under the Bonus Plan for 2007. On
March 5, 2008, the Committee determined the amount of the
award payable for 2007 based upon 2007 performance. The amount
for Mr. Lawler is pro-rated based on his employment
commencement date in 2007. See Compensation Discussion and
Analysis Elements of Our Parents Executive
Compensation Program Management Annual Incentive
Plan for a discussion of the performance criteria
applicable to these awards.
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(3)
|
|
Represents amount payable under our Parents productivity
gain sharing bonus program.
|
|
(4)
|
|
Award was immediately vested.
|
89
Equity
Awards Outstanding at Fiscal Year-End 2007
The following table shows unvested stock awards outstanding for
the Named Executive Officers as of December 31, 2007.
Market value is based on the closing market price of our
Parents common stock on December 31, 2007 ($7.17 a
share).
|
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|
|
|
|
|
|
|
|
|
Stock Awards
|
|
|
|
|
|
|
Market Value
|
|
|
|
|
|
|
of Shares of Stock
|
|
|
|
Number of Shares
|
|
|
That Have
|
|
|
|
That Have Not Vested
|
|
|
Not Vested
|
|
|
Jerry Cash(1)
|
|
|
498,264
|
|
|
$
|
3,572,553
|
|
David Grose(2)
|
|
|
108,564
|
|
|
$
|
778,404
|
|
David Lawler(3 )
|
|
|
90,000
|
|
|
$
|
645,300
|
|
Richard Marlin(4)
|
|
|
59,064
|
|
|
$
|
423,489
|
|
Dave Bolton(5)
|
|
|
66,110
|
|
|
$
|
474,009
|
|
|
|
|
(1)
|
|
166,088 shares vest on each of March 16, 2008, 2009
and 2010.
|
|
(2)
|
|
36,188 shares vest on each of March 16, 2008, 2009 and
2010.
|
|
(3)
|
|
30,000 shares vest on each of May 12, 2008, 2009 and
2010.
|
|
(4)
|
|
15,688 shares vest on each of March 16, 2008, 2009 and
2010. 12,000 shares vest on April 4, 2008.
|
|
(5)
|
|
15,370 shares vest on each of March 16, 2008, 2009 and
2010. 20,000 shares vest on October 5, 2008.
|
Stock
Vested in 2007
The following table sets forth certain information regarding
stock awards vested during 2007 for the Named Executive Officers.
|
|
|
|
|
|
|
|
|
|
|
Stock Awards
|
|
|
|
Number of Shares
|
|
|
|
|
|
|
of Common Stock
|
|
|
Value Realized
|
|
Name
|
|
Acquired on Vesting (#)
|
|
|
on Vesting ($)
|
|
|
Jerry Cash
|
|
|
1,728
|
|
|
$
|
16,813
|
|
David Grose
|
|
|
119,188
|
|
|
$
|
1,159,018
|
|
David Lawler
|
|
|
15,000
|
|
|
$
|
145,950
|
|
Richard Marlin
|
|
|
24,688
|
|
|
$
|
240,214
|
|
David Bolton
|
|
|
20,370
|
|
|
$
|
206,600
|
|
For purposes of the above table, the amount realized upon
vesting is determined by multiplying the number of shares of
stock by the market value of the shares on the date the shares
were issued to the Named Executive Officer.
Director
Compensation for 2007
The following table discloses the cash, equity awards and other
compensation earned, paid or awarded, as the case may be, to
each of our directors during the fiscal year ended 2007.
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|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or
|
|
|
All Other
|
|
|
|
|
|
|
Paid in Cash
|
|
|
Compensation
|
|
|
Total
|
|
Name
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
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Gary Pittman
|
|
$
|
5,086
|
|
|
$
|
3,065
|
(1)
|
|
$
|
8,151
|
|
Mark Stansberry
|
|
$
|
4,442
|
|
|
$
|
3,065
|
(1)
|
|
$
|
7,507
|
|
|
|
|
(1)
|
|
On January 28, 2008, the Board of Directors of our general
partner approved a grant of 15,000 common units each for the
non-employee directors, Messrs. Pittman and Stansberry,
with 25% of the units immediately vested and 25% of the units
vesting on each of the first three anniversaries of the vesting
date. Messrs. Pittman and
|
90
|
|
|
|
|
Stansberry each received distributions and distribution
equivalents with respect to the vested and unvested units
totaling $3,065 for the period from November 15, 2007
through December 31, 2007.
|
In addition to the equity awards described above, all of our
non-employee directors are entitled to the following cash
compensation for each year:
|
|
|
|
|
annual director fee of $32,000 per year (the fees for
Messrs. Pittman and Stansberry were pro rated for the
fourth quarter of 2007 based on their length of service);
|
|
|
|
annual fee of $7,500 per year for the Audit Committee
Chairperson (the fee for Mr. Pittman was pro rated for the
fourth quarter of 2007); and
|
|
|
|
annual fee of $2,500 per year for any other committee
chairperson (the fees for Mr. Stansberry were pro rated for
the fourth quarter of 2007).
|
Employment
Contracts
Each of the Named Executive Officers has an employment
agreement. Except as described below, the employment agreements
for each of the Named Executive Officers are substantially
similar and were entered into with our Parent during 2007. The
employment agreements for Messrs. Cash and Grose replaced
their existing employment agreements.
Each of these agreements has an initial term of three years (the
Initial Term). Upon expiration of the Initial Term,
each agreement will automatically continue for successive
one-year terms, unless earlier terminated in accordance with the
terms of the agreement. The positions, base salary and number of
restricted shares of our Parents common stock granted
under each of the employment agreements is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares of
|
|
Name
|
|
Position
|
|
Base Salary
|
|
|
Restricted Stock
|
|
|
Jerry Cash
|
|
Chief Executive Officer
|
|
$
|
525,000
|
|
|
|
493,080
|
|
David Grose
|
|
Chief Financial Officer
|
|
$
|
350,000
|
|
|
|
105,000
|
|
David Lawler
|
|
Chief Operating Officer
|
|
$
|
290,000
|
|
|
|
90,000
|
|
David Bolton
|
|
Executive Vice President Land
|
|
$
|
225,000
|
|
|
|
45,000
|
|
Richard Marlin
|
|
Executive Vice President Engineering
|
|
$
|
248,000
|
|
|
|
45,000
|
|
One-third of the restricted shares vest on each of the first
three anniversary dates of each employment agreement. In
addition, Mr. Grose and Mr. Lawler received 70,000 and
15,000 unrestricted shares, respectively, of our Parents
common stock in connection with the execution of their
employment agreements.
Each executive is eligible to participate in all of our
Parents incentive bonus plans that are established for its
executive officers. If our Parent terminates an executives
employment without cause (as defined below) or if an
executive terminates his employment agreement for Good Reason
(as defined below), in each case after notice and cure
periods
|
|
|
|
|
the executive will receive his base salary for the remainder of
the term,
|
|
|
|
our Parent will pay the executives health insurance
premium payments for the duration of the COBRA continuation
period (18 months) or until he becomes eligible for health
insurance with a different employer,
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the executive will receive his pro rata portion of any annual
bonus and other incentive compensation to which he would have
been entitled; and
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his unvested shares of restricted stock will vest (which vesting
may be deferred for six months if necessary to comply with
Section 409A of the Internal Revenue Code).
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Under each of the employment agreements, Good Reason means:
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our Parents failure to pay the executives salary or
annual bonus in accordance with the terms of the agreement
(unless the payment is not material and is being contested by
our Parent in good faith);
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if our Parent requires the executive to be based anywhere other
than Oklahoma City, Oklahoma;
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91
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a substantial reduction in the executives duties or
responsibilities; or
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the executive no longer has the title specified above.
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For purposes of the employment agreements, cause
includes the following:
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any act or omission by the executive that constitutes gross
negligence or willful misconduct;
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theft, dishonest acts or breach of fiduciary duty that
materially enrich the executive or materially damage our Parent
or conviction of a felony,
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any conflict of interest, except those consented to in writing
by our Parent;
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any material failure by the executive to observe our
Parents work rules, policies or procedures;
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failure or refusal by the executive to perform his duties and
responsibilities required under the employment agreements, or to
carry out reasonable instruction, to our Parents
satisfaction;
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any conduct that is materially detrimental to our Parents
operations, financial condition or reputation; or
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any material breach of the employment agreement by the executive.
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The following summarizes potential maximum payments that an
executive could receive upon a termination of employment without
cause or for Good Reason, actual amounts are likely to be less.
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Unvested
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Equity
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Name
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Base Salary(1)
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Compensation(2)
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Bonus(3)
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Benefits(4)
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Total
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Jerry Cash
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$
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1,575,000
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$
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3,572,553
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$
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338,625
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|
$
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9,183
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|
$
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5,495,361
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David Grose
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|
$
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1,050,000
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|
$
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778,404
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|
$
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225,750
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|
$
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13,701
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|
|
$
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2,067,855
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David Lawler
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|
$
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870,000
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|
|
$
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645,300
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$
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187,050
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|
$
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13,701
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|
|
$
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1,716,051
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Richard Marlin
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|
$
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744,000
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|
|
$
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423,489
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|
|
$
|
122,760
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|
|
$
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9,183
|
|
|
$
|
1,299,432
|
|
David Bolton
|
|
$
|
675,000
|
|
|
$
|
474,009
|
|
|
$
|
111,375
|
|
|
$
|
13,701
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|
|
$
|
1,274,085
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|
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(1)
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Assumes full three years of salary is paid. Actual amount paid
will be equal to the remaining base salary payable under the
agreement.
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(2)
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Assumes all equity awards are unvested on the date of
termination. For purposes of this table, we have used the number
of unvested shares as of December 31, 2007 and the closing
price of our Parents common stock on that date ($7.17).
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(3)
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Represents target amounts payable under our Parents Bonus
Plan and productivity gain sharing payments for 2008. Assumes a
full years bonus (i.e., if employment were terminated on
December 31 of a year). Actual payment would be pro-rated based
on the number of days in the year during which the executive was
employed.
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(4)
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Represents 18 months of insurance premiums at current rates.
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In general, base salary payments will be paid to the executive
in equal installments on our Parents regular payroll
dates, with the installments commencing six months after the
executives termination of employment (at which time the
executive will receive a lump sum amount equal to the monthly
payments that would have been paid during such six month
period). However, the payments may be commenced immediately if
an exemption under Internal Revenue Code § 409A is
available. If the executives employment is terminated
without cause within two years after a change in control (as
defined below), then the base salary payments will be paid in a
lump sum six months after termination of employment.
Under the employment agreements, a change in control
is generally defined as:
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the acquisition by any person or group of our Parents
common stock that, together with shares of common stock held by
such person or group, constitutes more than 50% of the total
voting power of our Parents common stock;
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any person or group acquires (or has acquired during the
12-month
period ending on the date of the most recent acquisition by such
person or group) ownership of our Parents common stock
possessing 35% or more of the total voting power of our
Parents common stock;
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92
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a majority of members of our Parents board of directors
being replaced during any
12-month
period by directors whose appointment or election is not
endorsed by a majority of the members of our Parents board
of directors prior to the date of the appointment or
election; or
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any person or group acquires (or has acquired during the
12-month
period ending on the date of the most recent acquisition by such
person or group) assets from our Parent that have a total gross
fair market value equal to or more than 40% of the total gross
fair market value of all of our Parents assets immediately
prior to the acquisition or acquisitions.
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The pro rata portion of any annual bonus or other compensation
to which the executive would have been entitled for the year
during which the termination occurred will be paid at the time
bonuses are paid to all employees, or if later, six months after
the executives termination of employment (unless an
exception to Internal Revenue Code § 409A applies).
If the executive is unable to render services as a result of
physical or mental disability, our Parent may terminate his
employment, and he will receive a lump-sum payment equal to one
years base salary and all compensation and benefits that
were accrued and vested as of the date of termination. If
necessary to comply with Internal Revenue Code § 409A,
the payment may be deferred for six months.
Each of the employment agreements also provides for one-year
restrictive covenants of non-solicitation in the event the
executive terminates his own employment or is terminated by our
Parent for cause. Our Parents obligation to make severance
payments is conditioned upon the executive not competing with it
during the term that severance payments are being made.
Compensation
Committee Report
Neither we nor our general partner has a compensation committee.
The Board of Directors of our general partner has reviewed and
discussed the compensation discussion and analysis required by
Item 402(b) of the SECs
Regulation S-K
set forth above with management and based on this review and
discussion, has approved it for inclusion in this
Form 10-K.
The Board of Directors of Quest Energy GP, LLC:
Jerry D. Cash
David C. Lawler
Gary M. Pittman
Mark A. Stansberry
Compensation
Committee Interlocks and Insider Participation
As previously discussed, our general partners Board of
Directors is not required to maintain, and does not maintain, a
compensation committee. Jerry Cash, our general partners
Chairman of the Board of Directors and Chief Executive Officer,
serves as the Chairman of the Board, President and Chief
Financial Officer of our Parent, and David Lawler, our general
partners Chief Operating Officer, serves as the Chief
Operating Officer of our Parent. All compensation decisions with
respect to each of these persons are made by the Compensation
Committee of the board of directors of our Parent. None of the
executive officers of our general partner serves as a member of
the board of directors or compensation committee of any entity
that has one or more of its executive officers serving as a
member of the board of directors of our general partner or of
any compensation committee.
Except for compensation arrangements discussed in this
Form 10-K,
we have not participated in any contracts, loans, fees, awards
or financial interests, direct or indirect, with any director of
our general partner, nor are we aware of any means, directly or
indirectly, by which a director could receive a material benefit
from us. Please read Certain Relationships and Related
Transactions, and Director Independence in Item 13 of
this report for information about relationships among us, our
general partner and our Parent.
93
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Item 12.
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Security
Ownership of Certain Beneficial Owners and Management and
Related Unitholder
Matters.
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The following table sets forth the beneficial ownership of our
units as of March 25, 2008 (unless otherwise indicated
below) held by:
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each person known by us to beneficially own 5% or more of our
common or subordinated units;
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each director of our general partner;
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each Named Executive Officer of our general partner; and
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all directors and officers of our general partner as a group.
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The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial
owner of a security if that person has or shares
voting power, which includes the power to vote or to
direct the voting of such security, or investment
power, which includes the power to dispose of or to direct
the disposition of such security. A person is also deemed to be
a beneficial owner of any securities of which that person has a
right to acquire beneficial ownership within 60 days. Under
these rules, more than one person may be deemed a beneficial
owner of the same securities and a person may be deemed a
beneficial owner of securities as to which he has no economic
interest.
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Percentage of
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Common
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Percentage of
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Percentage of
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Units and
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Common
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Common
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Subordinated
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Subordinated
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Subordinated
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Units
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Units
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Units
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Units
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Units
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Beneficially
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Beneficially
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Beneficially
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Beneficially
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Beneficially
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Name of Beneficial Owner
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Owned(1)
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Owned
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Owned
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Owned
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Owned
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5% Beneficial Owners:
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Quest Resource Corporation 210 Park Avenue, Suite 2750
Oklahoma City, OK 73102
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3,201,521
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26.0
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%
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8,857,981
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100
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%
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|
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57.0
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%
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Officers and Directors:
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Jerry D. Cash
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|
|
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David E. Grose
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|
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|
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|
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David Lawler
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|
|
|
|
|
|
|
|
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|
|
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|
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David Bolton
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|
|
|
|
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|
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|
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Richard Marlin
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|
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|
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Gary Pittman(1)
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|
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41,900
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*
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*
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Mark Stansberry(2)
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|
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3,750
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*
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|
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*
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All directors and executive officers as a group (8 persons)
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45,650
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*
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*
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*
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Signifies less than 1%
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(1)
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|
38,150 common units are owned by G. Pittman & Company,
which is wholly owned by Gary and Alice Pittman as tenants by
the entirety. In addition, Mr. Pittman is entitled to
receive 11,250 bonus units upon satisfaction of certain vesting
requirements. Mr. Pittman does not have the ability to vote
these bonus units.
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(2)
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In addition, Mr. Stansberry is entitled to receive 11,250
bonus units upon satisfaction of certain vesting requirements.
Mr. Stansberry does not have the ability to vote these
bonus units.
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94
The following table sets forth information as of March 5,
2008 concerning the shares of our Parents common stock
beneficially owned by (a) each of our general
partners directors, (b) each of the Named Executive
Officers and (c) all current directors and executive
officers as a group. If a person or entity listed in the
following table is the beneficial owner of less than one percent
of the securities outstanding, this fact is indicated by an
asterisk in the table.
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Number of Shares of
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Our Parents Common Stock
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Percent
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Beneficially
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of Class of Our Parents
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Name and Address of Beneficial Owner
|
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Owned(1)
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Common Stock
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Jerry D. Cash(2)
210 Park Avenue, Suite 2750
Oklahoma City, OK 73102
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1,790,245
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7.6
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%
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David Grose(3)
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|
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176,576
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*
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David C. Lawler(4)
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|
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105,000
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*
|
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Gary M. Pittman(5)
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|
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101,158
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|
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|
*
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David W. Bolton(6)
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|
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76,369
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*
|
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Richard Marlin(7)
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67,404
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|
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*
|
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All Directors and Executive Officers as a Group (8 Persons)
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2,329,972
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10.1
|
%
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(1)
|
|
The number of securities beneficially owned by the entities
above is determined under rules promulgated by the SEC and the
information is not necessarily indicative of beneficial
ownership for any other purpose. Under such rules, beneficial
ownership includes any securities as to which the individual has
sole or shared voting power or investment power and also any
securities that the individual has the right to acquire within
60 days through the exercise of any option or other right.
The inclusion herein of such securities, however, does not
constitute an admission that the named equityholder is a direct
or indirect beneficial owner of such securities. Unless
otherwise indicated, each person or entity named in the table
has sole voting power and investment power (or shares such power
with his or her spouse) with respect to all securities listed as
owned by such person or entity.
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(2)
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Includes (i) 1,200 shares of our common stock owned by
Mr. Cashs wife, Sherry J. Cash,
(ii) 7,678 shares held in Mr. Cashs
retirement account (Mr. Cash does not have voting rights
with respect to the shares held in his profit sharing retirement
account) and (iii) 493,080 restricted shares, which are
subject to vesting. Mr. Cash disclaims beneficial ownership
of the shares owned by Sherry J. Cash. In addition,
Mr. Cash is entitled to receive 5,185 bonus shares upon
satisfaction of certain vesting requirements. Mr. Cash does
not have the ability to vote these bonus shares. Of the
1,790,245 shares of our Parents common stock
beneficially owned by Mr. Cash, 848,458 have been pledged
to secure a personal loan.
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(3)
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|
Includes (i) 3,281 shares of our Parents common
stock held in Mr. Groses retirement account
(Mr. Grose does not have voting rights with respect to
these shares) and (ii) 105,000 restricted shares, which are
subject to vesting. In addition, Mr. Grose is entitled to
receive 3,565 bonus shares upon satisfaction of certain vesting
requirements. Mr. Grose does not have the ability to vote
these bonus shares.
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(4)
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Includes 90,000 restricted shares, which are subject to vesting.
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(5)
|
|
The 101,158 shares are owned by G. Pittman &
Company, which is wholly owned by Gary and Alice Pittman as
tenants by the entirety.
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(6)
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Includes 65,000 restricted shares, which are subject to vesting.
In addition, Mr. Bolton is entitled to receive 1,109 bonus
shares upon satisfaction of certain vesting requirements.
Mr. Bolton does not have the ability to vote these bonus
shares.
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(7)
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Includes (i) 8,258 shares held in
Mr. Marlins retirement account (Mr. Marlin does
not have voting rights with respect to the these shares) and
(ii) 45,000 restricted shares, which are subject to
vesting. In addition, Mr. Marlin is entitled to receive
2,062 bonus shares upon satisfaction of certain vesting
requirements. Mr. Marlin does not have the ability to vote
these bonus shares.
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95
Securities
Authorized For Issuance Under Equity Compensation
Plans
We refer you to Item 5 of this report under the caption
Securities Authorized For Issuance Under Equity
Compensation Plans for certain equity plan information.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
Our general partner and its affiliates own 3,201,521 common
units and 8,857,981 subordinated units representing an aggregate
57% limited partner interest in us. In addition, our general
partner owns a 2% general partner interest in us and the
incentive distribution rights.
Distributions
and Payments to Our General Partner and its Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with the formation, ongoing operation and any
liquidation of Quest Energy Partners, L.P. These distributions
and payments were determined by and among affiliated entities
and, consequently, are not the result of arms-length
negotiations.
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Formation Stage
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The consideration received by our Parent and its subsidiaries
for the contribution of the assets and liabilities to us
|
|
3,201,521 common units;
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8,857,981 subordinated units;
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431,827 general partner units; and
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|
the incentive distribution rights.
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|
Payments at or prior to closing of our initial public offering
|
|
We used $151.2 million of the net proceeds of our initial
public offering to repay indebtedness under existing credit
facilities of our Parent that were secured by the gas and oil
properties contributed to us by our Parent in connection with
that offering. Quest Cherokee, LLC, our principal operating
subsidiary, was a co-borrower on those credit facilities.
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Operational Stage
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Distributions of available cash to our general partner and its
affiliates
|
|
We will generally distribute 98% of our available cash to all
unitholders, including affiliates of our general partner (as the
holders of an aggregate of 3,201,521 common units and 8,857,981
subordinated units) and 2% of our available cash to our general
partner. In addition, if distributions exceed the minimum
quarterly distribution and other higher target distribution
levels, our general partner will be entitled to increasing
percentages of the distributions, up to 23% of the distributions
above the highest target distribution level.
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|
|
|
For 2007, our general partner and its affiliates received a
distribution of approximately $88,222 on their 2% general
partner interest and $2,463,756 on their common units and
subordinated units.
|
|
Payments to our general partner and its affiliates
|
|
Our partnership agreement requires us to reimburse our general
partner for all actual direct and indirect expenses it incurs or
actual payments it makes on our behalf and all other expenses
allocable to us or otherwise incurred by our general partner in
connection with operating our business, including overhead
allocated to our general partner by its affiliates. These
expenses include salary, bonus, incentive compensation and other
amounts paid to persons who perform services for us or on our
behalf, and expenses allocated to our general partner by its
affiliates. Our general partner is entitled to determine in
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96
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|
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|
|
good faith the expenses that are allocable to us. Our management
services agreement requires us to reimburse Quest Energy Service
for its expenses incurred on our behalf. For the period from
November 15, 2007 to December 31, 2007, we reimbursed
our general partner and Quest Energy Service for expenses of
$1.8 million in the aggregate.
|
|
Withdrawal or removal of the general partner
|
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of that interest.
|
|
Liquidation Stage
|
|
|
|
Liquidation
|
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances.
|
Agreements
Governing the Transactions
We and other parties entered into various documents and
agreements that effected our initial public offering and related
transactions, including the vesting of assets in, and the
assumption of liabilities by, us and our subsidiaries, and the
application of the proceeds of our initial public offering.
These agreements were not the result of arms-length
negotiations, and they, or any of the transactions that they
provide for, may not have been effected on terms at least as
favorable to the parties to these agreements as they could have
obtained from unaffiliated third parties. All of the transaction
expenses incurred in connection with these transactions,
including the expenses associated with transferring assets into
our subsidiaries, were paid from the proceeds of the offering.
Omnibus Agreement.
We entered into an omnibus
agreement with our Parent that governs our relationship with it
and its subsidiaries with respect to certain matters not
governed by the management services agreement.
Under the omnibus agreement, our Parent and its subsidiaries
agreed to give us a right to purchase any natural gas or oil
wells or other natural gas or oil rights and related equipment
and facilities that they acquire within the Cherokee Basin, but
not including any midstream or downstream assets. Except as
provided above, our Parent will not be restricted, under either
our partnership agreement or the omnibus agreement, from
competing with us and may acquire, construct or dispose of
additional gas and oil properties or other assets in the future
without any obligation to offer us the opportunity to acquire
those assets.
Under the omnibus agreement, our Parent will indemnify us for
three years after the closing of our initial public offering
against certain potential environmental claims, losses and
expenses associated with the operation of the assets occurring
before the closing date of the offering. Additionally, our
Parent will indemnify us for losses attributable to title
defects (for three years after the closing of the offering),
retained assets and income taxes attributable to pre-closing
operations (for the applicable statute of limitations). Our
Parents maximum liability for the environmental
indemnification obligations will not exceed $5.0 million
and our Parent will not have any indemnification obligation for
environmental claims or title defects until our aggregate losses
exceed $500,000. Our Parent will have no indemnification
obligations with respect to environmental claims made as a
result of additions to or modifications of environmental laws
promulgated after the closing date of the offering. We have
agreed to indemnify our Parent against environmental liabilities
related to our assets to the extent our Parent is not required
to indemnify us. We also will indemnify our Parent for all
losses attributable to the post-closing operations of the assets
contributed to us, to the extent not subject to our
Parents indemnification obligations.
Any or all of the provisions of the omnibus agreement, other
than the indemnification provisions described above, will be
terminable by our Parent at its option if our general partner is
removed without cause and units held by our general partner and
its affiliates are not voted in favor of that removal. The
omnibus agreement will also terminate in the event of a change
of control of us or our general partner.
Midstream Services Agreement.
We became a
party to an existing midstream services and gas dedication
agreement between our Parent and Quest Midstream pursuant to
which Quest Midstream gathers substantially all of
97
the gas from wells operated by us in the Cherokee Basin. Please
read Gas Gathering Midstream Services
Agreement under Item 1 of this report. The gathering
fees payable to Quest Midstream under the midstream services
agreement in some cases exceed the amount we are able to charge
to royalty owners under our gas leases for gathering and
compression. For the year ended December 31, 2007, we paid
approximately $6.0 million to Quest Midstream under the
midstream services agreement.
Management Services Agreement.
We entered into
a management services agreement with Quest Energy Service
pursuant to which Quest Energy Service provide us with legal,
information technology, accounting, finance, insurance, tax,
property management, engineering, administrative, risk
management, corporate development, commercial and marketing,
treasury, human resources, audit, investor relations and
acquisition services in respect of opportunities for us to
acquire long-lived, stable and proved gas and oil reserves.
We reimburse Quest Energy Service for the reasonable costs of
the services it provides to us. The employees of Quest Energy
Service also manage the operations of our Parent and Quest
Midstream and will be reimbursed by our Parent and Quest
Midstream for general and administrative services incurred on
their respective behalf. These expenses include salary, bonus,
incentive compensation and other amounts paid to persons who
perform services for us or on our behalf, and expenses allocated
to Quest Energy Service by its affiliates. Our general partner
is entitled to determine in good faith the expenses that are
allocable to us.
Our general partner has the right and the duty to review the
services provided, and the costs charged, by Quest Energy
Service under the management services agreement. Our general
partner may in the future cause us to hire additional personnel
to supplement or replace some or all of the services provided by
Quest Energy Service, as well as employ third-party service
providers. If we were to take such actions, they could increase
the overall costs of our operations.
The management services agreement is not terminable by us
without cause so long as our Parent controls our general
partner. Thereafter, the agreement is terminable by either us or
Quest Energy Service upon six months notice. The
management services agreement is terminable by us or our Parent
upon a material breach of the agreement by the other party and
failure to remedy such breach for 60 days (or 30 days
in the event of nonpayment) after receiving notice of the breach.
Quest Energy Service will not be liable to us for its
performance of, or failure to perform, services under the
management services agreement unless its acts or omissions
constitute gross negligence or willful misconduct.
Midstream Omnibus Agreement.
We are subject to
the midstream omnibus agreement dated as of December 22,
2006, among Quest Midstream, Quest Midstreams general
partner, Quest Midstreams operating subsidiary and our
Parent so long as we are an affiliate of our Parent and our
Parent or any of its affiliates controls Quest Midstream.
The midstream omnibus agreement restricts us from engaging in
the following businesses (each of which is referred to in this
report as a Restricted Business):
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the gathering, treating, processing and transporting of gas in
North America;
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the transporting and fractionating of gas liquids in North
America;
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any other midstream activities, including but not limited to
crude oil storage, transportation, gathering and terminaling;
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constructing, buying or selling any assets related to the
foregoing businesses; and
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any line of business other than those described in the preceding
bullet points that generates qualifying income,
within the meaning of Section 7704(d) of the Code, other
than any business that is primarily engaged in the exploration
for and production of oil or gas and the sale and marketing of
gas and oil derived from such exploration and production
activities.
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If a business described in the last bullet point above has been
offered to Quest Midstream and it has declined the opportunity
to purchase that business, then that line of business is no
longer considered a Restricted Business.
98
The following are not considered a Restricted Business:
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the ownership of a passive investment of less than 5% in an
entity engaged in a Restricted Business;
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any business in which Quest Midstream permits us to engage;
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the ownership or operation of assets used in a Restricted
Business if the value of the assets is less than
$4 million; and
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any business that we have given Quest Midstream the option to
acquire and it has elected not to purchase.
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Subject to certain exceptions, if we were to acquire any
midstream assets in the future pursuant to the above provisions,
then Quest Midstream will have a preferential right to acquire
those midstream assets in the event of a sale or transfer of
those assets by us.
If we acquire any acreage located outside the Cherokee Basin
that is not subject to any existing agreement with an
unaffiliated party to provide midstream services, Quest
Midstream will have a preferential right to offer to provide
midstream services to us in connection with wells to be
developed by us on that acreage.
Contribution, Conveyance and Assumption
Agreement.
We entered into a contribution,
conveyance and assumption agreement to effect, among other
things, the transfer of the assets, liabilities and operations
of our Parent located in the Cherokee Basin (other than its
midstream assets) to us at the closing of our initial public
offering, the issuance of 3,201,521 common units and 8,857,981
subordinated units to our Parent and the issuance to our general
partner of 431,827 general partner units and the incentive
distribution rights. We will indemnify our Parent for
liabilities arising out of or related to existing litigation
relating to the assets, liabilities and operations located in
the Cherokee Basin transferred to us.
Policy
Regarding Transactions with Related Persons
We do not have a formal, written policy for the review, approval
or ratification of transactions between us and any director or
executive officer, nominee for director, 5% unitholder or member
of the immediate family of any such person that are required to
be disclosed under Item 404(a) of
Regulation S-K.
However, our policy is that any activities, investments or
associations of a director or officer that create, or would
appear to create, a conflict between the personal interests of
such person and our interests must be assessed by the Chief
Financial Officer or the Audit Committee or in certain cases,
the Conflicts Committee, of our general partner.
Director
Independence
See Directors, Executive Officers and Corporate
Governance Committees of the Board of
Directors under Item 10 of this report for a
discussion of director independence.
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Item 14.
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Principal
Accountant Fees and
Services.
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The Audit Committee of our general partner selected Murrell,
Hall, McIntosh & Co. PLLP as our independent
registered public accounting firm to provide audit services for
the year ended December 31, 2007. The Audit
Committees charter requires the Audit Committee to approve
in advance all audit and non-audit services to be provided by
our independent registered public accounting firm. All services
reported in the audit, audit-related, tax and all other fees
categories below with respect to this report were approved by
the Audit Committee of our general partner (or the Audit
Committee of our Parent with respect to the amounts listed under
Predecessor).
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Type of Fee
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Successor
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Predecessor
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2007
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Audit Fees(1)
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$
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9,300
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$
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105,833
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$
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115,133
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Audit-Related Fees(2)
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2,328
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2,328
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Tax Fees(3)
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4,353
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15,374
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19,727
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All Other Fees
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Total
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$
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13,653
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$
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123,535
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$
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137,188
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99
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(1)
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Represents fees for professional services provided in connection
with the audit of our annual financial statements, review of our
quarterly financial statements and audits performed as part of
our registration filings for our initial public offering.
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(2)
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Represents fees for professional services that are reasonably
related to the performance of the audit or review of our
financial statements and not included in Audit Fees, including
services provided with respect to the filing of our
Form S-8
registration statement with the SEC.
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(3)
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Represents fees for professional services provided for tax
compliance, tax advice and tax planning.
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PART IV
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Item 15.
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Exhibits,
Financial Statement
Schedules.
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(a)
Exhibits, Financial Statements and Financial
Statement Schedules:
1.
Financial Statements:
Our consolidated/carve out financial statements and the report
of our independent registered public accounting firm are set
forth under Item 8 of this report.
2.
Financial Statement Schedules:
Financial statement schedules have been omitted because they
either are not required or are not applicable or because
equivalent information has been included in the financial
statements, the notes thereto or elsewhere herein.
3.
Exhibits:
Exhibits requiring attachment pursuant to Item 601 of
Regulation S-K
are listed in the Index to Exhibits beginning on page 102
of this
Form 10-K
that is incorporated herein by reference.
(b)
Exhibits.
See exhibits identified above under Item 15(a)3.
(c)
Financial Statement Schedules.
See financial statement schedules identified above under
Item 15(a)2, if any.
100
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
QUEST ENERGY PARTNERS, L.P.
By: Quest Energy GP, LLC, its General Partner
Jerry D. Cash, Chief Executive Officer
Dated: March 31, 2008
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
Jerry D. Cash, Chief Executive Officer (Principal Executive
Officer) and Director
March 31, 2008
David E. Grose, Chief Financial Officer (Principal Financial
Officer and Principal Accounting Officer)
March 31, 2008
David Lawler, Director
March 31, 2008
Mark A. Stansberry, Director
March 31, 2008
Gary M. Pittman, Director
March 31, 2008
101
EXHIBIT INDEX
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Exhibit No.
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Description
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*3
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.1
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Certificate of Limited Partnership (incorporated herein by
reference to Exhibit 3.1 to Quest Energy Partners,
L.P.s Registration Statement on
Form S-1
filed on July 19, 2007).
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*3
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.2
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First Amended and Restated Agreement of Limited Partnership of
Quest Energy Partners, L.P. (incorporated herein by reference to
Exhibit 3.1 to Quest Energy Partners, L.P.s amended
Current Report on
Form 8-K/A
filed on December 7, 2007).
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*3
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.3
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Certificate of Formation of Quest Energy GP, LLC (incorporated
herein by reference to Exhibit 3.3 to Quest Energy
Partners, L.P.s Registration Statement on
Form S-1
filed on July 19, 2007).
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*3
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.4
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Amended and Restated Limited Liability Company Agreement of
Quest Energy GP, LLC (incorporated herein by reference to
Exhibit 3.2 to Quest Energy Partners, L.P.s Current
Report on
Form 8-K
filed on November 21, 2007).
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*10
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.1
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Contribution, Conveyance and Assumption Agreement, dated as of
November 15, 2007, by and among Quest Energy Partners,
L.P., Quest Energy GP, LLC, Quest Resource Corporation, Quest
Cherokee, LLC, Quest Oil & Gas, LLC, and Quest Energy
Service, LLC (incorporated herein by reference to
Exhibit 10.1 to Quest Energy Partners, L.P.s Current
Report on
Form 8-K
filed on November 21, 2007).
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*10
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.2
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Omnibus Agreement, dated as November 15, 2007, by and among
Quest Energy Partners, L.P., Quest Energy GP, LLC and Quest
Resource Corporation (incorporated herein by reference to
Exhibit 10.2 to Quest Energy Partners, L.P.s Current
Report on
Form 8-K
filed on November 21, 2007).
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*10
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.3
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Management Services Agreement, dated as of November 15,
2007, by and among Quest Energy Partners, L.P., Quest Energy GP,
LLC and Quest Energy Service, LLC (incorporated herein by
reference to Exhibit 10.3 to Quest Energy Partners,
L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.4
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Amended and Restated Credit Agreement, dated as of
November 15, 2007, by and among Quest Resource Corporation,
as the Initial Co-Borrower, Quest Cherokee, LLC, as the
Borrower, Quest Energy Partners, L.P., as a Guarantor, Royal
Bank of Canada, as Administration Agent and Collateral Agent,
KeyBank National Association, as Documentation Agent, and the
lenders from time to time party thereto (incorporated herein by
reference to Exhibit 10.4 to Quest Energy Partners,
L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.5
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Midstream Services and Gas Dedication Agreement, dated
December 22, 2006 (but effective as of December 1,
2006), between Bluestem Pipeline, LLC and Quest Resource
Corporation, including exhibits thereto (incorporated herein by
reference to Exhibit 10.6 to Quest Resource
Corporations Current Report on
Form 8-K
(File
No. 0-17371)
filed on December 29, 2006).
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*10
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.6
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Amendment No. 1 to the Midstream Services and Gas
Dedication Agreement, dated as of August 9, 2007, by and
between Quest Resource Corporation and Bluestem Pipeline, LLC
(incorporated herein by reference to Exhibit 10.1 to Quest
Resource Corporations Current Report on
Form 8-K
(File
No. 0-17371)
filed on August 13, 2007).
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*10
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.7
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Assignment and Assumption Agreement, dated as of
November 15, 2007, by and among Quest Resource Corporation,
Quest Energy Partners, L.P. and Bluestem Pipeline, LLC
(incorporated herein by reference to Exhibit 10.5 to Quest
Energy Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.8
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Quest Midstream Omnibus Agreement, dated December 22, 2006,
among Quest Resource Corporation, Quest Midstream GP, LLC,
Bluestem Pipeline, LLC and Quest Midstream Partners, L.P.
(incorporated herein by reference to Exhibit 10.3 to Quest
Resource Corporations Current Report on
Form 8-K
(File
No. 0-17371)
filed on December 29, 2006).
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*10
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.9
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Acknowledgement and Consent, dated as of November 15, 2007,
of Quest Energy Partners, L.P. (incorporated herein by reference
to Exhibit 10.6 to Quest Energy Partners, L.P.s
Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.10
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Quest Energy Partners, L.P. Long-Term Incentive Plan
(incorporated herein by reference to Exhibit 10.7 to Quest
Energy Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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102
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Exhibit No.
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Description
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*10
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.11
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Form of Restricted Unit Award Agreement (incorporated herein by
reference to Exhibit 10.3 to Quest Energy Partners,
L.P.s Registration Statement on
Form S-1
filed on July 19, 2007).
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10
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.12
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Summary of Director Compensation Arrangements.
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10
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.13
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Form of Bonus Unit Award Agreement.
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*10
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.14
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Loan Transfer Agreement, dated as of November 15, 2007, by
and among Quest Resource Corporation, Quest Cherokee, LLC, Quest
Oil & Gas, LLC, Quest Energy Service, Inc., Quest
Cherokee Oilfield Service, LLC, Guggenheim Corporate Funding,
LLC, Wells Fargo Foothill, Inc., and Royal Bank of Canada
(incorporated herein by reference to Exhibit 10.8 to Quest
Energy Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.15
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Guaranty for Amended and Restated Credit Agreement by Quest
Energy Partners, L.P. in favor of Royal Bank of Canada, dated as
of November 15, 2007 (incorporated herein by reference to
Exhibit 10.9 to Quest Energy Partners, L.P.s Current
Report on
Form 8-K
filed on November 21, 2007).
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*10
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.16
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Guaranty for Amended and Restated Credit Agreement by Quest
Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada,
dated as of November 15, 2007 (incorporated herein by
reference to Exhibit 10.10 to Quest Energy Partners,
L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.17
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Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Energy Partners, L.P. for the benefit of
Royal Bank of Canada, dated as of November 15, 2007
(incorporated herein by reference to Exhibit 10.11 to Quest
Energy Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.18
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Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Cherokee Oilfield Service, LLC for the
benefit of Royal Bank of Canada, dated as of November 15,
2007 (incorporated herein by reference to Exhibit 10.12 to
Quest Energy Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*10
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.19
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Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Cherokee, LLC for the benefit of Royal Bank
of Canada, dated as of November 15, 2007 (incorporated
herein by reference to Exhibit 10.13 to Quest Energy
Partners, L.P.s Current Report on
Form 8-K
filed on November 21, 2007).
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*21
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.1
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List of Subsidiaries (incorporated herein by reference to
Exhibit 21.1 to Quest Energy Partners, L.P.s
Amendment No. 1 to
Form S-1
filed on September 6, 2007).
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23
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.1
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Consent of Cawley, Gillespie & Associates, Inc.
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23
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.2
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Consent of Murrell, Hall, McIntosh & Co., PLLP.
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31
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.1
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Certification by Chief Executive Officer pursuant to
Rule 13a-14(a)
or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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31
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.2
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Certification by Chief Financial Officer pursuant to
Rule 13a-14(a)
or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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32
|
.1
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Certification by Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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32
|
.2
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Certification by Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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*
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Incorporated by reference
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103