We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Share Name | Share Symbol | Market | Type |
---|---|---|---|
Bill Barrett Corp. (delisted) | NYSE:BBG | NYSE | Ordinary Share |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 4.84 | 0.00 | 01:00:00 |
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the transition period from
|
|
to
|
|
Delaware
|
|
80-0000545
|
(State or other jurisdiction of
incorporation
or organization)
|
|
(IRS Employer
Identification No.)
|
Securities registered pursuant to Section 12(b) of the Act:
|
||
Title of each class
|
|
Name of each exchange on which registered
|
Common Stock, $.001 par value
|
|
New York Stock Exchange
|
|
|
|
Securities registered pursuant to Section 12(g) of the Act: None
|
Large accelerated filer
|
|
o
|
|
Accelerated filer
|
|
þ
|
Non-accelerated filer
|
|
o
(Do not check if a smaller reporting company)
|
|
Smaller reporting company
|
|
o
|
•
|
volatility of market prices received for oil, natural gas and NGLs;
|
•
|
actual production being less than estimated;
|
•
|
changes in the estimates of proved reserves;
|
•
|
reductions in the borrowing base under our revolving bank credit facility (sometimes referred to as the "Amended Credit Facility");
|
•
|
availability of capital at a reasonable cost;
|
•
|
legislative or regulatory changes that can affect our ability to permit wells and conduct operations, including ballot initiatives seeking moratoria or bans on drilling or hydraulic fracturing;
|
•
|
availability of third party goods and services at reasonable rates;
|
•
|
liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, regulatory penalties or other matters that may not be covered by an effective indemnity or insurance; and
|
•
|
other uncertainties, including the factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in "Item 1A. Risk Factors" all of which are difficult to predict.
|
Basin/Area
|
|
State
|
|
Estimated Net
Proved Reserves
(MMBoe)
(1)
|
|
December 2016 Average Daily Net Production
(Boe/d) |
|
Net Producing Wells
|
|
Net Undeveloped Acreage
|
|
||||
Denver-Julesburg
|
|
CO/WY
|
|
42.9
|
|
|
15,102
|
|
|
192.6
|
|
|
29,788
|
|
(2)
|
Uinta Oil Program
|
|
UT
|
|
12.0
|
|
|
1,887
|
|
|
88.6
|
|
|
12,334
|
|
|
Other
|
|
Various
|
|
—
|
|
|
14
|
|
|
5.9
|
|
|
171,791
|
|
(3)
|
Total
|
|
|
|
54.9
|
|
|
17,003
|
|
|
287.1
|
|
|
213,913
|
|
|
(1)
|
Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in
2016
for natural gas (Henry Hub price) and oil (WTI Cushing price), which averaged
$2.48
per MMBtu of natural gas and
$42.75
per barrel of oil in
2016
, respectively, without giving effect to hedging transactions. The average NGL price of
$19.70
per barrel was based on Mt Belvieu pricing using a historical composite percentage. Our reserves estimates are based on a reserve report prepared by us and audited by our independent third party petroleum engineers. See "– Oil and Gas Data – Proved Reserves".
|
(2)
|
Excludes an additional
1,518
net undeveloped acres that are subject to drill-to-earn agreements.
|
(3)
|
Other includes
71,228
and
63,367
net undeveloped acres in the Paradox and Deseret Basins, respectively.
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||||||||
|
Oil
|
|
Natural
Gas
|
|
NGLs
|
|
Oil
|
|
Natural
Gas
|
|
NGLs
|
|
Oil
|
|
Natural
Gas
|
|
NGLs
|
|||||||||
Production
(1)(2)
|
64
|
%
|
|
20
|
%
|
|
16
|
%
|
|
67
|
%
|
|
20
|
%
|
|
13
|
%
|
|
44
|
%
|
|
40
|
%
|
|
16
|
%
|
Proved reserves
|
57
|
%
|
|
23
|
%
|
|
20
|
%
|
|
66
|
%
|
|
20
|
%
|
|
14
|
%
|
|
69
|
%
|
|
21
|
%
|
|
10
|
%
|
(1)
|
Our wells typically produce a higher percentage of oil at the beginning of their life cycle. During periods where fewer
|
(2)
|
Production for the year ended December 31, 2014 includes legacy natural gas producing properties that have been sold.
|
•
|
Estimated proved reserves as of
December 31, 2016
-
42.9
MMBoe.
|
•
|
Producing wells - We had interests in
299
gross (
192.6
net) producing wells as of
December 31, 2016
, and we serve as operator in 202 gross wells.
|
•
|
2016
net production -
5,054
MBoe.
|
•
|
Acreage - We held
29,788
net undeveloped and
26,149
net developed acres as of
December 31, 2016
.
|
•
|
Capital expenditures - Our capital expenditures for
2016
were
$95.5 million
for participation in the drilling of
17
gross (15.1 net) wells, acquisition of leasehold acres and construction of gathering facilities.
|
•
|
As of
December 31, 2016
, we were drilling 1 gross (1 net) well, and we were waiting to complete 7 gross (6 net) wells within the DJ Basin.
|
•
|
Based on our remaining reserves as of January 1, 2017, we have a 64% weighted average working interest in our producing wells in the DJ Basin.
|
•
|
Estimated proved reserves as of
December 31, 2016
-
12.0
MMBoe.
|
•
|
Producing wells - We had interests in
118
gross (
88.6
net) producing wells as of
December 31, 2016
, and we serve as operator in 103 gross wells.
|
•
|
2016
net production -
1,022
MBoe.
|
•
|
Acreage - We held
12,334
net undeveloped and
11,914
net developed acres as of
December 31, 2016
.
|
•
|
As of
December 31, 2016
, we were not in the process of drilling or completing any wells.
|
•
|
Based on our remaining reserves as of January 1, 2017, we have a 68.8% weighted average working interest in our producing wells in the Uinta Oil Program.
|
|
|
As of December 31,
|
|||||||
Proved Reserves:
(1)(2)
|
|
2016
|
|
2015
|
|
2014
|
|||
Proved Developed Reserves:
|
|
|
|
|
|
|
|||
Oil (MMBbls)
|
|
21.8
|
|
|
27.2
|
|
|
29.3
|
|
Natural gas (Bcf)
|
|
47.5
|
|
|
45.2
|
|
|
50.6
|
|
NGLs (MMBbls)
|
|
6.7
|
|
|
5.1
|
|
|
3.8
|
|
Total proved developed reserves (MMBoe)
(3)
|
|
36.4
|
|
|
39.8
|
|
|
41.5
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|||
Oil (MMBbls)
|
|
9.3
|
|
|
28.3
|
|
|
54.5
|
|
Natural gas (Bcf)
|
|
28.7
|
|
|
52.8
|
|
|
103.3
|
|
NGLs (MMBbls)
|
|
4.4
|
|
|
6.8
|
|
|
9.0
|
|
Total proved undeveloped reserves (MMBoe)
(3)
|
|
18.5
|
|
|
43.9
|
|
|
80.8
|
|
Total Proved Reserves (MMBoe)
(3)
|
|
54.9
|
|
|
83.7
|
|
|
122.3
|
|
(1)
|
Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in
2016
for natural gas (Henry Hub price) and oil (WTI Cushing price), subject to certain adjustments, or
$2.48
per MMBtu of natural gas and
$42.75
per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price of
$19.70
per barrel was based on Mt Belvieu pricing using a historical composite percentage. We currently do not include future reclamation costs net of salvage value in the calculation of our proved reserves. Our reserves estimates are based on a reserve report prepared by us and audited by NSAI. See "– Oil and Gas Data – Proved Reserves".
|
(2)
|
The comparability of the proved reserves for the periods presented are impacted by the Piceance Divestiture and Powder River Oil Divestiture in 2014. See Note
4
of the Notes to Consolidated Financial Statements for more information related to these divestitures.
|
(3)
|
Total does not add due to rounding.
|
|
|
As of December 31,
|
|||||||
Proved Undeveloped Reserves:
|
|
2016
|
|
2015
|
|
2014
|
|||
|
|
(MMBoe)
|
|||||||
Beginning balance
|
|
43.9
|
|
|
80.8
|
|
|
113.7
|
|
Additions from drilling program
|
|
8.4
|
|
|
2.6
|
|
|
12.5
|
|
Acquisitions
|
|
—
|
|
|
—
|
|
|
7.4
|
|
Engineering revisions
|
|
(0.7
|
)
|
|
1.3
|
|
|
(6.0
|
)
|
Price revisions
|
|
(0.3
|
)
|
|
(18.0
|
)
|
|
—
|
|
Converted to proved developed
|
|
(8.5
|
)
|
|
(8.1
|
)
|
|
(10.2
|
)
|
Sold/ expired/ other
(1)
|
|
(24.3
|
)
|
|
(14.7
|
)
|
|
(36.6
|
)
|
Total proved undeveloped reserves
(2)
|
|
18.5
|
|
|
43.9
|
|
|
80.8
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Proved undeveloped locations converted to proved developed wells during year
|
|
21
|
|
|
35
|
|
|
65
|
|
|||
Proved undeveloped drilling and completion capital invested (in millions)
|
|
$
|
55.3
|
|
|
$
|
165.3
|
|
|
$
|
227.5
|
|
Proved undeveloped facilities capital invested (in millions)
|
|
$
|
5.3
|
|
|
$
|
5.0
|
|
|
$
|
9.5
|
|
Percentage of proved undeveloped reserves converted to proved developed
(3)
|
|
19
|
%
|
|
10
|
%
|
|
9
|
%
|
|||
Prior year's proved undeveloped reserves remaining undeveloped at current year end (MMBoe)
|
|
9.6
|
|
|
40.8
|
|
|
66.8
|
|
(1)
|
The decrease in proved undeveloped reserves is the result of using discretion based on our development activity level in 2016. The downward revisions include approximately 24.3 MMboe that were removed from the proved undeveloped reserve category as these locations are not included in our near-term development plans. Of the 24.3 MMBoe revision, 18.2 MMBoe proved undeveloped reserves in the DJ Basin were removed as the planned development of these locations are outside the SEC's five-year development window, which is based on when the proved undeveloped location was added. Other than the timing of development, the DJ Basin locations technically meet the SEC proved undeveloped reserve definition and could be added if the Company's future development plan was accelerated. Additionally, 6.1 MMBoe of proved undeveloped reserves from the Uinta Oil Program were removed due to electing not to develop these locations in
|
(2)
|
Our development plan for drilling proved undeveloped wells represents an investment decision to drill these proved undeveloped locations within the five year development window allowed at the time the applicable proved undeveloped reserve is booked. Our development plan contemplates that we will develop our DJ Basin proved undeveloped locations with a one rig program over three years. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with a more attractive rate of return, leading us to deviate from our original development plan.
|
(3)
|
Our asset portfolio has significantly changed beginning in 2012 and continuing through 2014, resulting in a change in development focus for the years ended December 31, 2014, 2015 and 2016. During 2014 and 2015 the development program was focused on the oil assets located in the DJ and Uinta Basins which, at the time, were relatively immature in their development as compared to the divested gas assets. Given our acreage positions in both the DJ and Uinta Basins, our 2014 and 2015 development was concentrated on developing unproven locations in order to assess the extent of the plays across our acreage and to develop leases that would have expired. As a result, the conversion rate of proved undeveloped reserves was 9% and 10% for the years ended December 31, 2014 and 2015, respectively. Given the lower commodity price, the 2016 development was concentrated in areas of higher certainty. As a result, the conversion rate of proved undeveloped reserves increased to 19% for the year ended December 31, 2016.
|
•
|
A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This is intended to ensure the accuracy of the production data, which supplies the basis for forecasting.
|
•
|
A comparison is made and documented of land and lease record to interest data in the reserve database. This is intended to ensure that the costs and revenues will be properly determined in the reserves estimation.
|
•
|
A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This is intended to ensure that all costs are properly included in the reserve database.
|
•
|
A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.
|
•
|
Natural gas and oil prices based on the SEC pricing requirements are supplied by the third party independent engineering firm. Natural gas pricing for the first flow day of every month is collected from Platts Gas Daily Henry Hub price and oil pricing is collected from Bloomberg's WTI spot price. The average NGL price is based on a percentage of the WTI oil price per barrel.
|
•
|
A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check designed to ensure accuracy of input data in the reserve database.
|
•
|
Accurate classification of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party engineers. Discrepancies are discussed and differences are jointly resolved.
|
•
|
Internal reserves estimates are reviewed by well and by area by the Senior Vice President of Corporate Development and Planning. A variance by well to the previous year-end reserve report is used in this process. This review is independent of the reserves estimation process.
|
•
|
Reserves variances are discussed among the internal reservoir engineers and the Senior Vice President of Corporate Development and Planning. Our internal reserves estimates are reviewed by senior management and the Reserves and EHS Committee prior to publication.
|
•
|
The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data.
|
•
|
The NSAI engineer may verify the production data with public data.
|
•
|
The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.
|
•
|
The NSAI technical staff may prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.
|
•
|
For the reserves estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by analogy to other wells in the basin drilled on varying well spacing.
|
•
|
The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon his/her knowledge and experience.
|
•
|
The NSAI engineer does not verify our working and net revenue interests or product price deductions.
|
•
|
The NSAI engineer does not verify our capital costs although he/she may ask for confirming information and compare to basin analogs.
|
•
|
The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.
|
•
|
The NSAI engineer confirms the oil and gas prices used for the SEC reserves estimate.
|
•
|
NSAI confirms that its reserves estimate is within a 10% variance of our internal net reserves estimate and estimated
future net revenue (discounted at 10%), in the aggregate, before an audit letter is issued.
|
•
|
The audit by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.
|
|
Year Ended December 31,
|
||||||||||
2016
|
|
2015
|
|
2014
|
|||||||
Company Production Data:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
3,885
|
|
|
4,401
|
|
|
4,012
|
|
|||
Natural gas (MMcf)
|
7,170
|
|
|
7,764
|
|
|
21,744
|
|
|||
NGLs (MBbls)
|
1,010
|
|
|
898
|
|
|
1,476
|
|
|||
Combined volumes (MBoe)
|
6,090
|
|
|
6,593
|
|
|
9,112
|
|
|||
Daily combined volumes (Boe/d)
|
16,639
|
|
|
18,063
|
|
|
24,964
|
|
|||
DJ Basin – Production Data
(1)
:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
3,050
|
|
|
2,958
|
|
|
1,682
|
|
|||
Natural gas (MMcf)
|
6,228
|
|
|
6,012
|
|
|
4,224
|
|
|||
NGLs (MBbls)
|
966
|
|
|
815
|
|
|
423
|
|
|||
Combined volumes (MBoe)
|
5,054
|
|
|
4,775
|
|
|
2,809
|
|
|||
Daily combined volumes (Boe/d)
|
13,809
|
|
|
13,082
|
|
|
7,696
|
|
|||
Uinta Oil Program – Production Data
(1)
:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
830
|
|
|
1,420
|
|
|
1,821
|
|
|||
Natural gas (MMcf)
|
900
|
|
|
1,728
|
|
|
2,220
|
|
|||
NGLs (MBbls)
|
42
|
|
|
82
|
|
|
119
|
|
|||
Combined volumes (MBoe)
|
1,022
|
|
|
1,790
|
|
|
2,310
|
|
|||
Daily combined volumes (Boe/d)
|
2,792
|
|
|
4,904
|
|
|
6,329
|
|
|||
Average Realized Prices before Hedging:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
38.83
|
|
|
$
|
40.06
|
|
|
$
|
77.92
|
|
Natural gas (per Mcf)
|
1.98
|
|
|
2.23
|
|
|
4.78
|
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
31.55
|
|
|||
Combined (per Boe)
|
29.28
|
|
|
31.02
|
|
|
50.82
|
|
|||
Average Realized Prices with Hedging:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
62.56
|
|
|
$
|
78.19
|
|
|
$
|
79.51
|
|
Natural gas (per Mcf)
|
2.46
|
|
|
3.75
|
|
|
4.45
|
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
31.51
|
|
|||
Combined (per Boe)
|
44.98
|
|
|
58.27
|
|
|
50.73
|
|
|||
Average Costs ($ per Boe):
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
4.58
|
|
|
$
|
6.48
|
|
|
$
|
6.62
|
|
Gathering, transportation and processing expense
(2)
|
0.39
|
|
|
0.53
|
|
|
3.89
|
|
|||
Total production costs excluding production taxes
|
$
|
4.97
|
|
|
$
|
7.01
|
|
|
$
|
10.51
|
|
Production tax expense
|
1.75
|
|
|
1.85
|
|
|
3.44
|
|
|||
Depreciation, depletion and amortization
|
28.18
|
|
|
31.14
|
|
|
25.88
|
|
|||
General and administrative
(3)
|
6.92
|
|
|
8.17
|
|
|
5.86
|
|
(1)
|
The DJ Basin and the Uinta Oil Program in the Uinta Basin were the only development areas that contained 15% or more of our total proved reserves as of
December 31, 2016
, 2015 and 2014.
|
(2)
|
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of our Piceance Basin assets in September 2014 (see Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures). Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of our divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and
|
(3)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of
$11.9 million
(or
$1.96
per Boe),
$10.8 million
(or
$1.64
per Boe) and
$11.4 million
(or
$1.25
per Boe) for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
|
|
Oil
|
|
Gas
|
||||||||
Basin/Area
|
|
Gross Wells
|
|
Net Wells
|
|
Gross Wells
|
|
Net Wells
|
||||
DJ
|
|
271.0
|
|
|
173.3
|
|
|
28.0
|
|
|
19.3
|
|
Uinta Oil Program
|
|
118.0
|
|
|
88.6
|
|
|
—
|
|
|
—
|
|
Other
|
|
11.0
|
|
|
4.9
|
|
|
3.0
|
|
|
1.0
|
|
Total
|
|
400.0
|
|
|
266.8
|
|
|
31.0
|
|
|
20.3
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
||||||||
Basin/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||
DJ
|
|
35,539
|
|
|
26,149
|
|
|
57,427
|
|
|
29,788
|
|
(1)
|
Uinta Oil Program
|
|
14,221
|
|
|
11,914
|
|
|
21,233
|
|
|
12,334
|
|
|
Other
|
|
4,350
|
|
|
2,296
|
|
|
319,235
|
|
|
171,791
|
|
(2)
|
Total
|
|
54,110
|
|
|
40,359
|
|
|
397,895
|
|
|
213,913
|
|
|
(1)
|
Amounts shown for the DJ Basin do not include an additional
2,553
gross and
1,518
net undeveloped acres that are subject to drill-to-earn agreements.
|
(2)
|
Other includes
71,228
and
63,367
net undeveloped acres in the Paradox and Deseret Basins, respectively.
|
|
|
Net Undeveloped Acres Expiring
|
||||||||||||||||
Basin/Area
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
||||||
DJ
|
|
5,962
|
|
|
2,637
|
|
|
3,182
|
|
|
4,720
|
|
|
13,287
|
|
|
29,788
|
|
Uinta Oil Program
|
|
1,305
|
|
|
530
|
|
|
365
|
|
|
47
|
|
|
10,087
|
|
|
12,334
|
|
Other
|
|
18,440
|
|
|
53,216
|
|
|
21,278
|
|
|
2,019
|
|
|
76,838
|
|
|
171,791
|
|
Total
|
|
25,707
|
|
|
56,383
|
|
|
24,825
|
|
|
6,786
|
|
|
100,212
|
|
|
213,913
|
|
Type of Arrangement
|
|
Pipeline System / Location
|
|
Deliverable Market
|
|
Gross Deliveries (MMBtu/d)
|
|
Term
|
Firm Transport
|
|
Questar Overthrust
|
|
Rocky Mountains
|
|
50,000
|
|
08/11 – 07/21
|
Firm Transport
|
|
Ruby Pipeline
|
|
West Coast
|
|
50,000
|
|
08/11 – 07/21
|
•
|
require the acquisition of various permits before drilling commences;
|
•
|
require the installation of effective emission control equipment;
|
•
|
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
|
•
|
limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and
|
•
|
require measures to prevent pollution from current operations, such as E&P waste management, transportation and disposal requirements;
|
•
|
require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
|
•
|
impose substantial penalties for any non-compliance with federal, state and local laws and regulations;
|
•
|
impose substantial liabilities for any pollution resulting from our operations;
|
•
|
with respect to operations affecting federal lands or leases, require time consuming environmental analysis with uncertain outcomes;
|
•
|
expose us to litigation by environmental and other special interest groups; and
|
•
|
impose certain compliance and regulatory reporting requirements.
|
•
|
the location of wells and surface facilities;
|
•
|
the noise, traffic and light from the location;
|
•
|
the method of drilling and casing wells;
|
•
|
the rates of production or "allowables";
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
wildlife management and protection;
|
•
|
the protection of archeological and paleontological resources;
|
•
|
the plugging and abandoning of wells; and
|
•
|
notice to, and consultation with, surface owners and other third parties.
|
•
|
the global demand for oil, natural gas and NGLs;
|
•
|
domestic and foreign governmental regulations;
|
•
|
variations between product prices at sales points and applicable index prices;
|
•
|
political and economic conditions in oil producing countries, including the Middle East and South America;
|
•
|
the ability and willingness of members of the Organization of Petroleum Exporting Countries ("OPEC") to agree to and maintain oil price and production controls;
|
•
|
weather conditions;
|
•
|
technological advances affecting energy consumption;
|
•
|
national and global economic conditions;
|
•
|
proximity and capacity of oil and gas pipelines, refineries and other transportation and processing facilities;
|
•
|
the price and availability of alternative fuels; and
|
•
|
the strength of the U.S. dollar compared to other currencies.
|
•
|
environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
|
•
|
abnormally pressured or structured formations;
|
•
|
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
|
•
|
fires, explosions and ruptures of pipelines;
|
•
|
personal injuries and death; and
|
•
|
natural disasters.
|
•
|
injury or loss of life;
|
•
|
damage to and destruction of property and equipment;
|
•
|
damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;
|
•
|
pollution and other environmental damage, including spillage or mishandling of recovered hydrocarbons, hydraulic fracturing fluids and produced water;
|
•
|
regulatory investigations and penalties;
|
•
|
suspension of our operations; and
|
•
|
repair and remediation costs.
|
•
|
our proved reserves;
|
•
|
the level of oil, natural gas and NGLs we are able to produce from existing wells;
|
•
|
the prices at which oil, natural gas and NGLs are sold;
|
•
|
the costs required to operate production;
|
•
|
our ability to acquire, locate and produce new reserves;
|
•
|
global credit and securities markets;
|
•
|
the ability and willingness of lenders and investors to provide capital and the cost of that capital; and
|
•
|
the interest of buyers in our properties and the price they are willing to pay for properties.
|
•
|
The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. Significant recent commodity price declines have been caused in part by concerns about future global economic growth. This factor has at times been exacerbated by increases in oil and gas supply resulting from increases in U.S. oil and gas production.
|
•
|
The lenders under our Amended Credit Facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.
|
•
|
We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.
|
•
|
The losses incurred by financial institutions as well as the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.
|
•
|
Our credit facility bears floating interest rates based on the London Interbank Offer Rate ("LIBOR"). As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. Such increases caused and may in the future cause higher interest expense for unhedged levels of LIBOR-based borrowings.
|
•
|
Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced. This would reduce our funds available to borrow. In addition, the lenders can request an interim redetermination during each six month period which could reduce the funds available to borrow under our credit facility.
|
•
|
Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash and cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.
|
•
|
Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.
|
•
|
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
|
•
|
our production is less than we expect;
|
•
|
there is a change in the mark to market value of our derivatives; or
|
•
|
the counterparty to the hedging contract defaults on its contractual obligations.
|
•
|
giving the board the exclusive right to fill all board vacancies;
|
•
|
requiring special meetings of stockholders to be called only by the board;
|
•
|
requiring advance notice for stockholder proposals and director nominations;
|
•
|
prohibiting stockholder action by written consent;
|
•
|
prohibiting cumulative voting in the election of directors; and
|
•
|
allowing for authorized but unissued common and preferred shares.
|
•
|
refinancing or restructuring our debt;
|
•
|
selling assets;
|
•
|
reducing or delaying capital investments; or
|
•
|
seeking to raise additional capital.
|
•
|
increase our costs of doing business;
|
•
|
increase our vulnerability to general adverse economic and industry conditions;
|
•
|
limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;
|
•
|
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
|
•
|
impair our ability to obtain additional financing in the future; and
|
•
|
place us at a competitive disadvantage compared to our competitors that have less debt.
|
•
|
the repeal of the percentage depletion allowance for oil, natural gas and NGL properties;
|
•
|
the elimination of current deductions for intangible drilling and development costs;
|
•
|
the elimination of the deduction for certain U.S. production activities; and
|
•
|
an extension of the amortization period for certain geological and geophysical expenditures.
|
Item 5.
|
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
|
|
High
|
|
Low
|
||||
2016
|
|
|
|
||||
First Quarter
|
$
|
6.48
|
|
|
$
|
2.19
|
|
Second Quarter
|
9.38
|
|
|
5.26
|
|
||
Third Quarter
|
7.02
|
|
|
4.88
|
|
||
Fourth Quarter
|
8.24
|
|
|
4.61
|
|
||
2015
|
|
|
|
||||
First Quarter
|
$
|
13.36
|
|
|
$
|
7.90
|
|
Second Quarter
|
11.72
|
|
|
7.44
|
|
||
Third Quarter
|
8.64
|
|
|
2.75
|
|
||
Fourth Quarter
|
7.04
|
|
|
3.30
|
|
Period
|
|
Total
Number of
Shares Purchased
(1)
|
|
Weighted
Average Price
Paid Per
Share
|
|
Total Number of Shares
Purchased as
Part of Publicly
Announced Plans or
Programs
|
|
Maximum Number (or
Approximate Dollar Value)
of Shares that
May Yet be Purchased
Under the Plans or
Programs
|
|||||
October 1 - 31, 2016
|
|
935
|
|
|
$
|
5.17
|
|
|
0
|
|
|
0
|
|
November 1 - 30, 2016
|
|
808
|
|
|
$
|
6.73
|
|
|
0
|
|
|
0
|
|
December 1 - 31, 2016
|
|
913
|
|
|
$
|
6.68
|
|
|
0
|
|
|
0
|
|
Total
|
|
2,656
|
|
|
$
|
6.16
|
|
|
0
|
|
|
0
|
|
(1)
|
Represents shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.
|
1.
|
$100 was invested in our common stock on
December 31, 2011
, and $100 was invested in each of the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors 500 Index at the closing price on
December 31, 2011
. Due to our common stock being categorized as small cap energy as of September 30, 2014, the industry index of Standard & Poors SmallCap 600-Energy Sector replaced Standard & Poors MidCap 400 Index-Energy Sector.
|
2.
|
Dividends are reinvested on the ex-dividend dates.
|
|
December 31,
2011 |
|
December 31,
2012 |
|
December 31,
2013 |
|
December 31,
2014 |
|
December 31,
2015 |
|
December 31,
2016 |
||||||||||||
BBG
|
$
|
100
|
|
|
$
|
52
|
|
|
$
|
79
|
|
|
$
|
33
|
|
|
$
|
12
|
|
|
$
|
21
|
|
S&P SmallCap 600- Energy
|
100
|
|
|
100
|
|
|
138
|
|
|
88
|
|
|
46
|
|
|
63
|
|
||||||
S&P MidCap 400- Energy
|
100
|
|
|
99
|
|
|
124
|
|
|
92
|
|
|
60
|
|
|
72
|
|
||||||
S&P 500
|
100
|
|
|
113
|
|
|
147
|
|
|
164
|
|
|
163
|
|
|
178
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, gas and NGL production
(1)
|
$
|
178,328
|
|
|
$
|
204,537
|
|
|
$
|
464,137
|
|
|
$
|
565,555
|
|
|
$
|
700,639
|
|
Other operating revenues
|
491
|
|
|
3,355
|
|
|
8,154
|
|
|
2,538
|
|
|
(444
|
)
|
|||||
Total operating revenues
|
178,819
|
|
|
207,892
|
|
|
472,291
|
|
|
568,093
|
|
|
700,195
|
|
|||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expense
|
27,886
|
|
|
42,753
|
|
|
60,308
|
|
|
70,217
|
|
|
72,734
|
|
|||||
Gathering, transportation and processing expense
|
2,365
|
|
|
3,482
|
|
|
35,437
|
|
|
67,269
|
|
|
106,548
|
|
|||||
Production tax expense
|
10,638
|
|
|
12,197
|
|
|
31,333
|
|
|
27,172
|
|
|
25,513
|
|
|||||
Exploration expense
|
83
|
|
|
153
|
|
|
453
|
|
|
337
|
|
|
8,814
|
|
|||||
Impairment, dry hole costs and abandonment expense
|
4,249
|
|
|
575,310
|
|
|
46,881
|
|
|
238,398
|
|
|
67,869
|
|
|||||
(Gain) loss on sale of properties
|
1,078
|
|
|
1,745
|
|
|
100,407
|
|
|
—
|
|
|
—
|
|
|||||
Depreciation, depletion and amortization expense
|
171,641
|
|
|
205,275
|
|
|
235,805
|
|
|
279,775
|
|
|
326,842
|
|
|||||
Unused commitments
|
18,272
|
|
|
19,099
|
|
|
4,434
|
|
|
—
|
|
|
—
|
|
|||||
General and administrative expense
(2)
|
42,169
|
|
|
53,890
|
|
|
53,361
|
|
|
64,902
|
|
|
68,666
|
|
|||||
Other operating expenses, net
|
(316
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total operating expenses
|
278,065
|
|
|
913,904
|
|
|
568,419
|
|
|
748,070
|
|
|
676,986
|
|
|||||
Operating Income (Loss)
|
(99,246
|
)
|
|
(706,012
|
)
|
|
(96,128
|
)
|
|
(179,977
|
)
|
|
23,209
|
|
|||||
Other Income and Expense:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and other income
|
235
|
|
|
565
|
|
|
1,294
|
|
|
1,646
|
|
|
155
|
|
|||||
Interest expense
|
(59,373
|
)
|
|
(65,305
|
)
|
|
(69,623
|
)
|
|
(88,507
|
)
|
|
(95,506
|
)
|
|||||
Commodity derivative gain (loss)
|
(20,720
|
)
|
|
104,147
|
|
|
197,447
|
|
|
(23,068
|
)
|
|
72,759
|
|
|||||
Gain (loss) on extinguishment of debt
|
8,726
|
|
|
1,749
|
|
|
—
|
|
|
(21,460
|
)
|
|
1,601
|
|
|||||
Total other income and expense
|
(71,132
|
)
|
|
41,156
|
|
|
129,118
|
|
|
(131,389
|
)
|
|
(20,991
|
)
|
|||||
Income (Loss) before Income Taxes
|
(170,378
|
)
|
|
(664,856
|
)
|
|
32,990
|
|
|
(311,366
|
)
|
|
2,218
|
|
|||||
(Provision for) Benefit from Income Taxes
|
—
|
|
|
177,085
|
|
|
(17,909
|
)
|
|
118,633
|
|
|
(1,636
|
)
|
|||||
Net Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
|
$
|
(192,733
|
)
|
|
$
|
582
|
|
Net Income (Loss) per Common Share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
|
$
|
(4.06
|
)
|
|
$
|
0.01
|
|
Diluted
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
|
$
|
(4.06
|
)
|
|
$
|
0.01
|
|
Weighted average common shares outstanding, basic
|
55,384
|
|
|
48,303
|
|
|
48,011
|
|
|
47,497
|
|
|
47,195
|
|
|||||
Weighted average common shares outstanding, diluted
|
55,384
|
|
|
48,303
|
|
|
48,436
|
|
|
47,497
|
|
|
47,354
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Selected Cash Flow and Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
|
$
|
(192,733
|
)
|
|
$
|
582
|
|
Depreciation, depletion, impairment and amortization
|
171,824
|
|
|
777,713
|
|
|
275,988
|
|
|
506,326
|
|
|
364,190
|
|
|||||
Other non-cash items
|
124,552
|
|
|
(83,760
|
)
|
|
(59,970
|
)
|
|
(32,600
|
)
|
|
29,281
|
|
|||||
Change in assets and liabilities
|
(4,262
|
)
|
|
(12,504
|
)
|
|
30,618
|
|
|
(15,728
|
)
|
|
(5,617
|
)
|
|||||
Net cash provided by operating activities
|
$
|
121,736
|
|
|
$
|
193,678
|
|
|
$
|
261,717
|
|
|
$
|
265,265
|
|
|
$
|
388,436
|
|
Capital expenditures
(3)(4)(5)
|
$
|
98,292
|
|
|
$
|
287,411
|
|
|
$
|
569,312
|
|
|
$
|
474,031
|
|
|
$
|
962,573
|
|
(1)
|
The oil, gas and NGL production revenue decrease reflects the decrease in revenues due to the divestitures outlined in Note
4
to the Consolidated Financial Statements and the decrease in commodity price. In addition, oil, gas and NGL production revenues include the effects of cash flow hedging transactions for the years ended December 31, 2014, 2013 and 2012. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income ("AOCI") effective January 1, 2012 and remained in AOCI until the underlying transaction occurred. As the underlying transaction occurred, these gains or losses were reclassified from AOCI into oil and gas production revenues.
|
(2)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of
$11.9 million
,
$10.8 million
,
$11.4 million
,
$15.8 million
and
$16.4 million
for the years ended
December 31, 2016
,
2015
,
2014
,
2013
and
2012
, respectively.
|
(3)
|
Excludes future reclamation liabilities, net of liabilities sold, of negative
$3.7 million
, negative
$7.5 million
, negative
$8.6 million
, negative
$6.6 million
and
$7.5 million
for the years ended
December 31, 2016
,
2015
,
2014
,
2013
and
2012
, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of
$4.1 million
,
$3.0 million
,
$7.2 million
,
$12.2 million
and
$39.3 million
for the years ended
December 31, 2016
,
2015
,
2014
,
2013
and
2012
, respectively. Also includes furniture, fixtures and equipment costs of
$1.1 million
,
$1.3 million
,
$3.7 million
,
$1.3 million
and
$6.9 million
for the years ended
December 31, 2016
,
2015
,
2014
,
2013
and
2012
, respectively.
|
(4)
|
Not deducted from the amount are
$25.1 million
,
$123.3 million
,
$555.4 million
,
$306.3 million
and
$325.3 million
of proceeds received principally from the sale of interests in oil and gas properties during the years ended
December 31, 2016
,
2015
,
2014
,
2013
and
2012
, respectively.
|
(5)
|
Capital expenditures for the year ended December 31, 2014 exclude $79.0 million related to property acquired through property exchanges.
|
|
As of December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
275,841
|
|
|
$
|
128,836
|
|
|
$
|
165,904
|
|
|
$
|
54,595
|
|
|
$
|
79,445
|
|
Other current assets
|
42,611
|
|
|
145,481
|
|
|
260,201
|
|
|
102,652
|
|
|
148,894
|
|
|||||
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment
|
1,055,049
|
|
|
1,160,898
|
|
|
1,730,172
|
|
|
2,184,183
|
|
|
2,584,979
|
|
|||||
Other property and equipment, net of depreciation
|
7,100
|
|
|
9,786
|
|
|
13,715
|
|
|
18,313
|
|
|
26,358
|
|
|||||
Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment
|
—
|
|
|
—
|
|
|
9,234
|
|
|
—
|
|
|
—
|
|
|||||
Other assets
(1)
|
4,740
|
|
|
61,519
|
|
|
54,822
|
|
|
9,537
|
|
|
12,429
|
|
|||||
Total assets
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
|
$
|
2,234,048
|
|
|
$
|
2,369,280
|
|
|
$
|
2,852,105
|
|
Current liabilities
|
$
|
85,018
|
|
|
$
|
145,231
|
|
|
$
|
264,687
|
|
|
$
|
192,719
|
|
|
$
|
213,133
|
|
Long-term debt, net of debt issuance costs
(1)
|
711,808
|
|
|
794,652
|
|
|
792,786
|
|
|
966,849
|
|
|
1,139,310
|
|
|||||
Other long-term liabilities
|
16,972
|
|
|
17,221
|
|
|
147,087
|
|
|
203,994
|
|
|
316,887
|
|
|||||
Stockholders' equity
|
571,543
|
|
|
549,416
|
|
|
1,029,488
|
|
|
1,005,718
|
|
|
1,182,775
|
|
|||||
Total liabilities and stockholders' equity
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
|
$
|
2,234,048
|
|
|
$
|
2,369,280
|
|
|
$
|
2,852,105
|
|
(1)
|
We adopted ASU 2015-03 and ASU 2015-15 effective January 1, 2016, which required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability and as a result, $8.7 million, $10.4 million, $12.2 million and $17.3 million of debt issuance costs related to our long-term debt were reclassified from deferred financing costs and other noncurrent assets to long-term debt in our consolidated balance sheet as of December 31, 2015, 2014, 2013 and 2012, respectively.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Estimated net proved reserves (MMBoe)
|
54.9
|
|
|
83.7
|
|
|
122.3
|
|
|||
Standardized measure
(1)
(in millions)
|
$
|
329.3
|
|
|
$
|
327.6
|
|
|
$
|
1,169.6
|
|
(1)
|
December 31, 2016
reserves were based on average prices of
$42.75
WTI per Bbl of oil,
$2.48
Henry Hub per Mcf of natural gas and
$19.70
per Bbl of NGLs.
December 31, 2015
reserves were based on average prices of
$50.28
WTI for oil,
$2.59
Henry Hub for natural gas and
$20.37
for NGLs.
December 31, 2014
reserves were based on average prices of
$94.99
WTI for oil,
$4.35
Henry Hub for natural gas and
$39.65
for NGLs.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Oil (per Bbl)
|
$
|
38.83
|
|
|
$
|
40.06
|
|
|
$
|
77.92
|
|
Natural gas (per Mcf)
|
1.98
|
|
|
2.23
|
|
|
4.78
|
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
31.55
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Oil (per Bbl)
|
$
|
62.56
|
|
|
$
|
78.19
|
|
|
$
|
79.51
|
|
Natural gas (per Mcf)
|
2.46
|
|
|
3.75
|
|
|
4.45
|
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
31.51
|
|
|
Year Ended December 31,
|
|
Increase (Decrease)
|
|||||||||||
2016
|
|
2015
|
|
Amount
|
|
Percent
|
||||||||
($ in thousands, except per unit data)
|
||||||||||||||
Operating Results:
|
|
|
|
|
|
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
|
|||||||
Oil, gas and NGL production
|
$
|
178,328
|
|
|
$
|
204,537
|
|
|
$
|
(26,209
|
)
|
|
(13
|
)%
|
Other operating revenues
|
491
|
|
|
3,355
|
|
|
(2,864
|
)
|
|
(85
|
)%
|
|||
Total operating revenues
|
$
|
178,819
|
|
|
$
|
207,892
|
|
|
$
|
(29,073
|
)
|
|
(14
|
)%
|
Operating Expenses
|
|
|
|
|
|
|
|
|||||||
Lease operating expense
|
$
|
27,886
|
|
|
$
|
42,753
|
|
|
$
|
(14,867
|
)
|
|
(35
|
)%
|
Gathering, transportation and processing expense
|
2,365
|
|
|
3,482
|
|
|
(1,117
|
)
|
|
(32
|
)%
|
|||
Production tax expense
|
10,638
|
|
|
12,197
|
|
|
(1,559
|
)
|
|
(13
|
)%
|
|||
Exploration expense
|
83
|
|
|
153
|
|
|
(70
|
)
|
|
(46
|
)%
|
|||
Impairment, dry hole costs and abandonment expense
|
4,249
|
|
|
575,310
|
|
|
(571,061
|
)
|
|
(99
|
)%
|
|||
(Gain) loss on sale of properties
|
1,078
|
|
|
1,745
|
|
|
(667
|
)
|
|
(38
|
)%
|
|||
Depreciation, depletion and amortization
|
171,641
|
|
|
205,275
|
|
|
(33,634
|
)
|
|
(16
|
)%
|
|||
Unused commitments
|
18,272
|
|
|
19,099
|
|
|
(827
|
)
|
|
(4
|
)%
|
|||
General and administrative expense
(1)
|
42,169
|
|
|
53,890
|
|
|
(11,721
|
)
|
|
(22
|
)%
|
|||
Other operating expenses, net
|
(316
|
)
|
|
—
|
|
|
(316
|
)
|
|
*nm
|
|
|||
Total operating expenses
|
$
|
278,065
|
|
|
$
|
913,904
|
|
|
$
|
(635,839
|
)
|
|
(70
|
)%
|
Production Data:
|
|
|
|
|
|
|
|
|||||||
Oil (MBbls)
|
3,885
|
|
|
4,401
|
|
|
(516
|
)
|
|
(12
|
)%
|
|||
Natural gas (MMcf)
|
7,170
|
|
|
7,764
|
|
|
(594
|
)
|
|
(8
|
)%
|
|||
NGLs (MBbls)
|
1,010
|
|
|
898
|
|
|
112
|
|
|
12
|
%
|
|||
Combined volumes (MBoe)
|
6,090
|
|
|
6,593
|
|
|
(503
|
)
|
|
(8
|
)%
|
|||
Daily combined volumes (Boe/d)
|
16,639
|
|
|
18,063
|
|
|
(1,424
|
)
|
|
(8
|
)%
|
|||
Average Realized Prices before Hedging:
|
|
|
|
|
|
|
|
|||||||
Oil (per Bbl)
|
$
|
38.83
|
|
|
$
|
40.06
|
|
|
$
|
(1.23
|
)
|
|
(3
|
)%
|
Natural gas (per Mcf)
|
1.98
|
|
|
2.23
|
|
|
(0.25
|
)
|
|
(11
|
)%
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
0.99
|
|
|
8
|
%
|
|||
Combined (per Boe)
|
29.28
|
|
|
31.02
|
|
|
(1.74
|
)
|
|
(6
|
)%
|
|||
Average Realized Prices with Hedging:
|
|
|
|
|
|
|
|
|||||||
Oil (per Bbl)
|
$
|
62.56
|
|
|
$
|
78.19
|
|
|
$
|
(15.63
|
)
|
|
(20
|
)%
|
Natural gas (per Mcf)
|
2.46
|
|
|
3.75
|
|
|
(1.29
|
)
|
|
(34
|
)%
|
|||
NGLs (per Bbl)
|
13.15
|
|
|
12.16
|
|
|
0.99
|
|
|
8
|
%
|
|||
Combined (per Boe)
|
44.98
|
|
|
58.27
|
|
|
(13.29
|
)
|
|
(23
|
)%
|
|||
Average Costs (per Boe):
|
|
|
|
|
|
|
|
|||||||
Lease operating expense
|
$
|
4.58
|
|
|
$
|
6.48
|
|
|
$
|
(1.90
|
)
|
|
(29
|
)%
|
Gathering, transportation and processing expense
|
0.39
|
|
|
0.53
|
|
|
(0.14
|
)
|
|
(26
|
)%
|
|||
Production tax expense
|
1.75
|
|
|
1.85
|
|
|
(0.10
|
)
|
|
(5
|
)%
|
|||
Depreciation, depletion and amortization
|
28.18
|
|
|
31.14
|
|
|
(2.96
|
)
|
|
(10
|
)%
|
|||
General and administrative expense
(1)
|
6.92
|
|
|
8.17
|
|
|
(1.25
|
)
|
|
(15
|
)%
|
*
|
Not meaningful.
|
(1)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of
$11.9 million
(or
$1.96
per Boe) and
$10.8 million
(or
$1.64
per Boe) for the years ended
December 31, 2016
and
2015
, respectively.
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
|
% Increase (Decrease)
|
|||||||||||||||||||||
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
||||||||||||
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
||||||||||||
DJ Basin
|
3,050
|
|
966
|
|
6,228
|
|
5,054
|
|
|
2,958
|
|
815
|
|
6,012
|
|
4,775
|
|
|
3
|
%
|
19
|
%
|
4
|
%
|
6
|
%
|
Uinta Oil Program
|
830
|
|
42
|
|
900
|
|
1,022
|
|
|
1,420
|
|
82
|
|
1,728
|
|
1,790
|
|
|
(42
|
)%
|
(49
|
)%
|
(48
|
)%
|
(43
|
)%
|
Other
|
5
|
|
2
|
|
42
|
|
14
|
|
|
23
|
|
1
|
|
24
|
|
28
|
|
|
(78
|
)%
|
100
|
%
|
75
|
%
|
(50
|
)%
|
Total
|
3,885
|
|
1,010
|
|
7,170
|
|
6,090
|
|
|
4,401
|
|
898
|
|
7,764
|
|
6,593
|
|
|
(12
|
)%
|
12
|
%
|
(8
|
)%
|
(8
|
)%
|
|
Year Ended December 31,
|
|
||||||
|
2016
|
|
2015
|
|
||||
|
(in thousands)
|
|
||||||
Non-cash impairment of proved oil and gas properties
|
$
|
—
|
|
|
$
|
559,282
|
|
(1)
|
Non-cash impairment of unproved oil and gas properties
|
183
|
|
|
13,156
|
|
(1)
|
||
Dry hole costs
|
97
|
|
|
123
|
|
|
||
Abandonment expense
|
3,969
|
|
|
2,749
|
|
|
||
Total non-cash impairment, dry hole costs and abandonment expense
|
$
|
4,249
|
|
|
$
|
575,310
|
|
|
(1)
|
Due to the decline in oil prices, we recognized a non-cash impairment charge associated with the proved and unproved oil and gas properties in the Uinta Oil Program for the year ended December 31, 2015.
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Stock options and nonvested common stock
|
$
|
8,573
|
|
|
$
|
9,025
|
|
Shares issued for 401(k) plan
(1)
|
—
|
|
|
273
|
|
||
Nonvested common stock units
|
883
|
|
|
1,115
|
|
||
Performance cash units
(2)
|
2,485
|
|
|
427
|
|
||
Total
|
$
|
11,941
|
|
|
$
|
10,840
|
|
(1)
|
Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.
|
(2)
|
The performance cash units will be settled in cash for the performance metrics that are met.
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Realized gain (loss) on derivatives
|
$
|
95,598
|
|
|
$
|
179,652
|
|
Prior year unrealized (gain) loss transferred to realized (gain) loss
|
(99,809
|
)
|
|
(145,226
|
)
|
||
Unrealized gain (loss) on derivatives
|
(16,509
|
)
|
|
69,721
|
|
||
Total commodity derivative gain (loss)
|
$
|
(20,720
|
)
|
|
$
|
104,147
|
|
|
Year Ended December 31,
|
|
Increase (Decrease)
|
|||||||||||
2015
|
|
2014
|
|
Amount
|
|
Percent
|
||||||||
($ in thousands, except per unit data)
|
||||||||||||||
Operating Results:
|
|
|
|
|
|
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
|
|||||||
Oil, gas and NGL production
(1)
|
$
|
204,537
|
|
|
$
|
464,137
|
|
|
$
|
(259,600
|
)
|
|
(56
|
)%
|
Other operating revenues
|
3,355
|
|
|
8,154
|
|
|
(4,799
|
)
|
|
(59
|
)%
|
|||
Total operating revenues
|
$
|
207,892
|
|
|
$
|
472,291
|
|
|
$
|
(264,399
|
)
|
|
(56
|
)%
|
Operating Expenses
|
|
|
|
|
|
|
|
|||||||
Lease operating expense
|
$
|
42,753
|
|
|
$
|
60,308
|
|
|
$
|
(17,555
|
)
|
|
(29
|
)%
|
Gathering, transportation and processing expense
(2)
|
3,482
|
|
|
35,437
|
|
|
(31,955
|
)
|
|
*nm
|
|
|||
Production tax expense
|
12,197
|
|
|
31,333
|
|
|
(19,136
|
)
|
|
(61
|
)%
|
|||
Exploration expense
|
153
|
|
|
453
|
|
|
(300
|
)
|
|
(66
|
)%
|
|||
Impairment, dry hole costs and abandonment expense
|
575,310
|
|
|
46,881
|
|
|
528,429
|
|
|
*nm
|
|
|||
(Gain) loss on sale of properties
|
1,745
|
|
|
100,407
|
|
|
(98,662
|
)
|
|
(98
|
)%
|
|||
Depreciation, depletion and amortization
|
205,275
|
|
|
235,805
|
|
|
(30,530
|
)
|
|
(13
|
)%
|
|||
Unused commitments
(2)
|
19,099
|
|
|
4,434
|
|
|
14,665
|
|
|
*nm
|
|
|||
General and administrative expense
(3)
|
53,890
|
|
|
53,361
|
|
|
529
|
|
|
1
|
%
|
|||
Total operating expenses
|
$
|
913,904
|
|
|
$
|
568,419
|
|
|
$
|
345,485
|
|
|
61
|
%
|
Production Data:
|
|
|
|
|
|
|
|
|||||||
Oil (MBbls)
|
4,401
|
|
|
4,012
|
|
|
389
|
|
|
10
|
%
|
|||
Natural gas (MMcf)
|
7,764
|
|
|
21,744
|
|
|
(13,980
|
)
|
|
(64
|
)%
|
|||
NGLs (MBbls)
|
898
|
|
|
1,476
|
|
|
(578
|
)
|
|
(39
|
)%
|
|||
Combined volumes (MBoe)
|
6,593
|
|
|
9,112
|
|
|
(2,519
|
)
|
|
(28
|
)%
|
|||
Daily combined volumes (Boe/d)
|
18,063
|
|
|
24,964
|
|
|
(6,901
|
)
|
|
(28
|
)%
|
|||
Average Realized Prices before Hedging:
|
|
|
|
|
|
|
|
|||||||
Oil (per Bbl)
|
$
|
40.06
|
|
|
$
|
77.92
|
|
|
$
|
(37.86
|
)
|
|
(49
|
)%
|
Natural gas (per Mcf)
|
2.23
|
|
|
4.78
|
|
|
(2.55
|
)
|
|
(53
|
)%
|
|||
NGLs (per Bbl)
|
12.16
|
|
|
31.55
|
|
|
(19.39
|
)
|
|
(61
|
)%
|
|||
Combined (per Boe)
|
31.02
|
|
|
50.82
|
|
|
(19.80
|
)
|
|
(39
|
)%
|
|||
Average Realized Prices with Hedging:
|
|
|
|
|
|
|
|
|||||||
Oil (per Bbl)
|
$
|
78.19
|
|
|
$
|
79.51
|
|
|
$
|
(1.32
|
)
|
|
(2
|
)%
|
Natural gas (per Mcf)
|
3.75
|
|
|
4.45
|
|
|
(0.70
|
)
|
|
(16
|
)%
|
|||
NGLs (per Bbl)
|
12.16
|
|
|
31.51
|
|
|
(19.35
|
)
|
|
(61
|
)%
|
|||
Combined (per Boe)
|
58.27
|
|
|
50.73
|
|
|
7.54
|
|
|
15
|
%
|
|||
Average Costs (per Boe):
|
|
|
|
|
|
|
|
|||||||
Lease operating expense
|
$
|
6.48
|
|
|
$
|
6.62
|
|
|
$
|
(0.14
|
)
|
|
(2
|
)%
|
Gathering, transportation and processing expense
(2)
|
0.53
|
|
|
3.89
|
|
|
(3.36
|
)
|
|
(86
|
)%
|
|||
Production tax expense
|
1.85
|
|
|
3.44
|
|
|
(1.59
|
)
|
|
(46
|
)%
|
|||
Depreciation, depletion and amortization
|
31.14
|
|
|
25.88
|
|
|
5.26
|
|
|
20
|
%
|
|||
General and administrative expense
(3)
|
8.17
|
|
|
5.86
|
|
|
2.31
|
|
|
39
|
%
|
*
|
Not meaningful.
|
(1)
|
See the below production revenues and volumes for additional information related to revenue and production.
|
(2)
|
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in September 2014 (see Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures). Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Consolidated Statements of Operations.
|
(3)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of $10.8 million (or $1.64 per Boe) and $11.4 million (or $1.25 per Boe) for the years ended December 31, 2015 and 2014, respectively.
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
|
% Increase (Decrease)
|
|||||||||||||||||||||
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
||||||||||||
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
||||||||||||
DJ Basin
|
2,958
|
|
815
|
|
6,012
|
|
4,775
|
|
|
1,682
|
|
423
|
|
4,224
|
|
2,809
|
|
|
76
|
%
|
93
|
%
|
42
|
%
|
70
|
%
|
Uinta Oil Program
|
1,420
|
|
82
|
|
1,728
|
|
1,790
|
|
|
1,821
|
|
119
|
|
2,220
|
|
2,310
|
|
|
(22
|
)%
|
(31
|
)%
|
(22
|
)%
|
(23
|
)%
|
Other
(1)
|
23
|
|
1
|
|
24
|
|
28
|
|
|
509
|
|
934
|
|
15,300
|
|
3,993
|
|
|
*nm
|
|
*nm
|
|
*nm
|
|
*nm
|
|
Total
|
4,401
|
|
898
|
|
7,764
|
|
6,593
|
|
|
4,012
|
|
1,476
|
|
21,744
|
|
9,112
|
|
|
10
|
%
|
(39
|
)%
|
(64
|
)%
|
(28
|
)%
|
*
|
Not meaningful.
|
(1)
|
Includes oil, NGL and natural gas volumes of 177 MBbls, 911 MBbls and 14,808 MMcf, respectively, from the Piceance Basin and 326 MBbls, 22 MBbls and 480 MMcf, respectively, from the Powder River Basin for the year ended December 31, 2014.
|
|
Year Ended December 31,
|
|
||||||
|
2015
|
|
2014
|
|
||||
|
(in thousands)
|
|
||||||
Non-cash impairment of proved oil and gas properties
|
$
|
559,282
|
|
(1)
|
$
|
15,761
|
|
(2)
|
Non-cash impairment of unproved oil and gas properties
|
13,156
|
|
(1)
|
24,082
|
|
(3)
|
||
Non-cash impairment of inventory
|
—
|
|
|
340
|
|
|
||
Dry hole costs
|
123
|
|
|
101
|
|
|
||
Abandonment expense
|
2,749
|
|
|
6,597
|
|
|
||
Total non-cash impairment, dry hole costs and abandonment expense
|
$
|
575,310
|
|
|
$
|
46,881
|
|
|
(1)
|
Due to the decline in oil prices, we recognized a non-cash impairment charge associated with the proved and unproved oil and gas properties in the Uinta Oil Program for the year ended December 31, 2015.
|
(2)
|
As the result of the Powder River Oil Divestiture, the carrying values of the remaining properties were analyzed relative to their estimated fair market values. As a result, we recognized impairment expense on proved properties of $14.8 million for the year ended December 31, 2014. These properties were classified as held for sale as of December 31, 2014. In addition, $1.0 million of proved property impairment expense was incurred during the year ended December 31, 2014 related to the West Tavaputs Divestiture based upon a true-up of previously estimated carrying value. See Note 4 of the Notes to Consolidated Financial Statements
for more information related to these divestitures.
|
(3)
|
As a result of unsuccessful drilling and completion activity by an industry partner in the Paradox Basin, we recognized impairment expense of $11.6 million during the year ended December 31, 2014 related to the remaining unproved property in the Paradox Basin. We recognized impairment expense of $6.1 million related to certain unproved oil and gas properties in the Uinta Basin as a result of having no future plans to evaluate the acreage. In addition, we recognized impairment expense of $6.4 million as the result of the Powder River Oil Divestiture as discussed above.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Stock options and nonvested common stock
|
$
|
9,025
|
|
|
$
|
9,715
|
|
Shares issued for 401(k) plan
(1)
|
273
|
|
|
600
|
|
||
Nonvested common stock units
|
1,115
|
|
|
1,065
|
|
||
Performance cash units
(2)
|
427
|
|
|
—
|
|
||
Total
|
$
|
10,840
|
|
|
$
|
11,380
|
|
(1)
|
Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.
|
(2)
|
The performance cash units will be settled in cash for the performance metrics that are met. No cash performance units were granted during 2014.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Realized gain (loss) on derivatives
|
$
|
179,652
|
|
|
$
|
(1,888
|
)
|
Prior year unrealized (gain) loss transferred to realized (gain) loss
|
(145,226
|
)
|
|
6,706
|
|
||
Unrealized gain (loss) on derivatives
|
69,721
|
|
|
192,629
|
|
||
Total commodity derivative gain (loss)
|
$
|
104,147
|
|
|
$
|
197,447
|
|
Contract
|
|
Total
Hedged
Volumes
|
|
Quantity
Type
|
|
Weighted
Average
Fixed
Price
|
|
Index
Price
|
|
Fair Market
Value
(in thousands)
|
|||||
Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|||||
2017
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil
|
|
2,222,875
|
|
|
Bbls
|
|
$
|
58.79
|
|
|
WTI
|
|
5,564
|
|
|
Natural gas
|
|
3,650,000
|
|
|
MMbtu
|
|
$
|
2.96
|
|
|
NWPL
|
|
(1,511
|
)
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil
|
|
363,500
|
|
|
Bbls
|
|
$
|
54.04
|
|
|
WTI
|
|
(900
|
)
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
3,153
|
|
Contract
|
Total
Hedged Volumes |
|
Quantity
Type |
|
Weighted
Average Fixed Price |
|
Index
Price |
|||
Swap Contracts:
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|
|||
Oil
|
184,000
|
|
|
Bbls
|
|
$
|
56.19
|
|
|
WTI
|
2018
|
|
|
|
|
|
|
|
|||
Oil
|
500,750
|
|
|
Bbls
|
|
$
|
55.69
|
|
|
WTI
|
|
Year Ended December 31,
|
||||||||||
Basin/Area
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
DJ
|
$
|
95.5
|
|
|
$
|
250.3
|
|
|
$
|
384.0
|
|
Uinta Oil Program
|
1.4
|
|
|
34.6
|
|
|
152.9
|
|
|||
Powder River Oil
|
—
|
|
|
1.1
|
|
|
29.1
|
|
|||
Other
|
1.4
|
|
|
1.4
|
|
|
3.3
|
|
|||
Total
(1)(2)(3)
|
$
|
98.3
|
|
|
$
|
287.4
|
|
|
$
|
569.3
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Acquisitions of proved and unproved properties and other real estate
|
$
|
5.6
|
|
|
$
|
7.7
|
|
|
$
|
15.1
|
|
Drilling, development, exploration and exploitation of oil and natural gas properties
|
86.3
|
|
|
264.3
|
|
|
531.4
|
|
|||
Gathering and compression facilities
|
5.3
|
|
|
11.2
|
|
|
18.6
|
|
|||
Geologic and geophysical costs
|
—
|
|
|
2.9
|
|
|
0.5
|
|
|||
Furniture, fixtures and equipment
|
1.1
|
|
|
1.3
|
|
|
3.7
|
|
|||
Total
(1)(2)(3)
|
$
|
98.3
|
|
|
$
|
287.4
|
|
|
$
|
569.3
|
|
(1)
|
Capital expenditures for the year ended December 31, 2014 exclude $79.0 million related to property acquired through property exchanges.
|
(2)
|
For the years ended
December 31, 2016
,
2015
and
2014
, we received
$25.1 million
,
$123.3 million
and
$555.4 million
, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.
|
(3)
|
Excludes future reclamation liabilities, net of liabilities sold, of negative
$3.7 million
, negative
$7.5 million
and negative
$8.6 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of
$4.1 million
,
$3.0 million
and
$7.2 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
|
|
As of December 31, 2016
|
|
As of December 31, 2015
|
||||||||||||||||||||
|
Maturity Date
|
Principal
|
|
Debt Issuance Costs
|
|
Carrying
Amount |
|
Principal
|
|
Debt Issuance Costs
|
|
Carrying
Amount |
||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||
Amended Credit Facility
|
April 9, 2020
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Convertible Notes
(2)
|
March 15, 2028
(3)
|
579
|
|
|
—
|
|
|
579
|
|
|
579
|
|
|
—
|
|
|
579
|
|
||||||
7.625% Senior Notes
(4)
|
October 1, 2019
|
315,300
|
|
|
(2,169
|
)
|
|
313,131
|
|
|
400,000
|
|
|
(3,752
|
)
|
|
396,248
|
|
||||||
7.0% Senior Notes
(5)
|
October 15, 2022
|
400,000
|
|
|
(4,227
|
)
|
|
395,773
|
|
|
400,000
|
|
|
(4,953
|
)
|
|
395,047
|
|
||||||
Lease Financing Obligation
(6)
|
August 10, 2020
|
2,782
|
|
|
(3
|
)
|
|
2,779
|
|
|
3,222
|
|
|
(4
|
)
|
|
3,218
|
|
||||||
Total Debt
|
|
$
|
718,661
|
|
|
$
|
(6,399
|
)
|
|
$
|
712,262
|
|
|
$
|
803,801
|
|
|
$
|
(8,709
|
)
|
|
$
|
795,092
|
|
Less: Current Portion of Long-Term Debt
(7)
|
|
454
|
|
|
—
|
|
|
454
|
|
|
440
|
|
|
—
|
|
|
440
|
|
||||||
Total Long-Term Debt
|
|
$
|
718,207
|
|
|
$
|
(6,399
|
)
|
|
$
|
711,808
|
|
|
$
|
803,361
|
|
|
$
|
(8,709
|
)
|
|
$
|
794,652
|
|
(1)
|
In April 2015, the definition of "Maturity Date" in the Amended Credit Facility was amended to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of ours in existence as of April 9, 2015 or that may be incurred by us as of a future date, or any permitted refinancing debt in respect thereof.
|
(2)
|
The aggregate estimated fair value of the Convertible Notes was approximately
$0.5 million
as of
December 31, 2016
and
2015
, based on reported market trades of these instruments.
|
(3)
|
We have the right at any time with at least 30 days' notice to call the Convertible Notes at par, and the holders have the right to require us to purchase the notes on each of March 20, 2018 and March 20, 2023.
|
(4)
|
The aggregate estimated fair value of the
7.625%
Senior Notes was approximately
$314.5 million
and
$270.2 million
as of
December 31, 2016
and
2015
, respectively, based on reported market trades of these instruments.
|
(5)
|
The aggregate estimated fair value of the
7.0%
Senior Notes was approximately
$384.5 million
and
$272.0 million
as of
December 31, 2016
and
2015
, respectively, based on reported market trades of these instruments.
|
(6)
|
The aggregate estimated fair value of the Lease Financing Obligation was approximately
$2.6 million
and
$3.1 million
as of
December 31, 2016
and
2015
, respectively. As there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
|
(7)
|
The current portion of long-term debt as of
December 31, 2016
and
2015
includes the current portion of the Lease Financing Obligation.
|
|
Payments Due By Year
|
||||||||||||||||||||||||||
|
Year 1
|
|
Year 2
|
|
Year 3
|
|
Year 4
|
|
Year 5
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
Notes payable
(1)
|
$
|
553
|
|
|
$
|
530
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,083
|
|
7.625% Senior Notes
(2)
|
24,042
|
|
|
24,042
|
|
|
339,342
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
387,426
|
|
|||||||
7.0% Senior Notes
(3)
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
428,000
|
|
|
568,000
|
|
|||||||
Convertible Notes
(4)
|
29
|
|
|
585
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
614
|
|
|||||||
Lease Financing Obligation
(5)
|
537
|
|
|
537
|
|
|
1,825
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,899
|
|
|||||||
Office and office equipment leases and other
(6)(7)
|
5,237
|
|
|
2,665
|
|
|
693
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,595
|
|
|||||||
Firm transportation and processing agreements
(8)
|
18,590
|
|
|
18,691
|
|
|
18,691
|
|
|
18,691
|
|
|
10,902
|
|
|
—
|
|
|
85,565
|
|
|||||||
Asset retirement obligations
(9)
|
535
|
|
|
276
|
|
|
235
|
|
|
51
|
|
|
422
|
|
|
9,719
|
|
|
11,238
|
|
|||||||
Derivative liability
(10)
|
4,346
|
|
|
899
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,245
|
|
|||||||
Total
|
$
|
81,869
|
|
|
$
|
76,225
|
|
|
$
|
388,786
|
|
|
$
|
46,742
|
|
|
$
|
39,324
|
|
|
$
|
437,719
|
|
|
$
|
1,070,665
|
|
(1)
|
Notes payable includes interest on a $26.0 million letter of credit that accrues at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018. There is currently no balance outstanding under our Amended Credit Facility due April 9, 2020.
|
(2)
|
On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. On June 3, 2016, we completed an exchange of notes for shares of our common stock, reducing our aggregate principal balance to
$315.3 million
. We are obligated to make annual interest payments through maturity on October 1, 2019 equal to $24.0 million.
|
(3)
|
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity on October 15, 2022 equal to $28.0 million.
|
(4)
|
Our aggregate remaining principal amount of Convertible Notes was $0.6 million as of
December 31, 2016
. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us, which is expected to occur by 2018.
|
(5)
|
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
|
(6)
|
The lease for our principal offices in Denver extends through March 2019.
|
(7)
|
Includes a contractual obligation of
$1.0 million
related to certain drilling commitments on sold properties.
|
(8)
|
We have entered into contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is
five
years. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the processing facility or pipeline.
|
(9)
|
Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
|
(10)
|
Derivative liabilities represent the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of
December 31, 2016
. The ultimate settlement amounts are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
|
|
For the Year 2017
|
|
For the Year 2018
|
||||||||||
|
Derivative
Volumes |
|
Weighted Average
Price |
|
Derivative
Volumes |
|
Weighted Average
Price |
||||||
Oil (Bbls)
|
2,406,875
|
|
|
$
|
58.59
|
|
|
864,250
|
|
|
$
|
54.99
|
|
Natural Gas (MMbtu)
|
3,650,000
|
|
|
2.96
|
|
|
—
|
|
|
—
|
|
|
|
(a)
|
|
(b)
|
|
(c)
|
||||
Plan Category
|
|
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
|
|
Weighted Averaged
Exercise Price of
Outstanding
Options, Warrants
and Rights
(1)
|
|
Number of Securities
Remaining Available
for Future Issuance
(Excluding Securities
Reflected in Column (a))
|
||||
Equity compensation plans approved by shareholders
|
|
436,170
|
|
|
$
|
30.89
|
|
|
2,116,505
|
|
Equity compensation plans not approved by shareholders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
436,170
|
|
|
$
|
30.89
|
|
|
2,116,505
|
|
(1)
|
The weighted average exercise price relates to the
436,170
outstanding options included in column (a).
|
Report of Independent Registered Public Accounting Firm
|
|
73
|
Consolidated Balance Sheets as of December 31, 2016 and 2015
|
|
74
|
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014
|
|
75
|
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014
|
|
76
|
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014
|
|
77
|
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2016, 2015 and 2014
|
|
78
|
Notes to Consolidated Financial Statements
|
|
79
|
Exhibit
Number
|
|
Description of Exhibits
|
1.1
|
|
Equity Distribution Agreement, dated June 10, 2015, by and between Bill Barrett Corporation and Goldman, Sachs & Co. [Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed with the Commission on June 10, 2015.]
|
|
|
|
3.1*
|
|
Restated Certificate of Incorporation of Bill Barrett Corporation.
|
|
|
|
3.2
|
|
Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on May 15, 2012.]
|
|
|
|
4.1
|
|
Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
|
|
|
|
4.2
|
|
Indenture for Senior Debt Securities, dated March 12, 2008, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
|
|
|
|
4.3
|
|
First Supplemental Indenture for 5.00% Convertible Senior Notes due 2028, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of notes). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on March 12, 2008.]
|
|
|
|
4.4
|
|
Second Supplemental Indenture for 5.00% Convertible Senior Notes due 2028, dated July 8, 2009, by and between Bill Barrett Corporation, Circle B Land Company LLC, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed on July 8, 2009.]
|
|
|
|
4.5
|
|
Third Supplemental Indenture for 5.00% Convertible Senior Notes due 2028, dated August 3, 2011, by and between Bill Barrett Corporation, Circle B Land Company LLC, GB Acquisition Corporation, Elk Production Uintah, LLC, Aurora Gathering, LLC, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 21, 2012.]
|
|
|
|
Exhibit
Number
|
|
Description of Exhibits
|
4.6
|
|
Indenture for Senior Debt Securities, dated July 8, 2009, between Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM, LLC, Circle B Land Company LLC, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
|
|
|
|
4.7
|
|
Third Supplemental Indenture for 7.625% Senior Notes due 2019, dated September 27, 2011, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Circle B Land Company LLC, GB Acquisition Corporation, Elk Production Uintah, LLC, Aurora Gathering, LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of Notes). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K with the Commission on September 27, 2011.]
|
|
|
|
4.8
|
|
Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March 12, 2012, among the Company, Circle B Land Company LLC, Bill Barrett CBM Corporation, GB Acquisition Corporation, Elk Production Uintah, LLC, Aurora Gathering, LLC, and Deutsche Bank Trust Company Americas, as Trustee [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission March 12, 2012.]
|
|
|
|
10.1(a)
|
|
Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2010.]
|
|
|
|
10.1(b)
|
|
First Amendment to Third Amended and Restated Credit Agreement dated as of October 18, 2011 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 18, 2011.]
|
|
|
|
10.1(c)
|
|
Second Amendment dated effective as of September 30, 2014 to Third Amended and Restated Credit Agreement dated as of March 16, 2010, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on December 11, 2014.]
|
|
|
|
10.1(d)
|
|
Third Amendment, dated effective as of April 9, 2015, to Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation, certain of its subsidiaries party thereto and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on April 9, 2015.]
|
|
|
|
10.1(e)
|
|
Fourth Amendment, dated effective as of September 23, 2015, to Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation, certain of its subsidiaries party thereto and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on September 29, 2015.]
|
|
|
|
10.2+
|
|
Form of Indemnification Agreement, between Bill Barrett Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
|
|
|
|
10.3+
|
|
2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
|
|
|
|
10.4+
|
|
Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
|
|
|
|
10.5+
|
|
2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 16, 2008.]
|
|
|
|
Exhibit
Number
|
|
Description of Exhibits
|
10.6+
|
|
Form of Stock Option Agreement for 2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2008.]
|
|
|
|
10.7+
|
|
2012 Equity Incentive Plan. [Incorporated by reference to Appendix B to our Definitive Proxy Statement filed with the Commission on April 4, 2012.]
|
|
|
|
10.8+
|
|
Form of Restricted Common Stock Unit Award for 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on July 2, 2012.]
|
|
|
|
10.9+
|
|
Performance Cash Bonus Plan. [Incorporated by reference to Appendix A to our Proxy Statement for the 2011 Annual Meeting of Stockholders filed with the Commission on March 25, 2011.]
|
|
|
|
10.10+
|
|
Form of Amended and Restated Change in Control Severance Protection Agreement. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on January 30, 2015.]
|
|
|
|
10.11
|
|
Debt Exchange Agreement. [Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the Commission on August 4, 2016.]
|
|
|
|
10.12+
|
|
Confidential Severance and Release Agreement dated March 17, 2016. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 18, 2016.]
|
|
|
|
10.13+
|
|
Confidential Severance and Release Agreement dated April 7, 2016. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 8, 2016.]
|
|
|
|
10.14+
|
|
Deferred Compensation Plan. [Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the Commission on May 5, 2016.]
|
|
|
|
12.1*
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
21.1*
|
|
Subsidiaries of the Registrant.
|
|
|
|
23.1*
|
|
Consent of Deloitte & Touche LLP.
|
|
|
|
23.2*
|
|
Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
|
|
|
|
31.1*
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
|
|
|
|
31.2*
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
|
|
|
|
32**
|
|
Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.
|
|
|
|
99.1*
|
|
Report of Netherland, Sewell & Associates, Inc. dated January 16, 2017, concerning audit of oil and gas reserve estimates.
|
|
|
|
101.INS
|
|
XBRL Instance Document
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
Exhibit
Number
|
|
Description of Exhibits
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
+
|
Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
|
|
|
BILL BARRETT CORPORATION
|
|||
|
|
|
|
|
|
|
Date:
|
March 2, 2017
|
|
By:
|
/s/ R. Scot Woodall
|
||
|
|
|
|
R. Scot Woodall
|
||
|
|
|
|
Chief Executive Officer and President
|
||
|
|
|
|
|
|
|
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.
|
||||||
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
||
|
|
|
|
|
|
|
/s/ R. Scot Woodall
|
|
|
Chief Executive Officer, President, and Director (Principal Executive Officer)
|
|
March 2, 2017
|
|
R. Scot Woodall
|
|
|
|
|
||
|
|
|
|
|
|
|
/s/ William M. Crawford
|
|
|
Senior Vice President—Treasury and Finance (Principal Financial Officer)
|
|
March 2, 2017
|
|
William M. Crawford
|
|
|
|
|
||
|
|
|
|
|
||
/s/ David R. Macosko
|
|
|
Senior Vice President— Accounting (Principal Accounting Officer)
|
|
March 2, 2017
|
|
David R. Macosko
|
|
|
|
|
||
|
|
|
|
|
|
|
/s/ William F. Owens
|
|
|
Director
|
|
March 2, 2017
|
|
William F. Owens
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Jim W. Mogg
|
|
|
Director
|
|
March 2, 2017
|
|
Jim W. Mogg
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Edmund P. Segner, III
|
|
|
Director
|
|
March 2, 2017
|
|
Edmund P. Segner, III
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Randy I. Stein
|
|
|
Director
|
|
March 2, 2017
|
|
Randy I. Stein
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Michael E. Wiley
|
|
|
Director
|
|
March 2, 2017
|
|
Michael E. Wiley
|
|
|
|
|
|
Bill Barrett Corporation
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
73
|
Consolidated Balance Sheets as of December 31, 2016 and 2015
|
|
74
|
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014
|
|
75
|
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014
|
|
76
|
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014
|
|
77
|
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2016, 2015 and 2014
|
|
78
|
Notes to Consolidated Financial Statements
|
|
79
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands, except share data)
|
||||||
Assets:
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
275,841
|
|
|
$
|
128,836
|
|
Accounts receivable, net of allowance for doubtful accounts
|
32,837
|
|
|
43,461
|
|
||
Derivative assets
|
8,398
|
|
|
99,809
|
|
||
Prepayments and other current assets
|
1,376
|
|
|
2,211
|
|
||
Total current assets
|
318,452
|
|
|
274,317
|
|
||
Property and equipment - at cost, successful efforts method for oil and gas properties:
|
|
|
|
||||
Proved oil and gas properties
|
1,539,373
|
|
|
2,000,210
|
|
||
Unproved oil and gas properties, excluded from amortization
|
58,830
|
|
|
79,198
|
|
||
Furniture, equipment and other
|
23,636
|
|
|
26,021
|
|
||
|
1,621,839
|
|
|
2,105,429
|
|
||
Accumulated depreciation, depletion, amortization and impairment
|
(559,690
|
)
|
|
(934,745
|
)
|
||
Total property and equipment, net
|
1,062,149
|
|
|
1,170,684
|
|
||
Deferred income tax asset
|
1,587
|
|
|
38,219
|
|
||
Derivative assets
|
—
|
|
|
19,662
|
|
||
Deferred financing costs and other noncurrent assets
|
3,153
|
|
|
3,638
|
|
||
Total
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued liabilities
|
$
|
49,447
|
|
|
$
|
64,337
|
|
Amounts payable to oil and gas property owners
|
6,192
|
|
|
15,657
|
|
||
Production taxes payable
|
22,992
|
|
|
26,578
|
|
||
Derivative liabilities
|
4,346
|
|
|
—
|
|
||
Deferred income taxes
|
1,587
|
|
|
38,219
|
|
||
Current portion of long-term debt
|
454
|
|
|
440
|
|
||
Total current liabilities
|
85,018
|
|
|
145,231
|
|
||
Long-term debt, net of debt issuance costs
|
711,808
|
|
|
794,652
|
|
||
Asset retirement obligations
|
10,703
|
|
|
14,066
|
|
||
Derivatives and other noncurrent liabilities
|
6,269
|
|
|
3,155
|
|
||
Stockholders' equity:
|
|
|
|
||||
Common stock, $0.001 par value; authorized 150,000,000 shares; 75,721,360 and 49,864,512 shares issued and outstanding at December 31, 2016 and 2015, respectively, with 1,325,714 and 1,471,508 shares subject to restrictions, respectively
|
74
|
|
|
48
|
|
||
Additional paid-in capital
|
1,113,797
|
|
|
921,318
|
|
||
Retained earnings (Accumulated deficit)
|
(542,328
|
)
|
|
(371,950
|
)
|
||
Treasury stock, at cost: zero shares at December 31, 2016 and 2015
|
—
|
|
|
—
|
|
||
Total stockholders' equity
|
571,543
|
|
|
549,416
|
|
||
Total
|
$
|
1,385,341
|
|
|
$
|
1,506,520
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except share and per
share data)
|
||||||||||
Operating Revenues:
|
|
|
|
|
|
||||||
Oil, gas and NGL production
|
$
|
178,328
|
|
|
$
|
204,537
|
|
|
$
|
464,137
|
|
Other operating revenues
|
491
|
|
|
3,355
|
|
|
8,154
|
|
|||
Total operating revenues
|
178,819
|
|
|
207,892
|
|
|
472,291
|
|
|||
Operating Expenses:
|
|
|
|
|
|
||||||
Lease operating expense
|
27,886
|
|
|
42,753
|
|
|
60,308
|
|
|||
Gathering, transportation and processing expense
|
2,365
|
|
|
3,482
|
|
|
35,437
|
|
|||
Production tax expense
|
10,638
|
|
|
12,197
|
|
|
31,333
|
|
|||
Exploration expense
|
83
|
|
|
153
|
|
|
453
|
|
|||
Impairment, dry hole costs and abandonment expense
|
4,249
|
|
|
575,310
|
|
|
46,881
|
|
|||
(Gain) loss on sale of properties
|
1,078
|
|
|
1,745
|
|
|
100,407
|
|
|||
Depreciation, depletion and amortization
|
171,641
|
|
|
205,275
|
|
|
235,805
|
|
|||
Unused commitments
|
18,272
|
|
|
19,099
|
|
|
4,434
|
|
|||
General and administrative expense
|
42,169
|
|
|
53,890
|
|
|
53,361
|
|
|||
Other operating expenses, net
|
(316
|
)
|
|
—
|
|
|
—
|
|
|||
Total operating expenses
|
278,065
|
|
|
913,904
|
|
|
568,419
|
|
|||
Operating Income (Loss)
|
(99,246
|
)
|
|
(706,012
|
)
|
|
(96,128
|
)
|
|||
Other Income and Expense:
|
|
|
|
|
|
||||||
Interest and other income
|
235
|
|
|
565
|
|
|
1,294
|
|
|||
Interest expense
|
(59,373
|
)
|
|
(65,305
|
)
|
|
(69,623
|
)
|
|||
Commodity derivative gain (loss)
|
(20,720
|
)
|
|
104,147
|
|
|
197,447
|
|
|||
Gain (loss) on extinguishment of debt
|
8,726
|
|
|
1,749
|
|
|
—
|
|
|||
Total other income and expense
|
(71,132
|
)
|
|
41,156
|
|
|
129,118
|
|
|||
Income (Loss) before Income Taxes
|
(170,378
|
)
|
|
(664,856
|
)
|
|
32,990
|
|
|||
(Provision for) Benefit from Income Taxes
|
—
|
|
|
177,085
|
|
|
(17,909
|
)
|
|||
Net Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
Net Income (Loss) Per Common Share, Basic
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
Net Income (Loss) Per Common Share, Diluted
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
Weighted Average Common Shares Outstanding, Basic
|
55,384,020
|
|
|
48,303,276
|
|
|
48,010,730
|
|
|||
Weighted Average Common Shares Outstanding, Diluted
|
55,384,020
|
|
|
48,303,276
|
|
|
48,435,725
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Net Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
Other Comprehensive Income (Loss), net of tax:
|
|
|
|
|
|
||||||
Effect of derivative financial instruments
|
—
|
|
|
—
|
|
|
(669
|
)
|
|||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
(669
|
)
|
|||
Comprehensive Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
14,412
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Operating Activities:
|
|
|
|
|
|
||||||
Net Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
Adjustments to reconcile to net cash provided by operations:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
171,641
|
|
|
205,275
|
|
|
235,805
|
|
|||
Deferred income taxes
|
—
|
|
|
(176,797
|
)
|
|
16,644
|
|
|||
Impairment, dry hole costs and abandonment expense
|
4,249
|
|
|
575,310
|
|
|
46,881
|
|
|||
Commodity derivative (gain) loss
|
20,720
|
|
|
(104,147
|
)
|
|
(197,447
|
)
|
|||
Settlements of commodity derivatives
|
95,598
|
|
|
179,652
|
|
|
(1,888
|
)
|
|||
Stock compensation and other non-cash charges
|
8,982
|
|
|
10,040
|
|
|
11,352
|
|
|||
Amortization of debt discounts and deferred financing costs
|
2,834
|
|
|
4,624
|
|
|
4,264
|
|
|||
(Gain) loss on extinguishment of debt
|
(8,726
|
)
|
|
(1,749
|
)
|
|
—
|
|
|||
(Gain) loss on sale of properties
|
1,078
|
|
|
1,745
|
|
|
100,407
|
|
|||
Change in operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
10,624
|
|
|
20,995
|
|
|
32,163
|
|
|||
Prepayments and other assets
|
350
|
|
|
311
|
|
|
1,643
|
|
|||
Accounts payable, accrued and other liabilities
|
(2,893
|
)
|
|
(18,798
|
)
|
|
5,119
|
|
|||
Amounts payable to oil and gas property owners
|
(9,465
|
)
|
|
(3,530
|
)
|
|
(7,132
|
)
|
|||
Production taxes payable
|
(2,878
|
)
|
|
(11,482
|
)
|
|
(1,175
|
)
|
|||
Net cash provided by (used in) operating activities
|
121,736
|
|
|
193,678
|
|
|
261,717
|
|
|||
Investing Activities:
|
|
|
|
|
|
||||||
Additions to oil and gas properties, including acquisitions
|
(106,870
|
)
|
|
(324,534
|
)
|
|
(580,943
|
)
|
|||
Additions of furniture, equipment and other
|
(1,195
|
)
|
|
(1,223
|
)
|
|
(3,658
|
)
|
|||
Proceeds from sale of properties and other investing activities
|
24,927
|
|
|
123,122
|
|
|
555,296
|
|
|||
Cash paid for short-term investments
|
—
|
|
|
(114,883
|
)
|
|
—
|
|
|||
Proceeds from the sale of short-term investments
|
—
|
|
|
115,000
|
|
|
—
|
|
|||
Net cash provided by (used in) investing activities
|
(83,138
|
)
|
|
(202,518
|
)
|
|
(29,305
|
)
|
|||
Financing Activities:
|
|
|
|
|
|
||||||
Proceeds from debt
|
—
|
|
|
—
|
|
|
165,000
|
|
|||
Principal and redemption premium payments on debt
|
(440
|
)
|
|
(25,191
|
)
|
|
(283,546
|
)
|
|||
Proceeds from stock option exercises
|
—
|
|
|
—
|
|
|
126
|
|
|||
Proceeds from sale of common stock, net of offering costs
|
110,003
|
|
|
—
|
|
|
—
|
|
|||
Deferred financing costs and other
|
(1,156
|
)
|
|
(3,037
|
)
|
|
(2,683
|
)
|
|||
Net cash provided by (used in) financing activities
|
108,407
|
|
|
(28,228
|
)
|
|
(121,103
|
)
|
|||
Increase (Decrease) in Cash and Cash Equivalents
|
147,005
|
|
|
(37,068
|
)
|
|
111,309
|
|
|||
Beginning Cash and Cash Equivalents
|
128,836
|
|
|
165,904
|
|
|
54,595
|
|
|||
Ending Cash and Cash Equivalents
|
$
|
275,841
|
|
|
$
|
128,836
|
|
|
$
|
165,904
|
|
|
Common
Stock
|
|
Additional
Paid-In
Capital
|
|
Retained
Earnings
(Deficit)
|
|
Treasury
Stock
|
|
Accumulated
Other
Comprehensive
Income
|
|
Total
Stockholders' Equity |
||||||||||||
Balance at December 31, 2013
|
$
|
48
|
|
|
$
|
904,261
|
|
|
$
|
100,740
|
|
|
$
|
—
|
|
|
$
|
669
|
|
|
$
|
1,005,718
|
|
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
|
—
|
|
|
126
|
|
|
—
|
|
|
(2,684
|
)
|
|
—
|
|
|
(2,558
|
)
|
||||||
Stock-based compensation
|
—
|
|
|
11,916
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,916
|
|
||||||
Retirement of treasury stock
|
—
|
|
|
(2,684
|
)
|
|
—
|
|
|
2,684
|
|
|
—
|
|
|
—
|
|
||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
15,081
|
|
|
—
|
|
|
—
|
|
|
15,081
|
|
||||||
Effect of derivative financial instruments, net of $410 of taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(669
|
)
|
|
(669
|
)
|
||||||
Balance at December 31, 2014
|
48
|
|
|
913,619
|
|
|
115,821
|
|
|
—
|
|
|
—
|
|
|
1,029,488
|
|
||||||
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,173
|
)
|
|
—
|
|
|
(1,173
|
)
|
||||||
Stock-based compensation
|
—
|
|
|
10,468
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,468
|
|
||||||
Retirement of treasury stock
|
—
|
|
|
(1,173
|
)
|
|
—
|
|
|
1,173
|
|
|
—
|
|
|
—
|
|
||||||
Settlement of convertible notes
|
—
|
|
|
(1,596
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,596
|
)
|
||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
(487,771
|
)
|
|
—
|
|
|
—
|
|
|
(487,771
|
)
|
||||||
Balance at December 31, 2015
|
48
|
|
|
921,318
|
|
|
(371,950
|
)
|
|
—
|
|
|
—
|
|
|
549,416
|
|
||||||
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
|
1
|
|
|
—
|
|
|
—
|
|
|
(1,114
|
)
|
|
—
|
|
|
(1,113
|
)
|
||||||
Stock-based compensation
|
—
|
|
|
9,455
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,455
|
|
||||||
Retirement of treasury stock
|
—
|
|
|
(1,114
|
)
|
|
—
|
|
|
1,114
|
|
|
—
|
|
|
—
|
|
||||||
Exchange of senior notes for shares of common stock
|
10
|
|
|
74,390
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
74,400
|
|
||||||
Issuance of common stock, net of offering costs
|
15
|
|
|
109,748
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
109,763
|
|
||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
(170,378
|
)
|
|
—
|
|
|
—
|
|
|
(170,378
|
)
|
||||||
Balance at December 31, 2016
|
$
|
74
|
|
|
$
|
1,113,797
|
|
|
$
|
(542,328
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
571,543
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Accrued oil, gas and NGL sales
|
$
|
26,542
|
|
|
$
|
33,594
|
|
Due from joint interest owners
|
4,366
|
|
|
8,373
|
|
||
Other
|
1,952
|
|
|
1,508
|
|
||
Allowance for doubtful accounts
|
(23
|
)
|
|
(14
|
)
|
||
Total accounts receivable
|
$
|
32,837
|
|
|
$
|
43,461
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Proved properties
|
$
|
306,075
|
|
|
$
|
320,538
|
|
Wells and related equipment and facilities
|
1,164,354
|
|
|
1,592,716
|
|
||
Support equipment and facilities
|
63,238
|
|
|
77,785
|
|
||
Materials and supplies
|
5,706
|
|
|
9,171
|
|
||
Total proved oil and gas properties
|
$
|
1,539,373
|
|
|
$
|
2,000,210
|
|
Unproved properties
|
27,790
|
|
|
33,336
|
|
||
Wells and facilities in progress
|
31,040
|
|
|
45,862
|
|
||
Total unproved oil and gas properties, excluded from amortization
|
$
|
58,830
|
|
|
$
|
79,198
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(543,154
|
)
|
|
(918,510
|
)
|
||
Total oil and gas properties, net
|
$
|
1,055,049
|
|
|
$
|
1,160,898
|
|
|
Year Ended December 31,
|
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
|
||||||
|
(in thousands)
|
|
||||||||||
Non-cash impairment of proved oil and gas properties
|
$
|
—
|
|
|
$
|
559,282
|
|
(1)
|
$
|
15,761
|
|
(2)
|
Non-cash impairment of unproved oil and gas properties
|
183
|
|
|
13,156
|
|
(1)
|
24,082
|
|
(3)
|
|||
Non-cash impairment of inventory
|
—
|
|
|
—
|
|
|
340
|
|
|
|||
Dry hole costs
|
97
|
|
|
123
|
|
|
101
|
|
|
|||
Abandonment expense
|
3,969
|
|
|
2,749
|
|
|
6,597
|
|
|
|||
Total non-cash impairment, dry hole costs and abandonment expense
|
$
|
4,249
|
|
|
$
|
575,310
|
|
|
$
|
46,881
|
|
|
(1)
|
Due to the decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved oil and gas properties for the year ended December 31, 2015.
|
(2)
|
As a result of the Powder River Oil Divestiture (see Note
4
), the carrying values of the remaining properties were analyzed relative to their estimated fair market value. As a result, the Company recognized impairment of
$14.8 million
. These properties were classified as held for sale as of December 31, 2014. The remaining impairment of
$1.0 million
related to the sale of natural gas assets in the West Tavaputs area of the Uinta Basin in 2013 based on a true up of previously estimated carrying value.
|
(3)
|
As a result of unfavorable drilling and completion results in the Paradox Basin, the Company recognized an impairment of
$11.6 million
related to unproved oil and gas properties. In addition, the Company recognized an impairment of
$6.1 million
related to certain unproved oil and gas properties in the Uinta Basin as a result of having no future plans to evaluate certain acreage positions. The Company recognized an impairment of
$6.4 million
to unproved oil and gas properties as the result of the Powder River Oil Divestiture discussed in (2) above.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Accrued drilling, completion and facility costs
|
$
|
15,594
|
|
|
$
|
32,895
|
|
Accrued lease operating, gathering, transportation and processing expenses
|
4,261
|
|
|
4,930
|
|
||
Accrued general and administrative expenses
|
6,375
|
|
|
10,962
|
|
||
Accrued interest payable
|
12,264
|
|
|
13,918
|
|
||
Trade payables
|
7,900
|
|
|
620
|
|
||
Other
|
3,053
|
|
|
1,012
|
|
||
Total accounts payable and accrued liabilities
|
$
|
49,447
|
|
|
$
|
64,337
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net income (loss)
|
$
|
(170,378
|
)
|
|
$
|
(487,771
|
)
|
|
$
|
15,081
|
|
Basic weighted-average common shares outstanding in period
|
55,384
|
|
|
48,303
|
|
|
48,011
|
|
|||
Add dilutive effects of stock options and nonvested shares of common stock
|
—
|
|
|
—
|
|
|
425
|
|
|||
Diluted weighted-average common shares outstanding in period
|
55,384
|
|
|
48,303
|
|
|
48,436
|
|
|||
Basic net income (loss) per common share
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
Diluted net income (loss) per common share
|
$
|
(3.08
|
)
|
|
$
|
(10.10
|
)
|
|
$
|
0.31
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Cash paid for interest
|
$
|
58,193
|
|
|
$
|
61,047
|
|
|
$
|
65,935
|
|
Cash paid for income taxes
|
—
|
|
|
2
|
|
|
1
|
|
|||
Supplemental disclosures of non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Accrued receivables - oil and gas properties
(1)
|
—
|
|
|
—
|
|
|
42,872
|
|
|||
Accrued liabilities - oil and gas properties
|
23,944
|
|
|
33,805
|
|
|
72,297
|
|
|||
Change in asset retirement obligations, net of disposals
|
(4,799
|
)
|
|
(9,101
|
)
|
|
(22,740
|
)
|
|||
Fair value of debt exchanged for common stock
(2)
|
74,400
|
|
|
—
|
|
|
—
|
|
|||
Retirement of treasury stock
|
(1,114
|
)
|
|
(1,173
|
)
|
|
(2,684
|
)
|
|||
Fair value of properties exchanged in non-cash transactions
|
—
|
|
|
—
|
|
|
77,078
|
|
|||
Transfer of lease financing obligation
|
—
|
|
|
—
|
|
|
36,075
|
|
(1)
|
Includes a receivable of
$42.9 million
related to a settlement agreement with the U.S. Department of Interior resulting in the cancellation of certain Cottonwood Gulch natural gas leases in 2014.
|
(2)
|
See Note
5
for additional information regarding the Debt Exchange.
|
Assets:
|
|
|
||
Proved properties
|
|
$
|
1,320,745
|
|
Furniture, equipment and other
|
|
4,907
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
(688,864
|
)
|
|
Total assets
|
|
$
|
636,788
|
|
Liabilities:
|
|
|
||
Asset retirement obligation
|
|
$
|
22,448
|
|
Lease financing obligation
|
|
36,075
|
|
|
Other liabilities
|
|
84
|
|
|
Total liabilities
|
|
$
|
58,607
|
|
Net assets
|
|
$
|
578,181
|
|
|
|
As of December 31, 2016
|
|
As of December 31, 2015
|
||||||||||||||||||||
|
Maturity Date
|
Principal
|
|
Debt
Issuance Costs |
|
Carrying
Amount |
|
Principal
|
|
Debt
Issuance Costs |
|
Carrying
Amount |
||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||
Amended Credit Facility
(1)
|
April 9, 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Convertible Notes
(2)(3)
|
March 15, 2028
|
579
|
|
|
—
|
|
|
579
|
|
|
579
|
|
|
—
|
|
|
579
|
|
||||||
7.625% Senior Notes
(4)
|
October 1, 2019
|
315,300
|
|
|
(2,169
|
)
|
|
313,131
|
|
|
400,000
|
|
|
(3,752
|
)
|
|
396,248
|
|
||||||
7.0% Senior Notes
(5)
|
October 15, 2022
|
400,000
|
|
|
(4,227
|
)
|
|
395,773
|
|
|
400,000
|
|
|
(4,953
|
)
|
|
395,047
|
|
||||||
Lease Financing Obligation
(6)
|
August 10, 2020
|
2,782
|
|
|
(3
|
)
|
|
2,779
|
|
|
3,222
|
|
|
(4
|
)
|
|
3,218
|
|
||||||
Total Debt
|
|
$
|
718,661
|
|
|
$
|
(6,399
|
)
|
|
$
|
712,262
|
|
|
$
|
803,801
|
|
|
$
|
(8,709
|
)
|
|
$
|
795,092
|
|
Less: Current Portion of Long-Term Debt
(7)
|
|
454
|
|
|
—
|
|
|
454
|
|
|
440
|
|
|
—
|
|
|
440
|
|
||||||
Total Long-Term Debt
|
|
$
|
718,207
|
|
|
$
|
(6,399
|
)
|
|
$
|
711,808
|
|
|
$
|
803,361
|
|
|
$
|
(8,709
|
)
|
|
$
|
794,652
|
|
(1)
|
In April 2015, the definition of "Maturity Date" in the Amended Credit Facility was amended to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of the Company in existence as of April 9, 2015 or that may be incurred by the Company as of a future date, or any permitted refinancing debt in respect thereof.
|
(2)
|
The aggregate estimated fair value of the Convertible Notes was approximately
$0.5 million
as of both
December 31, 2016
and
2015
based on reported market trades of these instruments.
|
(3)
|
The Company has the right at any time, with at least 30 days' notice, to call the Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2018 and March 20, 2023.
|
(4)
|
The aggregate estimated fair value of the
7.625%
Senior Notes was approximately
$314.5 million
and
$270.2 million
as of
December 31, 2016
and
2015
, respectively, based on reported market trades of these instruments.
|
(5)
|
The aggregate estimated fair value of the
7.0%
Senior Notes was approximately
$384.5 million
and
$272.0 million
as of
December 31, 2016
and
2015
, respectively, based on reported market trades of these instruments.
|
(6)
|
The aggregate estimated fair value of the Lease Financing Obligation was approximately
$2.6 million
and
$3.1 million
as of
December 31, 2016
and
2015
, respectively. As there is no active public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
|
(7)
|
The current portion of long-term debt as of
December 31, 2016
and
2015
includes the current portion of the Lease Financing Obligation.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Beginning of period
|
$
|
15,176
|
|
|
$
|
22,852
|
|
|
$
|
43,005
|
|
Liabilities incurred
|
83
|
|
|
781
|
|
|
4,027
|
|
|||
Liabilities settled
|
(16
|
)
|
|
(739
|
)
|
|
(6,283
|
)
|
|||
Disposition of properties
|
(4,840
|
)
|
|
(9,056
|
)
|
|
(23,722
|
)
|
|||
Accretion expense
|
861
|
|
|
1,425
|
|
|
2,587
|
|
|||
Revisions to estimate
|
(26
|
)
|
|
(87
|
)
|
|
3,238
|
|
|||
End of period
|
$
|
11,238
|
|
|
$
|
15,176
|
|
|
$
|
22,852
|
|
Less: Liabilities associated with properties held for sale
|
—
|
|
|
—
|
|
|
146
|
|
|||
Less: Current asset retirement obligations
|
535
|
|
|
1,110
|
|
|
1,114
|
|
|||
Long-term asset retirement obligations
|
$
|
10,703
|
|
|
$
|
14,066
|
|
|
$
|
21,592
|
|
|
As of December 31, 2016
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Cash Equivalents
(1)
|
$
|
40,115
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
40,115
|
|
Deferred Compensation Plan
(1)
|
1,447
|
|
|
—
|
|
|
—
|
|
|
1,447
|
|
||||
Commodity Derivatives
(1)
|
—
|
|
|
13,156
|
|
|
—
|
|
|
13,156
|
|
||||
Liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity Derivatives
(1)
|
$
|
—
|
|
|
$
|
10,003
|
|
|
$
|
—
|
|
|
$
|
10,003
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
|
As of December 31, 2015
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Cash Equivalents
(1)
|
$
|
60,065
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
60,065
|
|
Deferred Compensation Plan
(1)
|
1,231
|
|
|
—
|
|
|
—
|
|
|
1,231
|
|
||||
Commodity Derivatives
(1)
|
—
|
|
|
119,471
|
|
|
—
|
|
|
119,471
|
|
||||
Proved oil and gas properties
(2)
|
—
|
|
|
—
|
|
|
178,221
|
|
|
178,221
|
|
||||
Unproved oil and gas properties
(2)
|
—
|
|
|
—
|
|
|
5,539
|
|
|
5,539
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
(2)
|
This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.
|
|
As of December 31, 2016
|
||||||||||
Balance Sheet
|
Gross Amounts of
Recognized Assets
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of Assets
Presented in the Balance
Sheet
|
||||||
|
|
|
(in thousands)
|
|
|
||||||
Derivative assets (current)
|
$
|
13,156
|
|
|
$
|
(4,758
|
)
|
(1)
|
$
|
8,398
|
|
Derivative assets (noncurrent)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total derivative assets
|
$
|
13,156
|
|
|
$
|
(4,758
|
)
|
|
$
|
8,398
|
|
|
Gross Amounts of
Recognized
Liabilities
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of Liabilities
Presented in the Balance
Sheet
|
||||||
|
|
|
(in thousands)
|
|
|
||||||
Derivative liabilities
|
$
|
(9,104
|
)
|
|
$
|
4,758
|
|
(1)
|
$
|
(4,346
|
)
|
Derivatives and other noncurrent liabilities
|
(899
|
)
|
|
—
|
|
(2)
|
(899
|
)
|
|||
Total derivative liabilities
|
$
|
(10,003
|
)
|
|
$
|
4,758
|
|
|
$
|
(5,245
|
)
|
|
|
|
|
|
|
||||||
|
As of December 31, 2015
|
||||||||||
Balance Sheet
|
Gross Amounts of
Recognized Assets
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of Assets
Presented in the Balance
Sheet
|
||||||
|
|
|
(in thousands)
|
|
|
||||||
Derivative assets (current)
|
$
|
99,809
|
|
|
$
|
—
|
|
|
$
|
99,809
|
|
Derivative assets (noncurrent)
|
19,662
|
|
|
—
|
|
|
19,662
|
|
|||
Total derivative assets
|
$
|
119,471
|
|
|
$
|
—
|
|
|
$
|
119,471
|
|
(1)
|
Asset and liability balances with the same counterparty are presented as a net asset or liability on the Consolidated Balance Sheets.
|
(2)
|
As of
December 31, 2016
, this line item on the Consolidated Balance Sheet includes
$5.4 million
of other noncurrent liabilities.
|
|
Derivatives Qualifying as
Cash Flow Hedges
|
|
Year Ended December 31,
|
||||||||||
2016
|
|
2015
|
|
2014
|
|||||||||
|
|
|
(in thousands)
|
||||||||||
Amount of Gain (Loss) Recognized in AOCI
|
Commodity Hedges
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Amount of Gain (Loss) Reclassified from AOCI into Income (net of tax)
(1)(2)
|
Commodity Hedges
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
669
|
|
Amount of Gain (Loss) Recognized in Income on Ineffective Hedges
|
Commodity Hedges
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Presented net of income tax expense of
$0.4 million
for the year ended December 31, 2014.
|
(2)
|
Gains reclassified from AOCI into income are included in the oil, gas and NGL production revenues in the Consolidated Statements of Operations.
|
|
For the Year 2017
|
|
For the Year 2018
|
||||||||||
|
Derivative Volumes
|
|
Weighted Average Price
|
|
Derivative Volumes
|
|
Weighted Average Price
|
||||||
Oil (Bbls)
|
2,222,875
|
|
|
$
|
58.79
|
|
|
363,500
|
|
|
$
|
54.04
|
|
Natural Gas (MMbtu)
|
3,650,000
|
|
|
2.96
|
|
|
—
|
|
|
—
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Commodity derivative settlements on derivatives designated as cash flow hedges
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,070
|
|
Total commodity derivative gain (loss)
(2)
|
(20,720
|
)
|
|
104,147
|
|
|
197,447
|
|
(1)
|
Included in oil, gas and NGL production revenues in the Consolidated Statements of Operations.
|
(2)
|
Included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Income tax (expense) benefit at the federal statutory rate
|
$
|
59,632
|
|
|
$
|
232,700
|
|
|
$
|
(11,546
|
)
|
State income taxes, net of federal tax effect
|
4,971
|
|
|
19,399
|
|
|
(932
|
)
|
|||
Incentive stock compensation
|
(8
|
)
|
|
(69
|
)
|
|
(199
|
)
|
|||
Nondeductible political contributions and lobbying costs
|
(18
|
)
|
|
(11
|
)
|
|
(108
|
)
|
|||
Nondeductible officer compensation
|
(56
|
)
|
|
(110
|
)
|
|
(229
|
)
|
|||
Other permanent items
|
(44
|
)
|
|
(89
|
)
|
|
(89
|
)
|
|||
Valuation allowance
|
(64,477
|
)
|
|
(74,978
|
)
|
|
—
|
|
|||
Deferred tax related to the changes in overall state tax rates
|
—
|
|
|
(74
|
)
|
|
(5,230
|
)
|
|||
Other, net
|
—
|
|
|
317
|
|
|
424
|
|
|||
Income tax (expense) benefit
|
$
|
—
|
|
|
$
|
177,085
|
|
|
$
|
(17,909
|
)
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Current:
|
|
|
|
||||
Deferred tax assets (liabilities):
|
|
|
|
||||
Derivative instruments
|
$
|
(1,537
|
)
|
|
$
|
(37,846
|
)
|
Accrued expenses
|
256
|
|
|
230
|
|
||
Bad debt expense
|
9
|
|
|
5
|
|
||
Prepaid expenses
|
(324
|
)
|
|
(615
|
)
|
||
Other
|
9
|
|
|
7
|
|
||
Total current deferred tax assets (liabilities)
|
$
|
(1,587
|
)
|
|
$
|
(38,219
|
)
|
|
|
|
|
||||
Long-term:
|
|
|
|
||||
Deferred tax assets:
|
|
|
|
||||
Net operating loss carryforward
|
$
|
252,436
|
|
|
$
|
124,828
|
|
Stock-based compensation
|
18,048
|
|
|
17,123
|
|
||
Deferred rent
|
443
|
|
|
622
|
|
||
Minimum tax credit carryforward
|
1,402
|
|
|
1,402
|
|
||
Deferred compensation
|
1,058
|
|
|
915
|
|
||
State tax credit carryforwards
|
5,588
|
|
|
5,641
|
|
||
Financing obligation
|
1,260
|
|
|
1,428
|
|
||
Other
|
263
|
|
|
269
|
|
||
Less: Valuation allowance
|
(142,032
|
)
|
|
(80,088
|
)
|
||
Total long-term deferred tax assets
|
138,466
|
|
|
72,140
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Oil and gas properties
|
(137,220
|
)
|
|
(26,466
|
)
|
||
Long-term derivative instruments
|
341
|
|
|
(7,455
|
)
|
||
Total long-term deferred tax assets (liabilities)
|
(136,879
|
)
|
|
(33,921
|
)
|
||
Net long-term deferred tax assets (liabilities)
|
$
|
1,587
|
|
|
$
|
38,219
|
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Common Stock Outstanding:
|
|
|
|
|
|
|||
Shares at beginning of period
|
49,864,512
|
|
|
49,526,637
|
|
|
49,152,448
|
|
Exercise of common stock options
|
—
|
|
|
—
|
|
|
7,926
|
|
Shares issued for 401(k) plan
|
—
|
|
|
31,699
|
|
|
36,533
|
|
Shares issued for directors' fees
|
97,299
|
|
|
44,892
|
|
|
44,551
|
|
Shares issued for nonvested shares of common stock
|
686,500
|
|
|
673,087
|
|
|
857,870
|
|
Shares issued for debt exchange
|
10,000,000
|
|
|
—
|
|
|
—
|
|
Shares issued for equity offering
|
15,525,000
|
|
|
—
|
|
|
—
|
|
Shares retired or forfeited
|
(451,951
|
)
|
|
(411,803
|
)
|
|
(572,691
|
)
|
Shares at end of period
|
75,721,360
|
|
|
49,864,512
|
|
|
49,526,637
|
|
Treasury Stock:
|
|
|
|
|
|
|||
Shares at beginning of period
|
—
|
|
|
—
|
|
|
—
|
|
Treasury stock acquired
|
227,561
|
|
|
109,473
|
|
|
116,813
|
|
Treasury stock retired
|
(227,561
|
)
|
|
(109,473
|
)
|
|
(116,813
|
)
|
Shares at end of period
|
—
|
|
|
—
|
|
|
—
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Common stock options
(1)
|
$
|
69
|
|
|
$
|
652
|
|
|
$
|
2,073
|
|
Nonvested common stock
(1)
|
6,696
|
|
|
6,721
|
|
|
6,845
|
|
|||
Nonvested common stock units
(1)
|
883
|
|
|
1,115
|
|
|
1,065
|
|
|||
Nonvested performance-based equity
(1)
|
1,808
|
|
|
1,652
|
|
|
990
|
|
|||
Nonvested performance cash units
(2)
|
2,485
|
|
|
427
|
|
|
—
|
|
|||
Total
|
$
|
11,941
|
|
|
$
|
10,567
|
|
|
$
|
10,973
|
|
(1)
|
Unrecognized compensation cost as of
December 31, 2016
was
$6.2 million
related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of
1.5
years.
|
(2)
|
The nonvested performance-based cash units are liability awards with
$2.9 million
and
$0.4 million
in derivatives and other noncurrent liabilities in the Consolidated Balance Sheets as of
December 31, 2016
and
2015
, respectively.
|
Option Awards
|
|
Shares
|
|
Weighted Average
Exercise Price
|
|
Weighted Average
Remaining
Contractual Term
(in years)
|
|
Aggregate
Intrinsic Value
|
|||||
Outstanding at January 1, 2016
|
|
917,821
|
|
|
$
|
29.25
|
|
|
|
|
|
||
Granted
(1)
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Forfeited or expired
|
|
(481,651
|
)
|
|
27.76
|
|
|
|
|
|
|||
Outstanding at December 31, 2016
(2)
|
|
436,170
|
|
|
30.89
|
|
|
1.16
|
|
$
|
—
|
|
(1)
|
The Company has not granted any share-based option awards since 2012.
|
(2)
|
At December 31, 2016, all share-based options granted have vested and are exercisable.
|
|
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
Common Stock Awards
|
|
Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|||||||||
Outstanding at January 1,
|
|
1,002,947
|
|
|
$
|
15.53
|
|
|
793,064
|
|
|
$
|
21.47
|
|
|
756,118
|
|
|
$
|
22.17
|
|
Granted
|
|
686,500
|
|
|
5.11
|
|
|
673,087
|
|
|
11.85
|
|
|
542,209
|
|
|
22.00
|
|
|||
Vested
|
|
(451,329
|
)
|
|
15.90
|
|
|
(294,957
|
)
|
|
21.69
|
|
|
(292,168
|
)
|
|
24.05
|
|
|||
Forfeited or expired
|
|
(69,019
|
)
|
|
14.14
|
|
|
(168,247
|
)
|
|
17.63
|
|
|
(213,095
|
)
|
|
21.99
|
|
|||
Outstanding at December 31,
|
|
1,169,099
|
|
|
9.33
|
|
|
1,002,947
|
|
|
15.53
|
|
|
793,064
|
|
|
21.47
|
|
|
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
Common Stock Unit Awards
|
|
Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|||||||||
Outstanding at January 1,
|
|
145,492
|
|
|
$
|
11.07
|
|
|
54,945
|
|
|
$
|
23.84
|
|
|
55,778
|
|
|
$
|
19.35
|
|
Granted
|
|
98,974
|
|
|
7.02
|
|
|
135,439
|
|
|
8.31
|
|
|
45,928
|
|
|
24.49
|
|
|||
Vested
|
|
(97,299
|
)
|
|
8.43
|
|
|
(44,892
|
)
|
|
18.38
|
|
|
(46,761
|
)
|
|
22.25
|
|
|||
Forfeited or expired
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Outstanding at December 31,
|
|
147,167
|
|
|
10.09
|
|
|
145,492
|
|
|
11.07
|
|
|
54,945
|
|
|
23.84
|
|
|
|
Year Ended December 31,
|
||||||||||||
|
|
2016
|
|
2015
|
||||||||||
Performance-Based Cash Unit Awards
|
|
Shares
|
|
Weighted
Average Fair Value |
|
Shares
|
|
Weighted
Average Fair Value |
||||||
Outstanding at January 1,
|
|
391,278
|
|
|
|
|
—
|
|
|
|
||||
Granted
|
|
646,572
|
|
|
|
|
422,345
|
|
|
|
||||
Vested
|
|
—
|
|
|
|
|
—
|
|
|
|
||||
Forfeited or expired
|
|
(95,524
|
)
|
|
|
|
(31,067
|
)
|
|
|
||||
Outstanding at December 31,
|
|
942,326
|
|
|
$
|
8.89
|
|
|
391,278
|
|
|
$
|
3.95
|
|
|
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
Performance-Based Common Stock Awards
|
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|
Shares
|
|
Weighted
Average Grant Date Fair Value |
|||||||||
Outstanding at January 1,
|
|
468,561
|
|
|
$
|
18.46
|
|
|
614,077
|
|
|
$
|
19.62
|
|
|
584,032
|
|
|
$
|
19.80
|
|
Granted
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
315,661
|
|
|
23.86
|
|
|||
Vested
(1)
|
|
(156,575
|
)
|
|
19.81
|
|
|
(11,623
|
)
|
|
23.07
|
|
|
(42,833
|
)
|
|
19.51
|
|
|||
Forfeited or expired
|
|
(155,371
|
)
|
|
20.44
|
|
|
(133,893
|
)
|
|
25.46
|
|
|
(242,783
|
)
|
|
22.13
|
|
|||
Outstanding at December 31,
|
|
156,615
|
|
|
19.54
|
|
|
468,561
|
|
|
18.46
|
|
|
614,077
|
|
|
19.62
|
|
(1)
|
The Compensation Committee approved a special retention award on July 18, 2013. A debt performance gate was required to be met as of December 31, 2013 in which the shares would vest on July 18, 2014, 2015 and 2016. The vested shares of
15,495
,
11,623
and
11,623
are included in the vested line item for the years ended December 31, 2016, 2015 and 2014, respectively.
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Beginning deferred compensation liability balance
|
$
|
1,231
|
|
|
$
|
1,069
|
|
Employee contributions
|
275
|
|
|
410
|
|
||
Company matching contributions
|
165
|
|
|
119
|
|
||
Distributions
|
(352
|
)
|
|
(346
|
)
|
||
Participant earnings (losses)
|
128
|
|
|
(21
|
)
|
||
Ending deferred compensation liability balance
|
$
|
1,447
|
|
|
$
|
1,231
|
|
|
|
|
|
||||
Amount to be paid within one year
|
$
|
214
|
|
|
$
|
206
|
|
Remaining balance to be paid beyond one year
|
$
|
1,233
|
|
|
$
|
1,025
|
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Beginning investment balance
|
$
|
1,231
|
|
|
$
|
1,069
|
|
Investment purchases
|
440
|
|
|
529
|
|
||
Distributions
|
(352
|
)
|
|
(346
|
)
|
||
Earnings (losses)
|
128
|
|
|
(21
|
)
|
||
Ending investment balance
|
$
|
1,447
|
|
|
$
|
1,231
|
|
|
As of December 31, 2016
|
||
|
(in thousands)
|
||
2017
|
$
|
537
|
|
2018
|
537
|
|
|
2019
|
1,825
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
2,899
|
|
|
As of December 31, 2016
|
||
|
(in thousands)
|
||
2017
|
$
|
18,590
|
|
2018
|
18,691
|
|
|
2019
|
18,691
|
|
|
2020
|
18,691
|
|
|
2021
|
10,902
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
85,565
|
|
|
As of December 31, 2016
|
||
|
(in thousands)
|
||
2017
(1)
|
$
|
5,237
|
|
2018
|
2,665
|
|
|
2019
|
693
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
8,595
|
|
(1)
|
Includes a contractual obligation of
$1.0 million
related to certain drilling commitments on sold properties.
|
|
As of December 31, 2016
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Current assets
|
$
|
318,274
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
318,452
|
|
Property and equipment, net
|
1,056,343
|
|
|
5,806
|
|
|
—
|
|
|
1,062,149
|
|
||||
Intercompany receivable
|
20,678
|
|
|
—
|
|
|
(20,678
|
)
|
|
—
|
|
||||
Investment in subsidiaries
|
(14,751
|
)
|
|
—
|
|
|
14,751
|
|
|
—
|
|
||||
Noncurrent assets
|
4,740
|
|
|
—
|
|
|
—
|
|
|
4,740
|
|
||||
Total assets
|
$
|
1,385,284
|
|
|
$
|
5,984
|
|
|
$
|
(5,927
|
)
|
|
$
|
1,385,341
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
$
|
85,018
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
85,018
|
|
Intercompany payable
|
—
|
|
|
20,678
|
|
|
(20,678
|
)
|
|
—
|
|
||||
Long-term debt
|
711,808
|
|
|
—
|
|
|
—
|
|
|
711,808
|
|
||||
Other noncurrent liabilities
|
16,915
|
|
|
57
|
|
|
—
|
|
|
16,972
|
|
||||
Stockholders' equity
|
571,543
|
|
|
(14,751
|
)
|
|
14,751
|
|
|
571,543
|
|
||||
Total liabilities and stockholders' equity
|
$
|
1,385,284
|
|
|
$
|
5,984
|
|
|
$
|
(5,927
|
)
|
|
$
|
1,385,341
|
|
|
As of December 31, 2015
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Current assets
|
$
|
274,115
|
|
|
$
|
202
|
|
|
$
|
—
|
|
|
$
|
274,317
|
|
Property and equipment, net
|
1,164,086
|
|
|
6,598
|
|
|
—
|
|
|
1,170,684
|
|
||||
Intercompany receivable
|
21,412
|
|
|
—
|
|
|
(21,412
|
)
|
|
—
|
|
||||
Investment in subsidiaries
|
(14,664
|
)
|
|
—
|
|
|
14,664
|
|
|
—
|
|
||||
Noncurrent assets
|
61,519
|
|
|
—
|
|
|
—
|
|
|
61,519
|
|
||||
Total assets
|
$
|
1,506,468
|
|
|
$
|
6,800
|
|
|
$
|
(6,748
|
)
|
|
$
|
1,506,520
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
$
|
145,231
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
145,231
|
|
Intercompany payable
|
—
|
|
|
21,412
|
|
|
(21,412
|
)
|
|
—
|
|
||||
Long-term debt
|
794,652
|
|
|
—
|
|
|
—
|
|
|
794,652
|
|
||||
Other noncurrent liabilities
|
17,169
|
|
|
52
|
|
|
—
|
|
|
17,221
|
|
||||
Stockholders' equity
|
549,416
|
|
|
(14,664
|
)
|
|
14,664
|
|
|
549,416
|
|
||||
Total liabilities and stockholders' equity
|
$
|
1,506,468
|
|
|
$
|
6,800
|
|
|
$
|
(6,748
|
)
|
|
$
|
1,506,520
|
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Operating and other revenues
|
$
|
178,191
|
|
|
$
|
628
|
|
|
$
|
—
|
|
|
$
|
178,819
|
|
Operating expenses
|
(235,181
|
)
|
|
(715
|
)
|
|
—
|
|
|
(235,896
|
)
|
||||
General and administrative
|
(42,169
|
)
|
|
—
|
|
|
—
|
|
|
(42,169
|
)
|
||||
Interest income and other income (expense)
|
(71,132
|
)
|
|
—
|
|
|
—
|
|
|
(71,132
|
)
|
||||
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries
|
(170,291
|
)
|
|
(87
|
)
|
|
—
|
|
|
(170,378
|
)
|
||||
(Provision for) Benefit from income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Equity in earnings (loss) of subsidiaries
|
(87
|
)
|
|
—
|
|
|
87
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
(170,378
|
)
|
|
$
|
(87
|
)
|
|
$
|
87
|
|
|
$
|
(170,378
|
)
|
|
Year Ended December 31, 2015
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Operating and other revenues
|
$
|
207,282
|
|
|
$
|
610
|
|
|
$
|
—
|
|
|
$
|
207,892
|
|
Operating expenses
|
(844,577
|
)
|
|
(15,437
|
)
|
|
—
|
|
|
(860,014
|
)
|
||||
General and administrative
|
(53,890
|
)
|
|
—
|
|
|
—
|
|
|
(53,890
|
)
|
||||
Interest income and other income (expense)
|
41,156
|
|
|
—
|
|
|
—
|
|
|
41,156
|
|
||||
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries
|
(650,029
|
)
|
|
(14,827
|
)
|
|
—
|
|
|
(664,856
|
)
|
||||
(Provision for) Benefit from income taxes
|
177,085
|
|
|
—
|
|
|
—
|
|
|
177,085
|
|
||||
Equity in earnings (loss) of subsidiaries
|
(14,827
|
)
|
|
—
|
|
|
14,827
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
(487,771
|
)
|
|
$
|
(14,827
|
)
|
|
$
|
14,827
|
|
|
$
|
(487,771
|
)
|
|
Year Ended December 31, 2014
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Operating and other revenues
|
$
|
472,288
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
472,291
|
|
Operating expenses
|
(514,721
|
)
|
|
(337
|
)
|
|
—
|
|
|
(515,058
|
)
|
||||
General and administrative
|
(53,361
|
)
|
|
—
|
|
|
—
|
|
|
(53,361
|
)
|
||||
Interest and other income (expense)
|
129,118
|
|
|
—
|
|
|
—
|
|
|
129,118
|
|
||||
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries
|
33,324
|
|
|
(334
|
)
|
|
—
|
|
|
32,990
|
|
||||
(Provision for) Benefit from income taxes
|
(17,909
|
)
|
|
—
|
|
|
—
|
|
|
(17,909
|
)
|
||||
Equity in earnings (loss) of subsidiaries
|
(334
|
)
|
|
—
|
|
|
334
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
15,081
|
|
|
$
|
(334
|
)
|
|
$
|
334
|
|
|
$
|
15,081
|
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Net Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(87
|
)
|
|
$
|
87
|
|
|
$
|
(170,378
|
)
|
Other Comprehensive Income (Loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Effect of derivative financial instruments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Comprehensive Income (Loss)
|
$
|
(170,378
|
)
|
|
$
|
(87
|
)
|
|
$
|
87
|
|
|
$
|
(170,378
|
)
|
|
Year Ended December 31, 2015
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Net Income (Loss)
|
$
|
(487,771
|
)
|
|
$
|
(14,827
|
)
|
|
$
|
14,827
|
|
|
$
|
(487,771
|
)
|
Other Comprehensive Income (Loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Effect of derivative financial instruments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Comprehensive Income (Loss)
|
$
|
(487,771
|
)
|
|
$
|
(14,827
|
)
|
|
$
|
14,827
|
|
|
$
|
(487,771
|
)
|
|
Year Ended December 31, 2014
|
||||||||||||||
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Net Income (Loss)
|
$
|
15,081
|
|
|
$
|
(334
|
)
|
|
$
|
334
|
|
|
$
|
15,081
|
|
Other Comprehensive Income (Loss), net of tax:
|
|
|
|
|
|
|
|
||||||||
Effect of derivative financial instruments
|
(669
|
)
|
|
—
|
|
|
—
|
|
|
(669
|
)
|
||||
Other comprehensive income (loss)
|
(669
|
)
|
|
—
|
|
|
—
|
|
|
(669
|
)
|
||||
Comprehensive Income (Loss)
|
$
|
14,412
|
|
|
$
|
(334
|
)
|
|
$
|
334
|
|
|
$
|
14,412
|
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Cash flows from operating activities
|
$
|
121,109
|
|
|
$
|
627
|
|
|
$
|
—
|
|
|
$
|
121,736
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
||||||||
Additions to oil and gas properties, including acquisitions
|
(106,852
|
)
|
|
(18
|
)
|
|
—
|
|
|
(106,870
|
)
|
||||
Additions to furniture, fixtures and other
|
(1,195
|
)
|
|
—
|
|
|
—
|
|
|
(1,195
|
)
|
||||
Proceeds from sale of properties and other investing activities
|
24,802
|
|
|
125
|
|
|
—
|
|
|
24,927
|
|
||||
Intercompany transfers
|
734
|
|
|
—
|
|
|
(734
|
)
|
|
—
|
|
||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
||||||||
Principal and redemption premium payments on debt
|
(440
|
)
|
|
—
|
|
|
—
|
|
|
(440
|
)
|
||||
Proceeds from sale of common stock
|
110,003
|
|
|
—
|
|
|
—
|
|
|
110,003
|
|
||||
Intercompany transfers
|
—
|
|
|
(734
|
)
|
|
734
|
|
|
—
|
|
||||
Other financing activities
|
(1,156
|
)
|
|
—
|
|
|
—
|
|
|
(1,156
|
)
|
||||
Change in cash and cash equivalents
|
147,005
|
|
|
—
|
|
|
—
|
|
|
147,005
|
|
||||
Beginning cash and cash equivalents
|
128,836
|
|
|
—
|
|
|
—
|
|
|
128,836
|
|
||||
Ending cash and cash equivalents
|
$
|
275,841
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
275,841
|
|
|
Year Ended December 31, 2015
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Cash flows from operating activities
|
$
|
193,329
|
|
|
$
|
349
|
|
|
$
|
—
|
|
|
$
|
193,678
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
||||||||
Additions to oil and gas properties, including acquisitions
|
(325,613
|
)
|
|
1,079
|
|
|
—
|
|
|
(324,534
|
)
|
||||
Additions to furniture, fixtures and other
|
(1,223
|
)
|
|
—
|
|
|
—
|
|
|
(1,223
|
)
|
||||
Proceeds from sale of properties and other investing activities
|
123,122
|
|
|
—
|
|
|
—
|
|
|
123,122
|
|
||||
Cash paid for short-term investments
|
(114,883
|
)
|
|
—
|
|
|
—
|
|
|
(114,883
|
)
|
||||
Proceeds from sale of short-term investments
|
115,000
|
|
|
—
|
|
|
—
|
|
|
115,000
|
|
||||
Intercompany transfers
|
1,428
|
|
|
—
|
|
|
(1,428
|
)
|
|
—
|
|
||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
||||||||
Principal and redemption premium payments on debt
|
(25,191
|
)
|
|
—
|
|
|
—
|
|
|
(25,191
|
)
|
||||
Intercompany transfers
|
—
|
|
|
(1,428
|
)
|
|
1,428
|
|
|
—
|
|
||||
Other financing activities
|
(3,037
|
)
|
|
—
|
|
|
—
|
|
|
(3,037
|
)
|
||||
Change in cash and cash equivalents
|
(37,068
|
)
|
|
—
|
|
|
—
|
|
|
(37,068
|
)
|
||||
Beginning cash and cash equivalents
|
165,904
|
|
|
—
|
|
|
—
|
|
|
165,904
|
|
||||
Ending cash and cash equivalents
|
$
|
128,836
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
128,836
|
|
|
Year Ended December 31, 2014
|
||||||||||||||
|
Parent
Issuer |
|
Guarantor
Subsidiaries |
|
Intercompany
Eliminations |
|
Consolidated
|
||||||||
|
(in thousands)
|
||||||||||||||
Cash flows from operating activities
|
$
|
261,704
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
261,717
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
||||||||
Additions to oil and gas properties, including acquisitions
|
(571,215
|
)
|
|
(9,728
|
)
|
|
—
|
|
|
(580,943
|
)
|
||||
Additions to furniture, fixtures and other
|
(3,658
|
)
|
|
—
|
|
|
—
|
|
|
(3,658
|
)
|
||||
Proceeds from sale of properties and other investing activities
|
553,477
|
|
|
1,819
|
|
|
—
|
|
|
555,296
|
|
||||
Intercompany transfers
|
(7,896
|
)
|
|
—
|
|
|
7,896
|
|
|
—
|
|
||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
||||||||
Proceeds from debt
|
165,000
|
|
|
—
|
|
|
—
|
|
|
165,000
|
|
||||
Principal and redemption premium payments on debt
|
(283,546
|
)
|
|
—
|
|
|
—
|
|
|
(283,546
|
)
|
||||
Intercompany transfers
|
—
|
|
|
7,896
|
|
|
(7,896
|
)
|
|
—
|
|
||||
Other financing activities
|
(2,557
|
)
|
|
—
|
|
|
—
|
|
|
(2,557
|
)
|
||||
Change in cash and cash equivalents
|
111,309
|
|
|
—
|
|
|
—
|
|
|
111,309
|
|
||||
Beginning cash and cash equivalents
|
54,595
|
|
|
—
|
|
|
—
|
|
|
54,595
|
|
||||
Ending cash and cash equivalents
|
$
|
165,904
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
165,904
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per Boe data)
|
||||||||||
Acquisition costs:
|
|
|
|
|
|
||||||
Unproved properties
(1)
|
$
|
5,557
|
|
|
$
|
5,331
|
|
|
$
|
44,121
|
|
Proved properties
(1)
|
—
|
|
|
2,358
|
|
|
49,660
|
|
|||
Exploration costs
|
180
|
|
|
361
|
|
|
855
|
|
|||
Development costs
|
91,471
|
|
|
278,028
|
|
|
549,982
|
|
|||
Asset retirement obligation
|
57
|
|
|
693
|
|
|
7,264
|
|
|||
Total costs incurred
(1)
|
$
|
97,265
|
|
|
$
|
286,771
|
|
|
$
|
651,882
|
|
Depletion per Boe of production
|
$
|
28.18
|
|
|
$
|
31.14
|
|
|
$
|
25.15
|
|
(1)
|
Year ended December 31, 2014 includes $79.0 million related to property acquired through asset exchanges, consisting of $29.3 million of unproved acquisition costs and $49.7 million of proved acquisition costs.
|
|
Oil
(MBbls) |
|
Gas
(MMcf) |
|
NGLs
(MBbls) |
|
Equivalent
Units (MBoe) |
||||
Proved reserves:
|
|
|
|
|
|
|
|
||||
Balance at December 31, 2013
|
83,501
|
|
|
466,340
|
|
|
35,756
|
|
|
196,982
|
|
Purchases of oil and gas reserves in place
|
5,501
|
|
|
12,313
|
|
|
1,190
|
|
|
8,743
|
|
Extension, discoveries and other additions
|
15,665
|
|
|
26,103
|
|
|
2,188
|
|
|
22,204
|
|
Revisions of previous estimates
|
(9,866
|
)
|
|
(47,749
|
)
|
|
(4,342
|
)
|
|
(22,166
|
)
|
Sales of reserves
|
(6,951
|
)
|
|
(281,389
|
)
|
|
(20,479
|
)
|
|
(74,329
|
)
|
Production
|
(4,012
|
)
|
|
(21,744
|
)
|
|
(1,476
|
)
|
|
(9,112
|
)
|
Balance at December 31, 2014
|
83,838
|
|
|
153,874
|
|
|
12,837
|
|
|
122,322
|
|
Purchases of oil and gas reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extension, discoveries and other additions
|
6,072
|
|
|
8,430
|
|
|
977
|
|
|
8,454
|
|
Revisions of previous estimates
|
(18,120
|
)
|
|
(39,125
|
)
|
|
240
|
|
|
(24,401
|
)
|
Sales of reserves
|
(11,866
|
)
|
|
(17,415
|
)
|
|
(1,312
|
)
|
|
(16,081
|
)
|
Production
|
(4,401
|
)
|
|
(7,765
|
)
|
|
(898
|
)
|
|
(6,593
|
)
|
Balance at December 31, 2015
|
55,523
|
|
|
97,999
|
|
|
11,844
|
|
|
83,701
|
|
Purchases of oil and gas reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extension, discoveries and other additions
|
4,986
|
|
|
14,670
|
|
|
2,250
|
|
|
9,681
|
|
Revisions of previous estimates
|
(24,267
|
)
|
|
(26,143
|
)
|
|
(1,768
|
)
|
|
(30,392
|
)
|
Sales of reserves
|
(1,347
|
)
|
|
(3,153
|
)
|
|
(174
|
)
|
|
(2,047
|
)
|
Production
|
(3,885
|
)
|
|
(7,170
|
)
|
|
(1,010
|
)
|
|
(6,090
|
)
|
Balance at December 31, 2016
|
31,010
|
|
|
76,203
|
|
|
11,142
|
|
|
54,853
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
29,292
|
|
|
50,590
|
|
|
3,825
|
|
|
41,549
|
|
December 31, 2015
|
27,196
|
|
|
45,191
|
|
|
5,079
|
|
|
39,807
|
|
December 31, 2016
|
21,748
|
|
|
47,510
|
|
|
6,718
|
|
|
36,384
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
54,546
|
|
|
103,284
|
|
|
9,013
|
|
|
80,773
|
|
December 31, 2015
|
28,327
|
|
|
52,808
|
|
|
6,765
|
|
|
43,894
|
|
December 31, 2016
|
9,262
|
|
|
28,693
|
|
|
4,424
|
|
|
18,469
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
1,393,373
|
|
|
$
|
2,552,844
|
|
|
$
|
7,725,475
|
|
Future production costs
|
(557,636
|
)
|
|
(967,518
|
)
|
|
(2,265,328
|
)
|
|||
Future development costs
|
(215,077
|
)
|
|
(674,350
|
)
|
|
(1,636,744
|
)
|
|||
Future income taxes
|
—
|
|
|
—
|
|
|
(910,446
|
)
|
|||
Future net cash flows
|
620,660
|
|
|
910,976
|
|
|
2,912,957
|
|
|||
10% annual discount
|
(291,351
|
)
|
|
(583,410
|
)
|
|
(1,743,375
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
329,309
|
|
|
$
|
327,566
|
|
|
$
|
1,169,582
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure of discounted future net cash flows, beginning of period
|
$
|
327,566
|
|
|
$
|
1,169,582
|
|
|
$
|
1,377,549
|
|
Sales of oil and gas, net of production costs and taxes
|
(119,167
|
)
|
|
(127,015
|
)
|
|
(331,559
|
)
|
|||
Extensions, discoveries and improved recovery, less related costs
|
58,121
|
|
|
33,085
|
|
|
263,383
|
|
|||
Quantity revisions
|
(228,538
|
)
|
|
(202,035
|
)
|
|
(416,642
|
)
|
|||
Price revisions
|
(157,414
|
)
|
|
(1,647,642
|
)
|
|
758,863
|
|
|||
Previously estimated development costs incurred during the period
|
52,611
|
|
|
154,985
|
|
|
84,995
|
|
|||
Changes in estimated future development costs
|
377,239
|
|
|
606,736
|
|
|
112
|
|
|||
Accretion of discount
|
31,941
|
|
|
145,387
|
|
|
174,925
|
|
|||
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
105,885
|
|
|||
Sales of reserves
|
(10,736
|
)
|
|
(82,081
|
)
|
|
(901,443
|
)
|
|||
Changes in production rates (timing) and other
|
(2,314
|
)
|
|
(2,747
|
)
|
|
(4,253
|
)
|
|||
Net changes in future income taxes
|
—
|
|
|
279,311
|
|
|
57,767
|
|
|||
Standardized measure of discounted future net cash flows, end of period
|
$
|
329,309
|
|
|
$
|
327,566
|
|
|
$
|
1,169,582
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
||||||||
Total revenues
|
$
|
29,434
|
|
|
$
|
47,284
|
|
|
$
|
50,481
|
|
|
$
|
51,620
|
|
Less: Costs and expenses
|
68,889
|
|
|
67,054
|
|
|
68,831
|
|
|
73,291
|
|
||||
Operating income (loss)
|
$
|
(39,455
|
)
|
|
$
|
(19,770
|
)
|
|
$
|
(18,350
|
)
|
|
$
|
(21,671
|
)
|
Income (loss) before income taxes
|
(46,496
|
)
|
|
(48,419
|
)
|
|
(26,186
|
)
|
|
(49,277
|
)
|
||||
Net income (loss)
|
(46,496
|
)
|
|
(48,419
|
)
|
|
(26,186
|
)
|
|
(49,277
|
)
|
||||
Net income (loss) per common share, basic
|
(0.96
|
)
|
|
(0.93
|
)
|
|
(0.44
|
)
|
|
(0.79
|
)
|
||||
Net income (loss) per common share, diluted
|
(0.96
|
)
|
|
(0.93
|
)
|
|
(0.44
|
)
|
|
(0.79
|
)
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
(1)
|
|
Fourth Quarter
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
||||||||
Total revenues
|
$
|
49,034
|
|
|
$
|
62,618
|
|
|
$
|
49,679
|
|
|
$
|
46,561
|
|
Less: Costs and expenses
|
88,488
|
|
|
88,425
|
|
|
656,737
|
|
|
80,254
|
|
||||
Operating income (loss)
|
$
|
(39,454
|
)
|
|
$
|
(25,807
|
)
|
|
$
|
(607,058
|
)
|
|
$
|
(33,693
|
)
|
Income (loss) before income taxes
|
(18,604
|
)
|
|
(71,528
|
)
|
|
(553,579
|
)
|
|
(21,145
|
)
|
||||
Net income (loss)
|
(11,731
|
)
|
|
(44,581
|
)
|
|
(410,314
|
)
|
|
(21,145
|
)
|
||||
Net income (loss) per common share, basic
|
(0.24
|
)
|
|
(0.92
|
)
|
|
(8.49
|
)
|
|
(0.45
|
)
|
||||
Net income (loss) per common share, diluted
|
(0.24
|
)
|
|
(0.92
|
)
|
|
(8.49
|
)
|
|
(0.45
|
)
|
(1)
|
The increase in expenses in the third quarter was due to recognizing a non-cash impairment charge associated with the Uinta Oil Program's proved and unproved oil and gas properties. See Note 4 for additional details.
|
1 Year Bill Barrett Chart |
1 Month Bill Barrett Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions