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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| TSXV:SRX | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
Hot Features
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Storm Resources Ltd. (TSX VENTURE:SRX)
Storm has also filed its audited consolidated financial statements as at
December 31, 2013 and for the three months and year then ended along with
Management's Discussion and Analysis ("MD&A") for the same periods. This
information appears on SEDAR at www.sedar.com and on Storm's website at
www.stormresourcesltd.com.
Selected financial and operating information for the three months and year ended
December 31, 2013, as well as reserve information at December 31, 2013, appears
below and should be read in conjunction with the related financial statements
and MD&A.
Highlights
Thousands of Cdn$, except Three Three
volumetric and per share Months Months
amounts Ended Ended Year Ended Year Ended
December December December December
31, 2013 31, 2012 31, 2013 31, 2012
----------------------------------------------------------------------------
FINANCIAL
Gas sales 7,807 3,416 21,019 8,054
NGL sales 4,483 1,597 13,124 4,466
Oil sales 3,090 5,399 15,435 19,793
----------------------------------------------------------------------------
Revenue from product sales(1) 15,380 10,412 49,578 32,313
----------------------------------------------------------------------------
Funds from operations(2) 7,501 5,016 21,949 13,387
Per share - basic ($) 0.09 0.08 0.30 0.24
Per share - diluted ($) 0.09 0.08 0.30 0.24
Net loss (25,174) (2,320) (26,203) (6,574)
Per share - basic ($) (0.34) (0.04) (0.36) (0.12)
Per share - diluted ($) (0.34) (0.04) (0.36) (0.12)
Adjusted net income (loss)
before reduction in carrying
amount of property and
equipment 826 (2,320) (203) (6,574)
Per share - basic and diluted
($) 0.01 (0.04) 0.00 (0.12)
Operations capital expenditures 11,380 10,016 67,410 26,868
Acquisitions and dispositions - (1,239) (14,966) 139,208
Debt including working capital
deficiency 12,059 44,696 12,059 40,376
Weighted average common shares
outstanding (000s)
Basic 81,994 61,824 73,391 56,067
Diluted 81,994 61,824 73,391 56,067
Common shares outstanding (000s)
Basic 87,483 61,824 87,483 61,824
Fully diluted 91,379 64,547 91,379 64,547
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATIONS
Oil equivalent (6:1)
----------------------------------------------------------------------------
Barrels of oil equivalent
(000s) 439 259 1,328 825
Barrels of oil equivalent per
day 4,773 2,815 3,637 2,254
Average selling price (Cdn$
per Boe)(1) 35.03 40.19 37.34 39.14
Gas production
----------------------------------------------------------------------------
Thousand cubic feet (000s) 2,015 987 5,783 3,053
Thousand cubic feet per day 21,898 10,728 15,843 8,342
Average selling price (Cdn$
per Mcf) 3.88 3.46 3.63 2.64
NGL Production
----------------------------------------------------------------------------
Barrels (000s) 64 25 187 67
Barrels per day 695 274 512 185
Average selling price (Cdn$
per barrel) 70.10 63.27 70.29 66.17
Oil Production
----------------------------------------------------------------------------
Barrels (000s) 39 69 177 249
Barrels per day 428 753 485 679
Average selling price (Cdn$
per barrel)(1) 78.47 77.93 87.16 79.53
Wells drilled
----------------------------------------------------------------------------
Gross 1.0 2.0 9.0 6.0
Net 1.0 1.2 8.6 4.4
(1) Excludes hedging gains and losses.
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See discussion of Non-GAAP Measurements on page 16 of the MD&A and
the reconciliation of funds from operations to the most directly comparable
measurement under GAAP, "Cash Flows from Operating Activities", on page 26 of
the MD&A.
President's Message
2013 FOURTH QUARTER AND YEAR-END HIGHLIGHTS
-- Production for the year averaged 3,637 Boe per day (27% oil plus NGL)
which represents an increase of 61% from 2012. Fourth quarter production
was 4,773 Boe per day (24% oil plus NGL), a year-over-year increase of
70%. On a per-share basis, fourth quarter production increased 20% from
the previous year while debt decreased by 70%, or $28.3 million.
Increased production was the result of growth at Umbach where production
averaged 3,262 Boe per day in the fourth quarter of 2013, a 480%
increase from 564 Boe per day in the fourth quarter of 2012.
-- NGL production averaged 695 barrels per day in the fourth quarter, an
increase of 154% from the fourth quarter of 2012. NGL production
increased as a result of production growth from the liquids-rich Montney
formation at Umbach. With condensate and pentane being approximately 60%
of the NGL mix, the fourth quarter NGL price of $70.10 per barrel was
81% of the average Edmonton Par light oil price.
-- Activity in 2013 was focused at Umbach where eight Montney horizontal
wells (7.6 net) plus one Montney vertical delineation well (1.0 net)
were drilled and seven horizontal wells (6.2 net) were completed and
pipeline connected. In the fourth quarter, one Montney horizontal well
(1.0 net) was drilled, one Montney horizontal well (1.0 net) was
completed and two Montney horizontal wells (2.0 net) were pipeline
connected.
-- On Storm's 100% working interest lands at Umbach, five horizontal
Montney wells (5.0 net) were drilled with rates over the first 90
operated days (excluding days shut in) averaging 3.7 Mmcf per day gross
raw gas which is equivalent to 670 Boe per day sales. This is an
improvement of 70% when compared to earlier horizontal wells drilled in
2010 and 2011.
-- Funds from operations for the year totaled $21.9 million, an increase of
64% from the previous year. Funds from operations in the fourth quarter
was $7.5 million or $0.09 per basic share, an increase of 12% from $0.08
per basic share in the prior year. The increase in funds from operations
was the result of significant production growth at Umbach.
-- The funds from operations netback was $16.52 per Boe in 2013, an
increase of 2% from the previous year. The funds from operations netback
improved to $17.08 per Boe in the fourth quarter.
-- The field operating netback excluding hedging gains or losses was $20.43
per Boe for the full year and increased to $20.82 per Boe in the fourth
quarter.
-- Operating costs improved throughout the year. The full year operating
cost of $10.86 per Boe was 5% lower than the previous year while the
fourth quarter operating cost of $9.73 per Boe was 17% lower than the
fourth quarter of 2012. Improving operating costs are the result of
production growth at Umbach where operating costs were $8.73 per Boe in
2013 which was lower than the corporate average of $10.86 per Boe.
-- Controllable cash costs (operating, transportation, cash G&A, interest
expense) declined to $16.24 per Boe in 2013 from $19.83 per Boe in the
prior year. Controllable cash costs showed further improvement to
average $15.38 per Boe in the fourth quarter. The largest improvement
was with cash G&A which decreased $1.52 per Boe to average $2.98 per Boe
during 2013.
-- Capital investment was $11.4 million in the fourth quarter and $52.4
million for the year, net of dispositions. Investment in 2013 was
focused on exploitation of the Montney formation at Umbach including
$14.0 million for infrastructure, $15.0 million to acquire undeveloped
land and $36.0 million for drilling and completions. Dispositions in
2013 totaled $19.5 million from the sale of non-core properties early in
2013.
-- Debt plus working capital deficiency, net of investments, ended the year
at $12.1 million which is 0.4 times annualized fourth quarter cash flow.
In November 2013, Storm's bank credit line was increased to $65.0
million from $52.0 million.
-- Total proved ("1P") reserves increased 50% to 20,764 Mboe with the all-
in cost for additions being $13.19 per Boe. Total proved plus probable
("2P") reserves increased 48% to 40,541 Mboe with the all-in cost for
additions being $9.79 per Boe. The increase in 1P and 2P reserves was
the result of continued delineation drilling in the upper Montney
formation at Umbach.
-- Better than expected horizontal well performance resulted in PDP
reserves at Umbach being revised higher by 439 Mboe.
-- Additions to 2P reserves replaced 910% of 2013 production.
-- Recycle ratio was 2.1 for 2P reserve additions using the all-in cost for
reserve additions and the 2013 field operating netback of $20.43 per Boe
excluding hedging gains or losses.
-- Cost of adding production during 2013 was $17.22 per Boe for proved
developed producing reserves ("PDP") on an all-in basis and was
approximately $20,000 per Boe per day using 2013 capital investment of
$52.4 million and production additions of 2,600 Boe per day (average
fourth quarter rate from wells starting production in 2013).
-- Subsequent to year end, Storm closed the acquisition of a 100% working
interest in 29 sections of land in the Umbach-Nig area, prospective for
liquids rich natural gas from the Montney formation. The acquisition
included two horizontal wells producing 359 Boe net per day (19% NGL)
from the Montney formation. Total cost of $87.9 million consisted of
$30.0 million in cash and 13.6 million common shares of Storm with a
deemed value of $4.25 per common share (closing price on the TSX Venture
Exchange January 30, 2014). The cash portion was funded with $34.8
million of gross proceeds from a bought deal financing and non-brokered
private placement of common shares which closed on February 14, 2014
(8.5 million common shares were issued at a price of $4.10 per common
share).
OPERATIONS REVIEW
Storm has a focused asset base with large land positions in resource plays at
Umbach and in the HRB which have multi-year drilling upside while the Grande
Prairie area, with its shallow decline, provides cash flow available for
investment.
Umbach, Northeast British Columbia
Storm's land position at Umbach is prospective for liquids-rich natural gas from
the Montney formation and currently totals 140 net sections (168 gross sections)
or 98,000 net acres. There are three project areas at Umbach:
-- Umbach South with 87 net sections at a 100% working interest (includes
the 29 sections recently acquired) where fourth quarter production
averaged 2,293 Boe per day.
-- Umbach North with 33 net sections of jointly owned lands (61 gross
sections with Storm's working interest being 60% on most of the lands)
where fourth quarter production average 969 Boe per day.
-- Nig with 20 net sections at a 100% working interest.
To date, Storm has been focused on exploiting the upper Montney although the
middle and lower Montney may also be productive. Since entering the area in
2010, and including the lands acquired in January 2014, Storm has invested $108
million to acquire this land position ($2,750 per hectare or $1,100 per acre).
Production at Umbach grew to 3,262 net Boe per day (18% liquids) in the fourth
quarter as a result of five Montney horizontal wells (4.6 net) that started
production during August to November. Fourth quarter NGL recovery was 40 barrels
per Mmcf sales or 629 barrels per day with approximately 60% being higher priced
condensate plus pentanes. The operating netback in the fourth quarter was $21.74
per Boe with revenue, after deducting transportation costs, of $31.10 per Boe
($3.52 per Mcf sales and $67.49 per barrel of NGL), a royalty rate of 3%, and
operating costs of $8.36 per Boe. Continuing production growth from the 100%
working interest lands at Umbach South is expected to result in operating costs
decreasing to approximately $7.00 per Boe in 2014.
Activity in the fourth quarter included converting a standing vertical well to a
water disposal well, drilling one Montney horizontal well (1.0 net), completing
one Montney horizontal well (1.0 net), and pipeline connecting two Montney
horizontal wells (2.0 net) which started producing on October 19th and November
19th. To date in the first quarter, two Montney horizontal wells (2.0 net) have
been drilled and two Montney horizontal wells have been completed with one
starting production in late February.
A total of 18 horizontal wells have been drilled in the upper Montney at Umbach
(14.4 net) and there are 14 producing horizontal wells (10.8 net). Production
performance has continued to improve based on a comparison of operated day rates
over the first 30 and 90 days (operated day rates exclude days where wells were
shut in due to capacity constraints):
----------------------------------------------------------------------------
30-Day 90-Day 1st Year
Average Average Average
Start of Frac Mmcf Per Mmcf Per Mmcf Per
Production Stages Day Day Day
----------------------------------------------------------------------------
Hz's 1 - 5 60% Umbach Mar/11 - 2.7 Mmcf/d 2.1 Mmcf/d 1.4 Mmcf/d
WI North Oct/12 7 - 11 5 hz's 5 hz's 5 hz's
----------------------------------------------------------------------------
Hz's 6 - 8 60% Umbach Nov/12 - 3.3 Mmcf/d 2.8 Mmcf/d not
WI North Aug/13 14 - 16 3 hz's 3 hz's available
----------------------------------------------------------------------------
Hz's 10 - 14 100% Umbach Apr/13 - 4.2 Mmcf/d 3.7 Mmcf/d not
WI South Nov/13 17 - 18 5 hz's 3 hz's available
----------------------------------------------------------------------------
Comparing operated day rates over 30 and 90 days and using the InSite Petroleum
Consultant Ltd. ("InSite") 2P type curve used in the 2013 year-end reserve
evaluation, Storm management estimates that the most recent horizontal wells (10
to 14) will average 2.4 Mmcf per day in the first year with ultimate recovery of
4.4 Bcf.
Cost to drill and complete horizontal wells in 2013 averaged $4.6 million with
the drilling cost averaging $2.2 million and the completion cost averaging $2.4
million. Tie-in costs have been approximately $0.5 million per horizontal well,
not including cost of longer gathering pipelines to connect multi-well pads to
field compression facilities. A decrease in costs is anticipated in 2014 with a
larger program and with more horizontal wells being drilled from common pads.
Total investment in infrastructure in 2013 at Umbach was approximately $12.6
million which included the acquisition of field compression for $4.5 million
plus construction of 18 kilometres of larger diameter 8-inch and 10-inch field
gathering pipelines. In 2014, an additional $19.0 million will be invested in
infrastructure which includes $5.0 million for larger diameter gathering
pipelines plus $14.0 million to construct a second field compression facility
with an initial capacity of 24 Mmcf per day. Capacity of the new field
compression facility is expandable to 48 Mmmcf per day for an additional
investment of $9.0 million with this expected to occur in 2015.
At pricing of $3.50 per GJ for natural gas and Cdn$89.00 per barrel for Edmonton
Par (WTI US$93.00/Bbl, FX Cdn$0.92), the estimated field netback is $21.00 per
Boe. With this pricing held constant, Storm management estimates that horizontal
wells have an unrisked half cycle rate of return of 37% (1.9 years to payout)
based on a first year average rate of 2.4 Mmcf per day gross raw gas (430 Boe
per day), ultimate recovery of 4.4 Bcf gross raw gas per horizontal well, NGL
recovery of 35 barrels per Mmcf sales (10% shrinkage), and $5.0 million to
drill, complete and tie in a horizontal well.
On January 31, 2014, Storm closed the acquisition of two producing Montney
horizontal wells and 29 sections of undeveloped land for a total cost of $87.9
million. The allocation of the purchase price was $61.5 million for nine
sections with production, reserves and 35 horizontal drilling locations, and
$26.4 million for the remaining 20 sections ($4,700 per hectare or $1,880 per
acre). Highlights of the acquisition are as follows:
-- A 100% working interest was acquired in the lands and two producing
horizontal wells (one upper Montney and one lower Montney).
-- Production from the two horizontal wells totaled 359 Boe per day (NGL
recovery 38 bbls per Mmcf sales) in the third quarter of 2013 with the
majority from the C-42-A horizontal well which has produced 1.4 Bcf to
date from the upper Montney with the current rate being 1.6 Mmcf per day
gross raw gas (295 Boe per day sales).
-- The acquired lands are contiguous with Storm's Umbach South lands where
five Montney horizontal wells (5.0 net) were drilled and commenced
production in 2013 from the upper Montney with rates averaging 4.3 Mmcf
per day gross raw gas over the first 30 operating days and 3.7 Mmcf per
day gross raw gas over the first 90 operating days (operating day rate
excludes days shut in).
-- The upper Montney formation is the primary target based on results to
date in the area; however, Storm management believes that the middle
Montney may also be productive across the acquired lands.
-- Storm management estimates DPIIP of 1.6 Tcf in the upper Montney
formation on the acquired lands based on data from existing wells on the
29 sections (seven vertical wells plus two Montney horizontal wells)
indicating that the upper Montney formation is 52 metres thick, has
average porosity of 6% and a reservoir pressure of 18,000 to 23,000 kPa.
-- Two to three horizontal wells will be drilled in the upper Montney on
the acquired lands in 2014 with additional wells being planned for 2015.
Horn River Basin, Northeast British Columbia
Storm has a 100% working interest in 123 sections in the HRB (81,000 net acres)
which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua
shales. Fourth quarter production averaged 363 Boe per day at an operating
netback of $11.59 per Boe. Wellsite compression was installed in November 2013
and production has increased to average 400 Boe per day to date in the first
quarter of 2014. Production is from one horizontal well with 12 fracture
stimulations which currently produces 2.7 Mmcf per day gross raw gas with
cumulative production of 3.8 Bcf gross raw gas since start-up in March 2011. A
second horizontal well was also drilled in 2011 and is awaiting completion with
timing dependent on natural gas pricing.
A resource evaluation completed by InSite effective December 31, 2011 estimates
that the best estimate of DPIIP in the core producing area is 3.1 Tcf gross raw
gas with the best estimate of contingent resources being 616 Bcf. The evaluated
area includes 30 sections at a 100% working interest and represents 22% of
Storm's total land holdings in the HRB. Commerciality has been proven across the
core producing area with a horizontal well that has been producing for 30 months
plus two vertical wells that were completed and tested with final test rates of
900 Mcf per day over the final 24 hours of each flow test.
Grande Prairie Area, Northwest Alberta and Northeast British Columbia
Production in the fourth quarter averaged 1,147 Boe per day (44% oil plus NGL)
at an operating netback of $21.65 per Boe. No capital was invested in this area
in the fourth quarter and minimal activity is planned during 2014. Cash flow
from this area will continue to be re-invested to grow production at Umbach.
HEDGING UPDATE
Current commodity price hedges for 2014 include 11,500 Mcf per day (14,000 GJ
per day) of natural gas with an average floor price of approximately $4.12 per
Mcf and an average ceiling price of $4.34 per Mcf (AECO monthly index $3.39 per
GJ for floor and $3.57 per GJ for ceiling). In addition, an oil price of WTI
Cdn$101.89 per barrel (WTI price in $US per barrel converted to $Cdn per barrel)
has been fixed on 338 barrels per day. It is likely that this hedge position
will be expanded with the objective of ensuring that a decrease in commodity
prices does not have a significant impact on capital investment and growth over
the next 12 to 18 months.
COMPARISON OF 2013 RESULTS VERSUS GUIDANCE
Shown below is a comparison of Storm's actual 2013 results to guidance provided
during 2013.
2013 2013 2013
Guidance Guidance Guidance
2013 Actual November May 15, February
Results 14, 2013 2013 28, 2013
----------------------------------------------------------------------------
Year-end adjusted debt plus
working capital $12.1 $40.0 $37.0 $44.0
deficiency(1) million million million million
----------------------------------------------------------------------------
Average operating costs $10.86 per $10 - $10 - $10 -
Boe $11/Boe $11/Boe $11/Boe
----------------------------------------------------------------------------
Average royalty rate (on
revenue before hedging) 12.2% 14% 13% - 14% 11% - 12%
----------------------------------------------------------------------------
Operations capital $67.5 $62.0 $62.0 $40.0
million million million million
Asset dispositions $19.5 $19.5 $19.5 $20.0
million million million million
Asset acquisitions $4.5 $4.5 $4.5 $4.5
million million million million
----------------------------------------------------------------------------
Cash G&A $4.0 not $3.7 $3.9
million provided million million
----------------------------------------------------------------------------
Exit or fourth quarter 4,773 4,500-5,000 4,500-5,000 4,000-4,500
average production Boe/d Boe/d Boe/d Boe/d
(24% oil + (24% oil + (25% oil + (25% oil +
NGL) NGL) NGL) NGL)
----------------------------------------------------------------------------
(1) Includes value of publicly listed securities.
Actual operations capital investment in 2013 of $67.5 million was $5.5 million
higher than most recent guidance of $62.0 million because of a casing failure
during completion of a horizontal well at Umbach in the fourth quarter ($3.0
million) and because the drilling of one horizontal well at Umbach was advanced
into the fourth quarter of 2013 instead of being drilled in 2014 ($2.5 million).
Year-end adjusted debt was lower as the result of receiving net proceeds
totaling $31.9 million from two equity financings that closed November 19, 2013.
OUTLOOK
Production in January and February averaged 4,970 Boe per day based on field
estimates and first quarter production is forecast to be 5,000 Boe per day.
Production is expected to be 5,000 to 5,500 Boe per day until September 2014
when the new facility at Umbach will be operational.
Storm's guidance for 2014 remains unchanged from what was provided on January
23, 2014 and is set forth below.
2014 Guidance
----------------------------------------------------------------------------
Estimated year-end debt plus working capital
deficiency(1) $ 50.0 million
----------------------------------------------------------------------------
Estimated average operating costs $ 8.00 - $9.00 per Boe
----------------------------------------------------------------------------
Estimated average royalty rate (on production
revenue before hedging) 14% - 15%
----------------------------------------------------------------------------
Estimated operations capital, excluding acquisitions
& dispositions $ 78.0 million
Estimated acquisitions $ 87.9 million
----------------------------------------------------------------------------
Estimated cash G&A net of recoveries $ 4.0 million
----------------------------------------------------------------------------
Forecast fourth quarter average production 7,500 - 7,900 Boe/d
(20% oil + NGL)
----------------------------------------------------------------------------
Forecast average annual production 5,500 - 6,500 Boe/d
(21% oil + NGL)
----------------------------------------------------------------------------
(1) Includes value of publicly listed securities.
Major expenditures included in operations capital investment for 2014 include:
-- $47.0 million at Umbach to drill 10 horizontal wells (10.0 net) with 9
horizontal wells (9.0 net) being completed and tied in; and
-- $19.0 million to expand infrastructure at Umbach, including a new field
compression facility, expandable from initial capacity of 24 Mmcf per
day to 48 Mmcf per day (expansion expected to occur in 2015).
This level of investment is forecast to increase Storm's fourth quarter 2014
production to 7,500 to 7,900 Boe per day which represents 60% growth on a
year-over-year basis.
Guidance for 2014 assumes an average natural gas price at AECO of $3.75 per GJ
and an Edmonton Par oil price of Cdn$90 per barrel. This reflects estimated
first quarter pricing of AECO $5.00 per GJ and Edmonton Par Cdn$98 per barrel.
Adjusted net debt is forecasted to be $50.0 million at the end of 2014
(including public company investments), which would be approximately 1.0 times
annualized funds from operations in the fourth quarter of 2014.
At Umbach, Storm is still in the early stages of delineating a large, higher
quality, liquids-rich resource in the Montney formation. NGL recovery increases
revenue and the relatively shallow depth (1,400 to 1,600 metres) results in a
lower drilling and completion cost with both providing Storm with a competitive
advantage. Significant future reserve growth is expected given 2P reserves have
been assigned to the upper Montney on only 8% of Storm's land position at
Umbach. In addition, showing that the middle and lower Montney are also
productive and sustained improvements in horizontal well productivity would also
lead to reserve additions. With a strong balance sheet and a plan in place to
further expand owned and operated infrastructure, continued rapid growth is
expected from Umbach during 2014 and 2015.
Storm's land position in the HRB continues to be a core, long-term asset with
significant leverage to higher natural gas prices.
Capital investment will be reviewed mid-year and, should natural gas prices
remain elevated and horizontal well performance at Umbach continue to meet or
exceed expectations, it is likely that capital investment would be increased in
the second half of 2014 and forecast fourth quarter production would also be
increased.
In closing, I would like to thank Storm's employees for their effort and hard
work in 2013 and Storm's Directors for their advice and guidance. A lot was
accomplished in 2013 and we look forward to providing updates on our progress
throughout 2014.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
March 6, 2014
Discovered-Petroleum-Initially-in-Place ("DPIIP") - is defined in the Canadian
Oil and Gas Evaluation Handbook ("COGEH") as the quantity of hydrocarbons that
are estimated to be in place within a known accumulation. DPIIP is divided into
recoverable and unrecoverable portions, with the estimated future recoverable
portion classified as reserves and contingent resources. There is no certainty
that it will be economically viable or technically feasible to produce any
portion of this DPIIP except for those portions identified as proved or probable
reserves.
Contingent Resources - are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic, legal,
environmental, political and regulatory matters, or a lack of markets. It is
also appropriate to classify as contingent resources the estimated discovered
recoverable quantities associated with a project at an early stage of
development. Estimates of contingent resources are estimates only; the actual
resources may be higher or lower than those calculated in the independent
evaluation. There is no certainty that the resources described in the evaluation
will be commercially produced.
Boe Presentation - For the purpose of calculating unit revenues and costs,
natural gas is converted to a barrel of oil equivalent ("Boe") using six
thousand cubic feet ("Mcf") of natural gas equal to one barrel of oil unless
otherwise stated. Boe may be misleading, particularly if used in isolation. A
Boe conversion ratio of six Mcf to one barrel ("Bbl") is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. All Boe measurements and
conversions in this report are derived by converting natural gas to oil in the
ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000
Boe.
Reserves at December 31, 2013
Storm's year-end reserve evaluation effective December 31, 2013 was prepared by
InSite Petroleum Consultants Ltd. ("InSite") under date of February 24, 2014.
InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The
InSite price forecast at December 31, 2013 was used to determine all estimates
of future net revenue (also referred to as net present value or NPV). Storm's
Reserves Committee which is made up of independent and appropriately qualified
directors, has reviewed and approved the evaluation prepared by InSite, and the
report of the Reserves Committee has been accepted by the Company's Board of
Directors.
Reserves included herein are stated on a company gross basis (working interest
before deduction of royalties without including any royalty interests) unless
noted otherwise. All reserves information has been prepared in accordance with
National Instrument ("NI") 51-101. In addition to the information disclosed in
this report, more detailed information will be included in Storm's Annual
Information Form.
Summary
-- Proved developed producing ("PDP") reserves increased 29% to total 7,579
Mboe with additions of 3,046 Mboe replacing 131% of production. The all-
in cost to add PDP reserves was $17.22 per Boe(1).
-- Total proved ("1P") reserves increased 50% to total 20,764 Mboe with the
all-in cost to add 1P reserves being $13.19 per Boe(1). This is a per-
share increase of 17% on a debt adjusted basis(2). The 1P reserve life
index ("RLI") is 12 years using production in the fourth quarter of
2013.
-- Total proved plus probable ("2P") reserves increased 48% to total 40,541
Mboe with the all-in cost to add 2P reserves being $9.79 per Boe(1).
This is a per-share increase of 15% on a debt adjusted basis(2). The 2P
RLI is 23 years using production in the fourth quarter of 2013.
-- The trailing three year all-in cost to add 1P reserves is $18.51 per Boe
and is $13.80 per Boe to add 2P reserves.
-- Recycle ratio was 1.5 for 1P reserve additions and 2.1 for 2P reserve
additions using the all-in cost for reserve additions and the 2013 field
operating netback of $20.44 per Boe excluding hedging gains or losses.
-- The finding and development cost ("FDC") per NI 51-101 requirements
(removing effect of acquisitions, dispositions and revisions) was $13.98
per Boe to add 1P reserves and $10.75 per Boe to add 2P reserves.
-- The year-over-year increase in 1P reserves was 6,942 Mboe which replaced
430% of 2013 production and the increase in 2P reserves was 13,210 Mboe
which replaced 910% of 2013 production.
-- 66% of total 2P reserves are at Umbach, 20% at Horn River Basin ("HRB")
and 14% at Grande Prairie.
-- Storm's asset value is $3.25 per share using the before tax 2P reserve
value of $298 million (discounted at 10%) and after deducting adjusted
net debt of $12.1 million at the end of 2013. This excludes any value
for Storm's landholdings which totaled 302,000 net acres at year end.
-- The majority of additions to 1P and 2P reserves in 2013 was from
drilling activity (extensions) at Umbach where 10,355 Mboe was added on
a 1P basis and 18,822 Mboe was added on a 2P basis with all of this
being from the upper Montney formation.
-- FDC was $159 million on a 1P basis and $319 MM on a 2P basis which is an
increase from the end of 2012 where FDC was $103 million on a 1P basis
and $229 million on a 2P basis. This represents approximately four years
of activity based on the anticipated 2014 capital investment levels.
-- Property dispositions completed during 2013 reduced 1P reserves by 859
Mboe and 2P reserves by 1,137 Mboe. FDC associated with the dispositions
was $1.7 million on a 2P basis (there was no 1P FDC). With net proceeds
from the dispositions totaling $19.5 million and including FDC, reserves
were sold for $22.70 per Boe on a 1P basis and $18.65 per Boe on a 2P
basis.
-- Technical revisions increased PDP reserves by 403 Mboe with 1P and 2P
reserves being reduced by 78 Mboe and 304 Mboe respectively. This was
related to well performance with negative 2P revisions at Grande Prairie
totaling 437 Mboe that were partially offset by positive 2P revisions of
105 Mboe in the HRB and 28 Mboe at Umbach North. Notably, improved
horizontal well performance resulted in PDP reserves at Umbach being
revised higher by 439 Mboe.
-- Economic factors reduced 1P reserves by 1,149 Mboe and reduced 2P
reserves by 2,844 Mboe. This was the result of removing two future
horizontal drilling locations in the HRB due to low natural gas prices.
-- At Umbach South (100% working interest), 2P reserves totaled 16,070 Mboe
which is 40% of Storm's total 2P. There are five horizontal wells with
PDP reserves and 20 future horizontal drilling locations (20.0 net) were
recognized on 6.25 gross sections (6.25 net) with 2P reserves averaging
642 Mboe per future drilling location (four proved plus probable future
horizontal drilling locations per producing horizontal well). An average
of 3.5 Bcf of gross raw gas was assigned per future horizontal drilling
location with 10% shrinkage from raw gas to sales gas and NGL recovery
of 37 barrels per Mmcf of sales (McMahon Gas Plant). 2P FDC totalled
$113 million net.
-- At Umbach North (60% working interest), 2P reserves totaled 10,741 Mboe
which is 26% of Storm's total 2P. There are eight horizontal wells with
PDP reserves and 26 future horizontal drilling locations (15.6 net) were
recognized on 8.5 gross sections (5.1 net) with 2P reserves averaging
549 Mboe per future drilling location (3.25 proved plus probable future
horizontal drilling locations per producing horizontal well). An average
of 3 Bcf of gross raw gas was assigned per future horizontal drilling
location with 17% shrinkage from raw gas to sales gas and NGL recovery
of 54 barrels per Mmcf of sales (Stoddart Gas Plant). 2P FDC totalled
$84 million net.
-- DPIIP in the upper Montney formation at Umbach was 604 Bcf for the area
where 2P reserves were recognized, an average of 41 Bcf per section.
-- Significant additional reserves are likely to be added in the future at
Umbach given that reserves are recognized in the upper Montney only on
8% of Storm's 140 net sections in the area. Additionally, comparing 30
to 90 operating day rates, Storm management estimates ultimate recovery
from the horizontal wells drilled to date at Umbach South will be 4.4
Bcf which is higher than InSite's estimate of 3.5 Bcf for future
horizontal drilling locations. More production history is required to
confirm Storm management's estimate of ultimate recovery.
-- In the HRB, 2P reserves were 8,258 Mboe with 1,466 Mboe assigned to
complete a standing horizontal shale gas well (1.0 net) and to drill
four future horizontal shale gas wells (4.0 net). Recoverable reserves
assigned to each of the future horizontal drilling locations averaged 10
Bcf of gross raw gas. Shrinkage of 12% was used to determine sales gas
volumes. 2P FDC was $84 million gross.
(1) The all-in calculation reflects the result of Storm's entire capital
investment program as it takes into account the effect of acquisitions,
dispositions and revisions, as well as the change in future development costs.
(2) Debt adjusted calculation increases 2013 year-end debt from $12.1 million to
$44.7 million to equal the 2012 year-end debt by buying back 8 million shares at
$4.05 per share (Storm's December 31, 2013 closing share price).
INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES
All amounts are stated in Canadian dollars unless otherwise specified. Where
applicable, natural gas has been converted to barrels of oil equivalent ("Boe")
based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion
method primarily applicable at the burner tip and does not recognize a value
equivalent at the wellhead. Given that the value ratio based on the current
price of crude oil as compared to natural gas is significantly different than
the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion
ratio may be misleading as an indication of value. Production volumes and
revenues are reported on a company gross basis, before deduction of Crown and
other royalties, unless otherwise stated. Unless otherwise specified, all
reserves volumes are based on "company gross reserves" using forecast prices and
costs. The oil and gas reserves statement for the year-ended December 31, 2013,
which will include complete disclosure of oil and gas reserves and other
information in accordance with NI 51-101, will be contained within the Annual
Information Form which will be available on SEDAR.
References to estimates of oil and gas classified as DPIIP are not, and should
not be confused with, oil and gas reserves.
Gross Company Interest Reserves as at December 31, 2013
(Before deduction of royalties payable, not including royalties receivable)
Light 6:1 Oil
Crude Oil Sales Gas NGL Equivalent
(Mbbls) (Mmcf) (Mbbls) (Mboe)
----------------------------------------------------------------------------
Proved producing 1,123 32,719 1,003 7,579
Proved non-producing - 123 2 22
----------------------------------------------------------------------------
Total proved developed 1,123 32,842 1,005 7,601
Proved undeveloped 300 65,758 1,903 13,163
----------------------------------------------------------------------------
Total proved 1,423 98,600 2,908 20,764
Probable additional 870 99,177 2,378 19,777
----------------------------------------------------------------------------
Total proved plus probable 2,293 197,777 5,286 40,541
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross Company Reserve Reconciliation for 2013
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)
----------------------------------------------------------------------------
Proved
Total plus
Proved Probable Probable
----------------------------------------------------------------------------
December 31, 2012 - opening balance 13,822 13,509 27,331
Acquisitions - - -
Discoveries - - -
Extensions 10,356 8,467 18,823
Dispositions (859) (278) (1,137)
Technical revisions (78) (226) (304)
Economic factors (1,149) (1,695) (2,844)
Production (1,328) - (1,328)
----------------------------------------------------------------------------
December 31, 2013 - closing balance 20,764 19,777 40,541
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Future Development Costs ("FDC")
Proved
----------------------------------------------------------------------------
HRB 2.0 net horizontals plus infrastructure $ 34.9 million
Umbach 20.6 net horizontals plus
infrastructure $ 117.0 million
Grande Prairie 3.0 net horizontals at Grimshaw $ 7.6 million
----------------------------------------------------------------------------
Total $ 159.5 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable Additional
----------------------------------------------------------------------------
HRB 5.0 net horizontals plus infrastructure $ 83.8 million
Umbach 36.0 net horizontals plus
infrastructure $ 197.9 million
Grande Prairie 5.0 net horizontals at Grimshaw; 5.0
net horizontals at GP Montney; and
1.0 net horizontal at GP Dunvegan $ 37.2 million
----------------------------------------------------------------------------
Total $ 318.9 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable
Proved Additional
Expenditures Expenditures
----------------------------------------------------------------------------
2014 $ 62,950 $ 67,800
2015 $ 13,107 $ 75,888
2016 $ 48,472 $ 63,454
2017 $ 34,946 $ 78,572
2018 $ - $ 33,155
2019 $ - $ -
----------------------------------------------------------------------------
Total FDC - undiscounted $ 159,475 $ 318,869
Total FDC - discounted at 10% $ 134,383 $ 259,220
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: InSite escalates capital costs at 2% per year after 2014.
NI 51-101 Finding and Development Costs
Total Proved Finding and Development 2013 2012 2011 3 Year
Cost Total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions
(000s) $ 67,450 $ 26,868 $ 25,360 $ 119,768
Net change in FDC (000s) 77,282 30,863 25,541 133,686
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 144,732 $ 57,731 $ 50,901 $ 253,364
----------------------------------------------------------------------------
Reserve additions excluding
acquisitions, dispositions,
revisions and economic factors
(Mboe) 10,356 4,067 2,505 16,928
Total proved finding and development
costs (per Boe) $ 13.98 $ 14.20 $ 20.32 $ 14.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable Finding 3 Year
and Development Cost 2013 2012 2011 Total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions
(000s) $ 67,450 $ 26,868 $ 25,360 $ 119,678
Net change in FDC (000s) 134,903 40,341 51,725 226,969
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 202,353 $ 67,209 $ 77,085 $ 346,647
----------------------------------------------------------------------------
Reserve additions excluding
acquisitions, dispositions,
revisions and economic factors
(Mboe) 18,823 5,514 5,278 29,615
Total proved plus probable finding
and development costs (per Boe) $ 10.75 $ 12.19 $ 14.60 $ 11.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding,
Development and Acquisition Cost
including FDC, Acquisitions, 3 Year
Dispositions, Revisions 2013 2012 2011 Total
----------------------------------------------------------------------------
Capital expenditures including
acquisitions and dispositions
(000s) $ 52,444 $ 166,076 $ 40,795 $ 259,315
Net change in FDC (000s) 56,600 72,655 25,541 154,796
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 109,044 $ 238,731 $ 66,336 $ 414,111
----------------------------------------------------------------------------
Reserve additions including
acquisitions, dispositions
revisions and economic factors
(Mboe) 8,270 10,927 3,178 22,375
All-in total proved finding and
development costs (per Boe) $ 13.19 $ 21.85 $ 20.87 $ 18.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable All-In
Finding, Development and
Acquisition Cost including FDC,
Acquisitions, Dispositions, 3 Year
Revisions 2013 2012 2011 Total
----------------------------------------------------------------------------
Capital expenditures including
acquisitions and dispositions
(000s) $ 52,444 $ 166,076 $ 40,795 $ 259,315
Net change in FDC (000s) 89,829 156,258 51,725 297,812
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 142,273 $ 322,334 $ 92,520 $ 557,127
----------------------------------------------------------------------------
Reserve additions including
acquisitions, dispositions
revisions and economic factors
(Mboe) 14,538 19,828 6,012 40,378
All-In total proved plus probable
finding and development costs (per
Boe) $ 9.79 $ 16.26 $ 15.39 $ 13.80
----------------------------------------------------------------------------
Operating netback per Boe excluding
hedging $ 20.43 $ 21.22 $ 22.81
----------------------------------------------------------------------------
Recycle ratio based on operating
netback (excluding hedging gains or
losses
Proved plus probable 2.1 1.3 1.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Present Value Summary (before tax) as at December 31, 2013
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL
produced and for transportation costs. The calculated NPVs include a deduction
for estimated future well abandonment costs.
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
----------------------------------------------------------------------------
Proved producing $ 184,439 $ 146,816 $ 122,247 $ 105,198 $ 92,774
Proved non-
producing 92 87 82 78 74
----------------------------------------------------------------------------
Total proved
developed $ 184,531 $ 146,903 $ 122,329 $ 105,276 $ 92,848
Proved undeveloped 184,537 107,293 62,108 34,079 15,855
----------------------------------------------------------------------------
Total proved $ 369,068 $ 254,196 $ 184,438 $ 139,355 $ 108,704
Probable additional 364,989 197,446 113,383 67,039 39,544
----------------------------------------------------------------------------
Total proved plus
probable $ 734,058 $ 451,643 $ 297,821 $ 206,393 $ 148,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2013
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL
produced and for transportation costs. The calculated NPVs each include a
deduction for estimated future well abandonment costs.
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
----------------------------------------------------------------------------
Proved producing 184,439 146,816 122,247 105,198 92,774
Proved non-
producing 92 87 82 78 74
----------------------------------------------------------------------------
Total proved
developed 184,531 146,903 122,329 105,276 92,848
Proved undeveloped 162,353 95,685 55,755 30,462 13,725
----------------------------------------------------------------------------
Total proved 346,884 242,588 178,084 135,738 106,574
Probable additional 274,236 146,917 82,937 47,569 26,517
----------------------------------------------------------------------------
Total proved plus
probable 621,121 389,504 261,021 183,308 133,091
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2013
Edmonton
WTI Light Crude Henry Hub AECO Natural
Crude Oil Oil Natural Gas Gas Propane Butane
(US$/Bbl) (Cdn$/Bbl) (US$/Mmbtu) (Cdn$/Mmbtu) (Cdn$/Bbl) (Cdn$/Bbl)
----------------------------------------------------------------------------
2014 96.00 96.05 4.25 3.99 48.03 76.84
2015 95.00 97.50 4.40 4.14 53.63 78.00
2016 95.00 97.45 4.75 4.50 53.60 77.96
2017 95.00 97.40 5.00 4.75 53.57 77.92
2018 96.00 98.40 5.25 5.01 54.12 78.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Forward-Looking Information - This press release contains forward-looking
statements and forward-looking information within the meaning of applicable
securities laws. The use of any of the words "will", "expect", "anticipate",
"intend", "believe", "plan", "potential", "outlook", "forecast", "estimate" and
similar expressions are intended to identify forward-looking statements or
information. More particularly, and without limitation, this press release
contains forward-looking statements and information concerning: production;
drilling plans; reserve volumes; capital expenditures; royalties; financing;
commodity prices; and production, operating and general and administrative
costs.
The forward-looking statements and information in this press release are based
on certain key expectations and assumptions made by Storm, including: prevailing
commodity prices and exchange rates; applicable royalty rates and tax laws;
future well production rates; reserve and resource volumes; the performance of
existing wells; success to be expected in drilling new wells; the adequacy of
budgeted capital expenditures to carrying out planned activities; the
availability and cost of services; and the receipt, in a timely manner, of
regulatory and other required approvals. Although the Company believes that the
expectations and assumptions on which such forward-looking statements and
information are based are reasonable, undue reliance should not be placed on
these forward-looking statements and information because of their inherent
uncertainty. In particular, there is no assurance that exploitation of the
Company's undeveloped lands and prospects will result in the emergence of
profitable operations.
Since forward-looking statements and information address future events and
conditions, by their very nature they involve inherent risks and uncertainties.
Actual results could differ materially from those currently anticipated due to a
number of factors and risks. These include, but are not limited to the risks
associated with the oil and gas industry in general such as: operational risks
in development, exploration and production; delays or changes in plans with
respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections
relating to reserves, production, costs and expenses; health, safety and
environmental risks; commodity price and exchange rate fluctuations; marketing
and transportation of petroleum and natural gas and loss of markets;
environmental risks; competition; ability to access sufficient capital from
internal and external sources; stock market volatility; and changes in
legislation, including but not limited to tax laws, royalty rates and
environmental regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the
operations or financial results of the Company are included or are incorporated
by reference in the company's MD&A for the three months and year ended December
31, 2013.
The forward-looking statements and information contained in this press release
are made as of the date hereof and the Company undertakes no obligation to
update publicly or revise any forward-looking statements or information, whether
as a result of new information, future events or otherwise, unless so required
by applicable securities laws.
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT
TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS
RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS PRESS RELEASE.
FOR FURTHER INFORMATION PLEASE CONTACT:
Storm Resources Ltd.
Brian Lavergne
President & Chief Executive Officer
(403) 817-6145
Storm Resources Ltd.
Donald McLean
Chief Financial Officer
(403) 817-6145
Storm Resources Ltd.
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com
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