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Storm Resources Ltd. Is Pleased to Announce Its Financial and Operating Results for the Three Months Ended March 31, 2016


/EINPresswire.com/ -- CALGARY, ALBERTA -- (Marketwired) -- 05/12/16 -- Storm Resources Ltd. ("Storm" or the "Company") (TSX VENTURE: SRX) has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2016 and for the three months then ended along with Management's Discussion and Analysis ("MD&A") for the same period. 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 ended March 31, 2016 appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights


Thousands of Cdn$, except volumetric Three Months Ended  Three Months Ended
 and per-share amounts                   March 31, 2016      March 31, 2015
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FINANCIAL
Revenue from product sales(1)                    16,121              18,512
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Funds from operations(2)                          7,855              13,712
  Per share - basic ($)                            0.07                0.12
  Per share - diluted ($)                          0.07                0.12
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Net loss                                         (4,984)             (3,565)
  Per share - basic ($)                           (0.04)              (0.03)
  Per share - diluted ($)                         (0.04)              (0.03)
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Net capital invested
  Operations capital expenditures                23,946              35,680
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Debt including working capital
 deficiency(3)                                   77,162              85,098
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Common shares (000s)
  Weighted average - basic                      119,591             111,322
  Weighted average - diluted                    119,591             111,322
  Outstanding end of period - basic             119,742             111,322
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OPERATIONS
(Cdn$ per Boe)
Revenue                                           13.20               21.04
Royalties                                         (0.76)              (0.54)
Production                                        (6.71)              (8.67)
Transportation                                    (0.53)              (1.68)
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Field operating netback                            5.20               10.15
Hedging gains                                      3.03                8.36
General and administrative                        (1.25)              (2.24)
Interest and finance costs                        (0.56)              (0.70)
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Funds from operations - per Boe                    6.42               15.57
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Barrels of oil equivalent per day
 (6:1)                                           13,418               9,776
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Gas Production
  Thousand cubic feet per day                    66,012              47,713
  Price (Cdn$ per Mcf)                             1.62                2.85
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NGL production
  Barrels per day                                 2,416               1,493
  Price (Cdn$ per barrel)                         29.12               37.10
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Oil Production
  Barrels per day                                     -                 330
  Price (Cdn$ per barrel)                             -               43.08
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Wells drilled (100% working interest)               7.0                 6.0
Wells completed (100% working
 interest)                                          2.0                 3.0
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(1)  Excludes hedging gains and losses.
(2)  Certain financial amounts shown above are non-GAAP measurements,
     including funds from operations and funds from operations per share,
     operations capital expenditures, debt including working capital
     deficiency and all measurements per Boe. See discussion of Non-GAAP
     Measurements on page 24 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 17 of the MD&A.
(3)  Excludes the fair value of commodity price contracts.

PRESIDENT'S MESSAGE

2016 FIRST QUARTER HIGHLIGHTS


--  Production averaged 13,418 Boe per day (18% NGL), a per-share increase
    of 25% from the previous quarter and 27% from the previous year. Low
    natural gas prices resulted in production being reduced to meet firm
    processing and transportation commitments with approximately 800 Boe per
    day shut in at Umbach plus the startup of new horizontal wells was
    delayed.

--  NGL production was 2,416 barrels per day, an increase of 62% from the
    previous year. The price was $29.12 per barrel which was 71% of the
    average Edmonton light oil price (60% of the NGL volume was higher value
    condensate and plant pentanes).

--  NGL was 18% of total production but amounted to 40% of revenue from
    product sales versus 27% in the prior year period.

--  Activity was focused at Umbach where seven horizontal wells were
    drilled, two horizontal wells were completed and one horizontal well
    commenced production.

--  At the end of the quarter, there was an inventory of 12 horizontal wells
    (12.0 net) that had not started producing (includes three completed
    wells).

--  Montney horizontal well performance at Umbach continues to improve with
    the four most recent wells averaging 5.8 Mmcf per day gross raw gas over
    the first 90 calendar days, a 23% increase from the average 2014 and
    2015 wells. As a result, the type curve used for forecasting future
    horizontal well performance is being increased to 7.0 Bcf raw from 6.3
    Bcf raw.

--  Controllable cash costs (operating, cash G&A, interest expense) were
    $8.52 per Boe, a year-over-year decrease of 27%. Transportation cost is
    excluded given that the sales price for volumes sold on the Alliance
    Pipeline includes a deduction for the pipeline tariff (artificially
    reduces the transportation cost).

--  Funds from operations was $7.9 million which is a decrease of 42% from
    the previous year. Production growth of 37% was more than offset by a
    45% decrease in revenue plus hedging gains per Boe.

--  With 67% of first quarter natural gas production being sold in the
    higher priced Chicago market, the natural gas price net of
    transportation was approximately 9% higher versus selling at BC Station
    2.

--  Net loss was $5.0 million or $4.09 per Boe and reflects the extremely
    low first quarter commodity prices with funds from operations at $6.42
    per Boe being less than the depletion and depreciation rate of $8.15 per
    Boe.

--  Net capital investment was $23.9 million and included $15.9 million for
    drilling and completions plus $6.1 million to purchase major equipment
    for the third field compression facility at Umbach.

--  Debt including working capital deficiency was $77.2 million, which is
    2.4 times annualized first quarter funds flow. Subsequent to quarter
    end, the bank credit facility was set at $130.0 million after the annual
    review was completed (previously $140.0 million).

OPERATIONS REVIEW

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections). Two sections (2.0 net) were acquired during the first quarter of 2016. To date, 48 horizontal wells have been drilled (44.4 net) with 36 horizontal wells producing at the end of the first quarter (32.4 net).

First quarter 2016 production was 13,398 Boe per day with NGL recovery at 37 barrels per Mmcf sales (60% of the NGL volume is higher priced field condensate plus pentanes recovered at the gas plant).

In the first quarter of 2016, seven horizontal wells (7.0 net) were drilled, two wells (2.0 net) were completed, and one well (1.0 net) started production. There is currently an inventory of 12 horizontal wells (12.0 net) that have not started producing which includes three completed wells.

Storm's two operated field compression facilities have total capacity of 80 Mmcf per day raw gas with actual throughput in the first quarter averaging 70 Mmcf per day raw gas. As a result of the low natural gas price at AECO and BC Station 2, construction of the third field compression facility with initial capacity of 35 Mmcf per day is being deferred with startup now planned for April 2017 (was November 2016). Estimated total cost is unchanged at $25.0 million (expandable to 70 Mmcf per day raw gas for an additional $7.0 million) with $10.9 million invested to date for site preparation and to purchase major equipment ($6.1 million Q1 2016, $4.8 million 2015).

Raw gas from Storm's field compression facilities is sent to the McMahon and Stoddart Gas Plants where Storm has firm processing commitments totaling 65 Mmcf per day raw gas in 2016.

A summary of horizontal well performance and costs is provided below. The four most recent horizontal wells have averaged 5.8 Mmcf per day gross raw gas over the first 90 calendar days, a 23% improvement from the average 2014 and 2015 horizontal well. On a per-stage basis, the drill and complete cost in 2015 has decreased by 17% from 2014.


                                     Actual      IP 90     IP 180     IP 365
                                    Drill &    Cal Day    Cal Day    Cal Day
Year of         Frac Completed     Complete     Mmcf/d     Mmcf/d     Mmcf/d
 Completion   Stages    Length         Cost        Raw        Raw        Raw
----------------------------------------------------------------------------
2013              17   1,190 m $4.6 million 3.5 Mmcf/d 2.9 Mmcf/d 2.2 Mmcf/d
6 wells                        $270 K/stage     6 hz's     6 hz's     6 hz's
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2014              19   1,170 m $4.6 million 4.6 Mmcf/d 4.2 Mmcf/d 3.3 Mmcf/d
13 wells                       $240 K/stage    13 hz's    13 hz's    13 hz's
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2015              22   1,360 m $4.4 million 4.8 Mmcf/d        3.5
11 wells                       $200 K/stage    10 hz's  Mmcf/d(i)
                                                           6 hz's
----------------------------------------------------------------------------
Q4/15 (62-A       23   1,435 m $4.3 million 5.8 Mmcf/d
 pad)                          $190 K/stage     4 hz's
5 wells
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(i) Performance to date of the 2015 wells was reduced by the downtime experienced in the second half of 2015.

Based on the performance of the most recent horizontal wells completed in Q4/15, which are longer and have more frac stages, Storm management is increasing the type curve used for forecasting performance of future horizontal wells to 7.0 Bcf raw from 6.3 Bcf raw (type curve has the same decline profile as the type curve used by InSite in the 2015 reserve evaluation). Future horizontal wells are being planned for greater than 1,600 metres of completed length with more than 28 frac stages. For reference, the previous 6.3 Bcf type curve was based on performance of the average 2014 and 2015 wells which have a completed length of 1,265 metres and an average of 21 frac stages. More information on the type curve and well economics is provided in the presentation on Storm's website.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Storm's one horizontal well, producing 280 Boe per day, was shut in during July 2015 due to the low natural gas price at BC Station 2.

HEDGING AND TRANSPORTATION

Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow. A maximum of 50% of the most recent monthly production will be hedged; anticipated production growth is not hedged. Although Storm has no oil production, the WTI price is hedged as approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane and butane). A summary for 2016 is provided below.


----------------------------------------------------------------------------
                     Volume                            Price
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Crude Oil           500 Bopd          Collar - WTI Cdn$75.00 X Cdn$90.75/Bbl
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Natural
 Gas       21,250 GJ/d (17,000 Mcf/d)      AECO Cdn$2.98/GJ ($3.72/Mcf)
           11,000 GJ/d (8,800 Mcf/d)   BC Stn 2 price = AECO - Cdn$0.3375/GJ
         33,000 Mmbtu/d (27,800 Mcf/d) Chicago price = AECO + US$0.672/Mmbtu
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Storm's strategy with respect to natural gas transportation commitments is to ensure natural gas sales are diversified by selling at Chicago, AECO and BC Station 2. Current transportation commitments total 63 Mmcf per day in 2016 and increase to 92 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018). A summary is provided below.


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          2016                      2017                      2018
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44 Mmcf/d (55,000         48 Mmcf/d (61,000         53 Mmcf/d (67,000
GJ/d)(1)                  GJ/d)(1)                  GJ/d)(1)

sale at McMahon           sale at McMahon           sale at McMahon
(Alliance Pipeline)       (Alliance Pipeline)       (Alliance Pipeline)
Chicago price -           Chicago price -           Chicago price -
Cdn$1.30/GJ(2)            Cdn$1.30/GJ(2)            Cdn$1.30/GJ(2)
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9.0 Mmcf/d (11,400 GJ/d)  24.0 Mmcf/d (30,200       29.0 Mmcf/d (36,500
sale at BC Stn 2          GJ/d)                     GJ/d)
-Cdn$0.15/GJ pipeline     sale at BC Stn 2          sale at BC Stn 2
tariff                    -Cdn$0.15/GJ pipeline     -Cdn$0.15/GJ pipeline
                          tariff                    tariff

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9.8 Mmcf/d (12,400 GJ/d)                            10.0 Mmcf/d (12,600
sale at McMahon                                     GJ/d)
AECO - Cdn$0.68/GJ                                  sale at AECO
differential                                        -Cdn$0.43/GJ pipeline
                                                    tariffs
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(1)  Interruptible capacity on the Alliance Pipeline adds up to 25% of
     contracted capacity.
(2)  The Alliance Pipeline tariff of $1.30 per GJ is determined assuming
     US$1 = Cdn$1.29, Chicago US$2.20 per Mmbtu and 5.25% shrinkage for fuel
     gas (fuel gas shrinkage adds $$0.14 per GJ).

OUTLOOK

Production in the second quarter is forecast to be approximately 12,500 Boe per day and, until the natural gas price improves, production will be maintained at this level which fulfills firm processing and transportation commitments. Capital investment in the second quarter is expected to be under $2.0 million.

Natural gas prices remain weak with April daily spot prices averaging US$1.92 per Mmbtu at Chicago and $1.04 per GJ at AECO. Forward strip pricing for natural gas for the remainder of 2016 is not materially different from pricing realized in the first quarter where the operating netback excluding hedging gains was $5.20 per Boe. This is less than the cost of adding reserves (the 2015 all-in PDP FD&A cost was $6.53 per Boe) and, as a result, producing more than what's required to fulfill firm processing and transportation commitments is not economically justifiable. As a result, capital investment in 2016 will be reduced to between $37.0 and $42.0 million with the startup of the third facility at Umbach deferred to April 2017 when the forward strip is supportive of production growth. With the benefit of commodity price hedges and with the majority of natural gas production being sold in Chicago at a higher price than at BC Station 2, forecast funds flow in 2016 is expected to provide most of the capital required to maintain production at current levels. Revised guidance is provided below with assumed commodity prices being approximately equal to realized prices to date and the current forward strip.


                     Original Guidance            Revised            Revised
2016 Guidance             Nov 11, 2015       Feb 25, 2016       May 12, 2016
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Chicago natural gas
 price                                  US$2.20 per Mmbtu  US$2.20 per Mmbtu
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AECO natural gas
 price                    $2.50 per GJ       $2.00 per GJ       $1.60 per GJ
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BC STN 2 natural gas
 price                    $1.90 per GJ       $1.45 per GJ       $1.25 per GJ
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Edmonton light oil
 price                  Cdn$57 per Bbl     Cdn$46 per Bbl     Cdn$50 per Bbl
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Estimated average    $7.00 - $7.50 per
 operating costs                   Boe      $7.00 per Boe      $7.00 per Boe
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Estimated average
 royalty rate (%
 production revenue
 before hedging)               7% - 8%            5% - 6%            5% - 6%
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Estimated operations
 capital(excluding
 acquisitions &                                                $37.0 - $42.0
 dispositions)          $105.0 million      $80.0 million            million
----------------------------------------------------------------------------
Estimated cash G&A        $5.0 million       $5.0 million       $5.7 million
 net of recoveries       $0.80 per Boe      $0.95 per Boe      $1.20 per Boe
----------------------------------------------------------------------------
Estimated funds flow                        $39.0 million      $31.0 million
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Forecast fourth        20,000 - 21,000    15,500 - 16,500    13,000 - 14,000
 quarter production              Boe/d              Boe/d              Boe/d
                             (17% NGL)          (18% NGL)          (18% NGL)
----------------------------------------------------------------------------
Forecast annual        16,000 - 18,000    14,000 - 15,000    12,500 - 13,500
 production                      Boe/d              Boe/d              Boe/d
                       (17% oil + NGL)    (18% oil + NGL)    (18% oil + NGL)
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Umbach horizontal       14 gross (14.0     12 gross (12.0
 wells drilled                    net)               net)  8 gross (8.0 net)
Umbach horizontal       14 gross (14.0     10 gross (10.0
 wells completed                  net)               net)  6 gross (6.0 net)
Umbach horizontal       16 gross (16.0     12 gross (12.0
 wells connected                  net)               net)  8 gross (8.0 net)
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With respect to the revised guidance, estimated cash G&A net of recoveries for 2016 has increased as a result of lower overhead recoveries associated with lower capital investment (no change to gross G&A excluding overhead recoveries). As well, capital investment in 2016 includes $6.1 million incurred in the first quarter to purchase major equipment for the third field compression facility.

The AECO - BC Station 2 price differential was -$0.41 per GJ in the first quarter, an improvement from -$0.85 per GJ in 2015 and closer to historical levels (-$0.20 per GJ for 2010 to 2014). Although the low AECO price in the first quarter ($1.74 per GJ) has more than offset the improvement, having the differential return to historical levels is supportive of Storm's future production growth given that incremental production would be sold at BC Station 2.

Reducing cash costs and improving capital efficiency has always been a focus at the current and predecessor 'Storm' companies. Further improvements are expected in 2016 with the largest being the transition to drilling longer horizontal wells with more frac stages which is expected to result in a reduction of the cost to add reserves. Cash costs are also expected to decrease by reducing third party processing fees and through initiatives to reduce field level operating expenses.

Further weakening of natural gas prices in North America over the last three months is the result of reduced demand from a warmer than normal winter combined with continued growth in natural gas production. At current pricing, the business is 'broken' for natural gas producers in Western Canada as funds flow excluding hedges fails to generate sufficient capital to offset declines; as well, rates of return are too low to justify growing production on a full-cycle basis (including the cost of expanding infrastructure). Pricing will improve once the oversupply of natural gas is reduced through natural declines and shut-ins. Not knowing when the natural gas price will improve, Storm's primary objective in 2016 is to maintain a strong balance sheet by ensuring capital investment is approximately equal to funds flow and thus avoid increasing debt. This will preserve the ability to accelerate growth when the price does improve.

Although Storm is reducing capital investment in 2016 as a result of deterioration in the price of natural gas, annual average production in 2016 is still forecast to increase by 30% on a year-over-year basis.

Storm's land position in the Horn River Basin continues to be a core, long-term asset with significant leverage to higher natural gas prices.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

May 12, 2016

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.

Non-GAAP Measures - This document contains the terms "funds from operations", "funds from operations per share", "netbacks", "field netbacks", "field operating income", "total operating income", "cash costs", and measurements "per Boe" which are not recognized under Generally Accepted Accounting Principles ("GAAP") and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. In particular, funds from operations is not intended to represent, or be equivalent to, cash flow from operating activities calculated in accordance with GAAP, which is measured on the Company's consolidated statements of cash flows. Funds from operations and similar non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties. These measurements are also used by lenders to measure compliance with debt covenants and thus set interest costs. Additional information relating to certain of these non-GAAP measures, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the MD&A.

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 and completion plans; capacity of facilities; timing and construction of a third field compression facility and the purchase of equipment in connection therewith; the effect on the Company of the operations capital expenditures being reduced in 2016; hedging; 2016 and 2017 guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated land and property acquisition costs, estimated general and administrative costs, estimated fourth quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt in 2016 and 2017; reserve volumes; commodity prices; production, operating and general and administrative costs; anticipated lower costs for services; anticipated higher level of run rate cash flow associated with a larger production base; natural gas sales; and improvement on controllable cash costs. Statements of "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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 ended March 31, 2016.

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.

Contacts:
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