CALGARY, ALBERTA–(Marketwired – May 13, 2015) – Storm Resources Ltd. (TSX VENTURE:SRX) has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2015 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 and on Storm’s website at

Selected financial and operating information for the three months ended March 31, 2015 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and per-share amounts Three Months Ended
March 31, 2015
Three Months Ended
March 31, 2014
Revenue from product sales 18,512 20,807
Funds from operations(1) 13,712 8,660
Per share – basic ($) 0.12 0.09
Per share – diluted ($) 0.12 0.08
Net income (loss) (3,565 ) 206
Per share – basic ($) (0.03 ) 0.00
Per share – diluted ($) (0.03 ) 0.00
Operations capital expenditures 35,680 22,343
Land and property acquisitions 88,051
Debt including working capital deficiency 85,098 22,176
Common shares (000s)
Weighted average – basic 111,322 100,668
Weighted average – diluted 111,322 102,413
Outstanding end of period – basic 111,322 109,612
(Cdn$ per Boe)
Revenue 21.04 45.62
Royalties (0.54 ) (7.56 )
Production (8.67 ) (10.88 )
Transportation (1.68 ) (1.71 )
Field operating netback 10.15 25.47
Hedging gains (losses) 8.36 (3.10 )
General and administrative (2.24 ) (2.91 )
Interest (0.70 ) (0.47 )
Funds from operations netback 15.57 18.99
Barrels of oil equivalent per day (6:1) 9,776 5,068
Gas Production
Thousand cubic feet per day 47,713 23,711
Price (Cdn$ per Mcf) 2.85 5.63
NGL production
Barrels per day 1,493 725
Price (Cdn$ per barrel) 37.10 84.49
Oil Production
Barrels per day 330 391
Price (Cdn$ per barrel) 43.08 93.08
Wells drilled
Gross 6.0 5.0
Net 6.0 5.0

1) Funds from operations, funds from operations per share and funds from operations netback are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 19 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 20 of the MD&A.



  • Operational success at Umbach continued in the first quarter with horizontal well performance continuing to improve and with the expansion of the second Umbach field compression facility being completed on time and on budget.
  • Production averaged 9,776 Boe per day (19% oil plus NGL), an increase of 91% on a per-share basis from the previous year. The increase was the result of growth at Umbach where first quarter production was 8,579 Boe per day, a year-over-year increase of 141%.
  • NGL production was 1,493 barrels per day, an increase of 106% from the previous year which was the result of production growth from the liquids-rich Montney formation at Umbach where NGL recovery was 33 barrels per Mmcf sales in the quarter. With approximately 60% of the NGL mix being condensate plus pentanes, the NGL price of $37.10 per barrel was 71% of the average Edmonton light oil price.
  • Activity in the quarter was focused at Umbach, where six Montney horizontal wells (6.0 net) were drilled, two horizontal wells (2.0 net) were completed, three horizontal wells (3.0 net) began producing, a 15-kilometre pipeline connecting the first field compression facility to the Stoddart Gas Plant was completed, and the second field compression facility was expanded from 27 to 54 Mmcf per day raw gas.
  • Horizontal well performance at Umbach continues to improve. The first 2015 horizontal well having enough production history averaged 5.6 Mmcf per day gross raw gas over the first 90 calendar days, an improvement of 19% from the average 2014 horizontal well. Field condensate from this well averaged 32 barrels per Mmcf raw gas over the same period, an increase of 60% from the average of all horizontal wells drilled to date (an additional 18 to 42 barrels of NGL per Mmcf sales is also recovered after processing at a gas plant).
  • There is currently an inventory of 10 horizontal wells (10.0 net), which includes one completed horizontal well, that have not started producing at Umbach.
  • Funds from operations was $13.7 million, or $0.12 per basic share, which is an increase of 33% from the prior year.
  • The funds from operations netback was $15.57 per Boe, a year-over-year decrease of 18% which was primarily the result of revenue per Boe declining by $24.58 per Boe, or 54%. This was partially offset by a hedging gain of $8.36 per Boe and by controllable cash costs declining by 17%, or $2.68 per Boe. Controllable cash costs includes operating, transportation, interest and cash general and administrative costs.
  • Net loss was $3.6 million, or $0.03 per share, compared to net income of $0.2 million in the previous year. The net loss was caused in part by the reversal of prior period unrealized hedging gains amounting to $6.8 million (the realized hedging gain of $7.4 million in the first quarter reduced the prior period unrealized hedging gain).
  • Capital investment was focused on the Umbach area and totaled $35.7 million which included $15.4 million for infrastructure and $19.1 million for drilling and completions.
  • For the remainder of 2015, Storm has hedged approximately 40% of forecast natural gas production at an AECO price of $4.17 per Mcf ($3.33 per GJ).
  • Debt plus working capital deficiency was $85.1 million which is 1.6 times annualized first quarter cash flow. In April 2015, Storm’s bank credit line was increased to $150.0 million from $130.0 million.


Storm has a focused asset base with large land positions in resource plays at Umbach and in the Horn River Basin (“HRB”) which have multi-year drilling inventories 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 141 net sections (167 gross sections), or 100,000 net acres. To date, a total of 33.4 net horizontal wells (37.0 gross) have been drilled into the Montney formation with 23.4 net being on production.

First quarter production from Umbach was 8,579 Boe per day, a year-over-year increase of 141%. NGL production was 1,431 barrels per day, an increase of 118% and represents a recovery of 33 barrels per Mmcf sales (approximately 60% of NGL is higher priced field condensate plus pentanes recovered at the gas plant). Revenue from Umbach was $20.64 per Boe ($2.88 per Mcf sales and $37.38 per barrel of NGL), transportation costs were $1.58 per Boe, royalties were $0.46 per Boe (2% of revenue), operating costs were $7.88 per Boe, and the operating netback was $10.73 per Boe.

Activity in the first quarter included drilling six Montney horizontal wells (6.0 net) and completing two Montney horizontal wells (2.0 net) with three horizontal wells (3.0 net) starting production. There remains an inventory of 10 horizontal wells (10.0 net) that have not started producing which includes one completed horizontal well and nine standing horizontal wells awaiting completion.

Storm operates two field compression facilities (both 100% working interest) that have total capacity of 72 Mmcf per day raw gas with throughput in the first quarter averaging 42 Mmcf per day raw gas. The first field compression facility with capacity of 18 Mmcf per day raw gas had average throughput of 17 Mmcf per day raw gas in the first quarter. A 15-kilometre pipeline was constructed in the first quarter to connect the first facility to the Stoddart Gas Plant which is expected to reduce operating costs and increase NGL recovery to 55 barrels per Mmcf sales beginning in April. The second field compression facility was expanded from 27 to 54 Mmcf per day of capacity at the end of March with throughput averaging 25 Mmcf per day of raw gas during the first quarter. Investment to expand infrastructure at Umbach in the first quarter totaled $13.5 million. In the second quarter of 2015, a condensate stabilizer and other equipment will be installed at the second facility with the estimated cost being $6.4 million. These additions will improve condensate pricing and also reduce operating costs.

The operating cost at Umbach is expected to decline to $6.50 to $6.75 per Boe by the fourth quarter of 2015 as a result of continued production growth, recent longer term processing commitments which have a lower associated fee, wells recently converted to salt water disposal, and equipment additions at the second field compression facility.

Engineering design has been completed for a third field compression facility and $4.0 million will be invested to purchase major equipment in 2015 ($2.0 million in the first quarter). This facility is expected to be operational in mid-2016 with the total cost estimated to be $24.0 million for 35 Mmcf per day raw gas capacity which will be expandable to 70 Mmcf per day for an additional investment of $7.0 million.

Storm recently contracted for transportation of up to 31.8 Mmcf per day of natural gas on the Alliance Pipeline for delivery to the Chicago market starting December 2015. The actual capacity allocated to Storm is expected to be finalized by August. Based on the current forward strip for natural gas sold at Chicago, plantgate pricing after deducting applicable pipeline tariffs is expected to be comparable to the price at AECO. Shipping on the Alliance Pipeline diversifies market access for Storm and will mitigate any future weakness in the AECO – BC Station 2 price differential which was -$0.59 per GJ in the first quarter (approximately 44% of Storm’s natural gas production was sold at the BC Station 2 daily spot price in the first quarter). For reference, the differential averaged -$0.21 per GJ from 2011 to 2014. The increase in the price differential in the first quarter is expected to be temporary and was caused by continued growth of natural gas production from northeast British Columbia and unplanned maintenance reducing flows onto the TransCanada NGTL Pipeline system in Alberta. This resulted in additional volumes being sold into the smaller BC Station 2 market and widened the differential to AECO.

Performance of the 2014 and 2015 horizontal wells shows significant improvement over earlier wells when rates are compared over the first 90 and 180 calendar days (includes downtime).

IP 90 Cal Day Gross
Raw Mmcf Per Day
IP 180 Cal Day Gross
Raw Mmcf Per Day
1st Year Cal Day Gross
Raw Mmcf Per Day
2011 – 2012 hz’s (7 wells) 7 – 14 1.9 Mmcf/d
345 Boe/d sales
7 hz’s
1.4 Mmcf/d
255 Boe/d sales
7 hz’s
1.3 Mmcf/d
235 Boe/d sales
7 hz’s
2013 hz’s (6 wells) 16 – 18 4.0 Mmcf/d
725 Boe/d sales
6 hz’s
2.9 Mmcf/d
525 Boe/d sales
6 hz’s
2.2 Mmcf/d
400 Boe/d sales
6 hz’s
2014 hz’s (10 wells) 16 – 20 4.7 Mmcf/d
850 Boe/d sales
10 hz’s
4.9 Mmcf/d
885 Boe/d sales
7 hz’s
4.3 Mmcf/d
780 Boe/d sales
1 hz
2015 hz’s (3 wells) 18 – 22 5.6 Mmcf/d
1,015 Boe/d sales
1 hz

Note: Sales volume is calculated using 8% shrinkage from raw gas to sales and 30 barrels of NGL per Mmcf sales.

Based on the performance of the 2014 horizontal wells with 16 to 20 frac stages, Storm management is using a 6.3 Bcf raw gas type curve for internal budgeting purposes (this type curve has same decline profile as the 3.2 and 4.4 Bcf raw gas 2P type curves used by InSite in the 2014 reserve evaluation). With a 6.3 Bcf raw gas type curve, the first year average rate is 3.6 Mmcf per day gross raw gas or 650 Boe per day sales (8% shrinkage from raw gas to sales and 30 barrels of NGL per Mmcf sales). Based on a cost of $5.4 million to drill, complete and tie in a horizontal well with 20 to 24 frac stages, the payout is approximately 25 months and the rate of return is 31% using $2.80 per GJ at AECO and Cdn $68.00 per barrel for Edmonton light oil (approximate 2016 forward strip pricing held flat for the life of the well). See the presentation on Storm’s website for further details. In 2014, the actual cost to drill, complete, and tie-in a horizontal well with 16 to 20 frac stages averaged $4.9 million. Drilling times averaged approximately 14 days. The average tie-in cost was $0.3 million per horizontal well which doesn’t include the cost of longer gathering pipelines to connect multi-well pads to field compression facilities. With the 2015 horizontal wells having an increased number of frac stages (20 to 24), the cost to drill, complete, and tie in a horizontal well has increased to $5.4 million. These results do not recognize any improvement in service costs in 2015.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the HRB (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. First quarter production averaged 281 Boe per day (100% natural gas), a year-over-year decline of 26%. The operating netback was $0.40 per Boe with revenue of $12.56 per Boe, transportation costs of $0.63 per Boe, an operating cost of $11.09 per Boe and a royalty of $0.44 per Boe, or 3% of revenue.

Grande Prairie Area, Northwest Alberta

Production in the first quarter was 916 Boe per day (43% oil plus NGL), a year-over-year decline of 19%. In mid-January 2015, approximately 150 Boe per day of natural gas burdened with higher third party processing fees was shut in as a result of the recent decline in the natural gas price. The operating netback was $8.36 per Boe with revenue of $28.14 per Boe, a transportation cost of $2.93 per Boe, an operating cost of $15.52 per Boe and a royalty of $1.32 per Boe, or 5% of revenue. Cash flow from this area continues to be re-invested to grow production at Umbach.


For April to December of 2015, 23,900 Mcf per day (29,900 GJ per day) of natural gas is hedged at an average AECO price of approximately $4.17 per Mcf (AECO monthly index $3.33 per GJ).

During January 2015, Storm’s oil hedges for 2015 were unwound for net proceeds of $5.1 million.

For 2016, 8,000 Mcf per day (10,000 GJ per day) of natural gas is hedged at an average AECO price of approximately $3.75 per Mcf (AECO monthly index $3.00 per GJ). Storm plans to continue adding to the 2016 hedge position during the remainder of 2015.

The purpose of Storm’s commodity price hedges is to reduce the effect of commodity price fluctuations on capital investment and growth over the next 12 months. A maximum of 50% of current production (most recent monthly or quarterly average), before royalties, will be hedged; anticipated production growth is not hedged.


Production in April 2015 averaged 11,900 Boe per day based on field estimates and production in the second quarter of 2015 is forecast to be 10,000 to 10,500 Boe per day which includes the effect of a 21-day maintenance turnaround at the McMahon Gas Plant in June which is expected to reduce second quarter production by 1,700 Boe per day. Capital investment in the second quarter is expected to total $9.0 to $11.5 million which includes completing one horizontal well (1.0 net) and $6.4 million to add equipment at the second field compression facility at Umbach.

Guidance for 2015 remains unchanged from that provided on February 26, 2015.

2015 Guidance November 13, 2014
Original Guidance
February 26, 2015
Revised Guidance
AECO natural gas price $3.25 per GJ $2.35 – $2.90 per GJ
BC STN 2 natural gas price $3.00 per GJ $2.05 – $2.60 per GJ
Edmonton light oil price Cdn$83 per Bbl Cdn$53 – $62 per Bbl
Estimated average operating costs $7.50 – $8.00 per Boe $8.00 – $8.50 per Boe
Estimated average royalty rate (on production revenue before hedging) 12% – 14% 6% – 10%
Estimated operations capital (excluding acquisitions & dispositions) $110.0 million $80.0 million
Estimated cash G&A net of recoveries $5.3 million $5.3 million
Forecast fourth quarter production 14,000 – 14,500 Boe/d
(18% oil + NGL)
14,000 – 14,500 Boe/d
(19% oil + NGL)
Forecast annual production 11,500 – 12,700 Boe/d
(19% oil + NGL)
11,000 – 12,000 Boe/d
(20% oil + NGL)
Umbach horizontal wells drilled 9 gross (9.0 net) 6 gross (6.0 net)
Umbach horizontal wells completed 14 gross (14.0 net) 11 gross (11.0 net)
Umbach horizontal wells starting production 16 gross (16.0 net) 14 gross (14.0 net)

Capital investment in 2015 includes:

  • $47.8 million at Umbach for drilling and completions;
  • $23.4 million to expand infrastructure at Umbach, including expansion of the second field compression facility from 27 Mmcf per day to 54 Mmcf per day in the first quarter, plus $4.0 million to order major equipment for a third field compression facility.

Total debt at the end of 2015 is forecast to be $91.0 million assuming average 2015 pricing of AECO Cdn$2.58 per GJ and Edmonton light oil Cdn$61.50 per barrel which represent actual prices to date plus current forward strip pricing for the remainder of 2015. This would be approximately 1.6 times annualized funds from operations in the fourth quarter of 2015.

If the natural gas price increases from current levels during 2015 and provides an incentive for doing so, Storm can accelerate the timing for completing the nine standing horizontal wells which would increase production in the second half of 2015. There is currently approximately 16 Mmcf per day of unused raw gas compression capacity at Umbach.

With approximately 35% of Storm’s first quarter revenue coming from oil and NGL sales (excluding hedging gains), the recent improvement in the price of oil will also increase Storm’s revenue and cash flow. The Edmonton light oil price is currently approximately Cdn$66.00 per barrel (WTI US$58 per barrel) which is $14.00 per barrel higher than the price in the first quarter and would increase Storm’s first quarter oil price by approximately 33% and the NGL price by approximately 23% which adds $1.50 per Boe to the operations netback.

The corporate operating cost is expected to decline from $8.67 per Boe in the first quarter to below $7.50 per Boe in the fourth quarter as a result of operating costs at Umbach declining below $6.75 per Boe in the fourth quarter of 2015.

At Umbach, Montney horizontal wells continue to offer attractive rates of return at current forward strip pricing for oil and natural gas given that NGL recovery increases revenue while the relatively shallow depth of the Montney (1,400 to 1,600 metres) results in a lower drilling and completion cost. With a strong balance sheet, an evolving plan to expand infrastructure at Umbach, and improving capital efficiencies, Storm expects to meet or exceed 2015 production guidance and remains well positioned for continued rapid growth into 2016.

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


Effective May 1, 2015, Jamie Conboy was appointed Vice President, Geology, Darren Evans was appointed Vice President, Exploitation and Bret Kimpton was appointed Vice President, Production. All three joined Storm predecessor companies between 1999 and 2005 and have made meaningful contributions towards the success of Storm.


Brian Lavergne, President and Chief Executive Officer

May 13, 2015

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.

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; capacity of facilities; installation of a condensation stabilizer and equipment; construction of a 15-kilometer pipeline; 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 2015; 2015 guidance in respect of certain operational and financial metrics, including, but not limited to, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated land and property acquisitions 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 at end of 2015; reserve volumes; capital expenditures; royalties; financing; commodity prices; and production, operating and general and administrative 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, 2015.

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.