CALGARY, ALBERTA–(Marketwired – May 14, 2014) – Storm Resources Ltd. (TSX VENTURE:SRX)
Storm has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2014 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 stormresourcesltd.com.
Selected financial and operating information for the three months ended March 31, 2014, appears below and should be read in conjunction with the related financial statements and MD&A.
|Thousands of Cdn$, except volumetric
and per-share amounts
|Three Months Ended
March 31, 2014
|Three Months Ended
March 31, 2013
|Revenue from product sales(1)||20,807||9,048|
|Funds from operations(2)||8,660||3,227|
|Per share – basic ($)||0.09||0.05|
|Per share – diluted ($)||0.08||0.05|
|Net income (loss)||206||(261||)|
|Per share – basic ($)||0.00||0.00|
|Per share – diluted ($)||0.00||0.00|
|Operations capital expenditures||22,343||20,133|
|Acquisitions and dispositions||88,051||(19,496||)|
|Debt including working capital deficiency||22,176||42,106|
|Weighted average common shares outstanding (000s)|
|Common shares outstanding (000s)|
|Oil equivalent (6:1)|
|Barrels of oil equivalent (000s)||456||224|
|Barrels of oil equivalent per day||5,068||2,488|
|Average selling price (Cdn$ per Boe)(1)||45.62||40.37|
|Thousand cubic feet (000s)||2,134||880|
|Thousand cubic feet per day||23,711||9,780|
|Average selling price (Cdn$ per Mcf)||5.63||3.46|
|Barrels per day||725||261|
|Average selling price (Cdn$ per barrel)||84.49||67.08|
|Barrels per day||391||597|
|Average selling price (Cdn$ per barrel)(1)||93.08||82.21|
|(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 9 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 19 of the MD&A.|
FIRST QUARTER 2014 HIGHLIGHTS
- Production in the first quarter was 5,068 Boe per day (22% oil plus NGL), an increase of 104% from the same period last year and 6% from the prior quarter. On a per-share outstanding at quarter end basis, the year-over-year increase was 15%. The increase resulted from growth at Umbach where first quarter production was 3,559 Boe per day which represents growth of 565% from the first quarter of 2013.
- NGL production was 725 barrels per day in the first quarter, a year-over-year increase of 178%. NGL production increased as a result of production growth from the liquids-rich Montney formation at Umbach. The first quarter NGL price of $84.49 per barrel was 84% of the average Edmonton Par light oil price.
- Activity in the first quarter of 2014 was focused on Storm’s 100% working interest lands at Umbach South where four Montney horizontal wells (4.0 net) plus one Montney vertical delineation well (1.0 net) were drilled and two horizontal wells (2.0 net) were completed and pipeline connected. As the existing facility is at capacity, only one of the completed Montney horizontal wells started producing in late February with the average rate in March and April being restricted to 4.3 Mmcf per day gross raw gas. The remaining Montney horizontal wells will start producing in September when Storm’s new facility at Umbach is operational.
- Funds from operations for the quarter totaled $8.7 million or $0.09 per basic share, a year-over-year increase of 80% on a per-share basis. The increase in funds from operations was the result of growth at Umbach where the field operating netback was $27.03 per Boe which is higher than the corporate average.
- The funds from operations netback was $18.99 per Boe in the quarter, an increase of $4.58 per Boe or 32% from the prior year. The year-over-year improvement was primarily the result of lower operating costs and the first quarter natural gas price increasing to $5.63 per Mcf from $3.46 per Mcf in the prior year period. These gains were partially offset by a hedging loss of $3.10 per Boe.
- The field operating netback, excluding hedging gains or losses, was $25.47 per Boe for the quarter, an increase of 26% from $20.14 per Boe in the previous year. The first quarter operating cost was $10.88 per Boe, a decrease of 20% from the prior year. Operating costs are improving due to growth at Umbach where the first quarter operating cost was $7.78 per Boe.
- Controllable cash costs (operating, transportation, cash G&A, interest expense) were $15.97 per Boe in the quarter which is a decrease of $4.84 per Boe, or 23%, from $20.81 per Boe in the prior year.
- Capital investment was $110.4 million in the first quarter which included $88.0 million for an asset acquisition at Umbach. Operations capital expenditures totaled $22.3 million and included $3.4 million for facilities and pipelines plus $17.8 million for drilling and completions.
- Debt plus working capital deficiency, net of investments, at the quarter end totaled $22.2 million which is 0.6 times annualized first quarter cash flow. In May 2014, Storm’s banker, ATB Financial, increased the revolving bank facility to $90.0 million.
- On January 31, 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. The total cost of approximately $88.0 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).
- On February 14, a bought deal financing and non-brokered private placement of common shares were completed with 8.5 million common shares being issued at a price of $4.10 per common share. Aggregate gross proceeds of $34.9 million were used to fund the cash portion of the acquisition of land and production in the Umbach-Nig area that closed January 31, 2014.
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 140 net sections (168 gross sections), or 98,000 net acres. Including the lands acquired in January 2014, Storm has invested $108.0 million to acquire this land position ($2,750 per hectare or $1,100 per acre) since entering the area in 2010. 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 first quarter production averaged 2,676 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 first quarter production averaged 883 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.
First quarter production at Umbach was 3,559 net Boe per day (18% NGL), a year-over-year increase of 565%. NGL recovery was 38 barrels per Mmcf sales or 656 barrels per day with approximately 60% being higher priced condensate plus pentanes. The operating netback was $27.03 per Boe with revenue, after deducting transportation costs, of $42.32 per Boe ($5.56 per Mcf sales and $81.65 per barrel of NGL), a royalty rate of 18%, and operating costs of $7.78 per Boe. Operating costs at Umbach have improved significantly from $11.48 per Boe in the first quarter of 2013. Notably, on the 100% working interest lands at Umbach South where Storm owns field compression, the operating cost was $6.55 per Boe.
Activity in the first quarter included drilling four Montney horizontal wells (4.0 net) at Umbach South, drilling one Montney vertical delineation well (1.0 net) at Nig and completing two Montney horizontal wells (2.0 net). One Montney horizontal well commenced production in late February with the rate being restricted to 4.3 Mmcf per day gross raw gas in March and April as the existing facility is full. This horizontal well has averaged 6.0 Mmcf per day gross raw gas to date in May as a result of facility upgrades completed in early May. The vertical delineation well at Nig was cored in the upper, middle, and lower Montney and, after the core data has been analyzed, the wellbore will be re-entered and a horizontal well will be drilled into one of the three Montney intervals (likely in 2015). To date in the second quarter, an additional three Montney horizontal wells (3.0 net) have been drilled and two Montney horizontal wells (2.0 net) have been completed.
The existing Umbach South field compression facility has been full since December 2013 with throughput of approximately 17 Mmcf per day gross raw gas. As a result, a second field compression facility is being constructed with initial capacity of 24 Mmcf per day which is expected to be operational in September 2014. Cost of the new field compression facility is $14.0 million and it is designed to be expandable to 48 Mmcf per day for an additional investment of $9.0 million, with this expected to occur in mid-2015. Investment in infrastructure at Umbach in 2014 will also include installing 12 kilometers of larger diameter gathering pipelines at a cost of $5.0 million.
Currently, there are 16 horizontal wells producing from the Montney formation at Umbach. Production performance of the most recent horizontal wells (Umbach South hz’s 10 – 15) is significantly improved from earlier wells and is exceeding management’s forecasts. Following is a comparison of calendar day rates for all of the producing Montney horizontal wells.
|Start of Production||
|30 Cal Day
|90 Cal Day Gross
|1st Year Cal Day Gross
|Hz’s 1 – 5||60||%||Umbach North||Mar/11 – Oct/12||7 – 11||2.8 Mmcf/d
|Hz’s 6 – 8||60||%||Umbach North||Nov/12 – Aug/13||14 – 16||3.3 Mmcf/d
|Hz’s 10 – 15||100||%||Umbach South||Apr/13 – Nov/13||17 – 18||4.2 Mmcf/d
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. First quarter production averaged 380 Boe per day at an operating netback of $17.03 per Boe. Production is from one horizontal well with 12 fracture stimulations which currently produces 2.5 Mmcf per day gross raw gas with cumulative production of 4.0 Bcf gross raw gas since start-up in March 2011.
A resource evaluation completed by InSite Petroleum Consultants Ltd. 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 24% 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 38 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 first quarter averaged 1,129 Boe per day (41% oil plus NGL) at an operating netback of $23.43 per Boe. Production was reduced by approximately 115 Boe per day as a result of equipment failures on seven wells. The cost of repairing the wells increased the first quarter operating cost to $21.10 per Boe (2013 average operating cost was $14.72 per Boe). Production in April recovered to 1,260 Boe per day based on field estimates. Cash flow from this area continues to be re-invested to grow production at Umbach.
Current commodity price hedges, which comprise both swaps and collars, for the remainder of 2014 include 11,800 Mcf per day (14,200 GJ per day) of natural gas with an average floor price of approximately $4.16 per Mcf and an average ceiling price of $4.38 per Mcf (AECO monthly index $3.38 per GJ for the floor and $3.56 per GJ for the ceiling). In addition, an oil price of WTI Cdn$102.43 per barrel (WTI price in $US per barrel converted to $Cdn per barrel) has been fixed on 450 barrels per day.
In the first quarter of 2015, the price of 5,800 Mcf per day (7,000 GJ per day) of natural gas has been hedged with an average floor price of approximately $4.92 per Mcf and an average ceiling price of $6.25 per Mcf (AECO monthly index $4.00 per GJ for floor and $5.08 per GJ for ceiling).
The purpose of Storm’s commodity price hedges is to ensure that a decrease in commodity prices does not have a significant impact on capital investment and growth over the next 12 to 18 months.
Production in April averaged 5,350 Boe per day based on field estimates, and second quarter production is forecast to be 5,200 to 5,500 Boe per day. Corporate production will increase when the new field compression facility is operational at Umbach in September 2014.
As a result of a higher forecast natural gas price and the recent changes to British Columbia’s Deep Well Royalty Credit Program, Storm is increasing 2014 capital investment from $78.0 million to $97.0 million. The incremental capital will be invested at Umbach to drill an additional four Montney horizontal wells (4.0 net) and complete four Montney horizontal wells (3.6 net). Forecast production for the fourth quarter of 2014 increases to 8,900 to 9,200 Boe per day which represents 90% growth on a year-over-year basis (55% growth on a per-share basis). Revised guidance is set forth below.
|January 23, 2014
|May 14, 2014
|AECO natural gas price||$3.35 per GJ||$4.25 per GJ|
|Edmonton Par light oil price||Cdn $89 per bbl||Cdn $94 per bbl|
|Estimated year-end debt plus working capital deficiency(1)||$50.0 million||$57.0 million|
|Estimated average operating costs||$8.00 – $9.00 per Boe||$8.00 – $9.00 per Boe|
|Estimated average royalty rate (on production revenue before hedging)||14% – 15||%||15% – 16||%|
|Estimated operations capital, excluding acquisitions & dispositions||$78.0 million||$97.0 million|
|Estimated acquisitions||$88.0 million||$88.0 million|
|Estimated cash G&A net of recoveries||$4.0 million||$4.0 million|
|Forecast fourth quarter average production||7,500 – 7,900 Boe/d||8,900 – 9,200 Boe/d|
|(20% oil + NGL||)||(20% oil + NGL||)|
|Forecast average annual production||5,500 – 6,500 Boe/d||6,000 – 6,700 Boe/d|
|(21% oil + NGL||)||(21% oil + NGL||)|
|Umbach horizontal wells drilled||10 gross (10.0 net||)||14 gross (14.0 net||)|
|Umbach horizontal wells completed & tied in||9 gross (9.0 net||)||13 gross (12.6 net||)|
(1) Includes value of publicly listed securities.
Adjusted net debt at the end of 2014 is forecast to be $57.0 million (including public company investments), which would be approximately 0.9 times annualized funds from operations in the fourth quarter of 2014 (assumes fourth quarter AECO $3.75 per GJ and Edmonton Par Cdn$87.00 per barrel).
The recently announced changes to British Columbia’s Deep Well Royalty Credit Program provides a royalty credit of approximately $0.6 million for a Montney horizontal well with a 1,200 metre lateral drilled at Umbach after April 1, 2014. The royalty credit reduces the royalty rate to 6% until the credit is used up which is forecast to be approximately 14 months at an AECO natural gas price of $3.75 per GJ. Eight of Storm’s Montney horizontal wells being drilled at Umbach in 2014 will benefit from the royalty credit which will be re-invested to drill and complete additional horizontal wells at Umbach.
At Umbach, one drilling rig has been working since early December 2013 and has drilled eight Montney horizontal wells (8.0 net) with seven horizontal wells drilled as part of the 2014 program. Drilling operations have continued through spring break-up and the remaining seven Montney horizontal wells (7.0 net) in the 2014 program are expected to be drilled by the end of August. Four Montney horizontal wells (4.0 net) have been completed so far in 2014 with one well commencing production in late February. Horizontal well performance is exceeding management’s forecast which has moderated declines. As a result, the existing facility is full and most of the newly drilled Montney horizontal wells will commence production once construction of the new 24 Mmcf per day field compression facility is completed in September 2014. The decision to expand the new facility to 48 Mmcf per day
will likely be made in the fourth quarter of 2014 with approximately six to eight months being required to order equipment and for construction of the expansion. With a growing inventory of horizontal wells to be turned on when the second field compression facility is completed, significant growth is expected at Umbach in the second half of 2014.
Storm’s land position in the HRB continues to be a core, long-term asset with significant leverage to improving natural gas prices.
Brian Lavergne, President and Chief Executive Officer
May 14, 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.
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 ended March 31, 2014.
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.