CALGARY, ALBERTA–(Marketwired – May 15, 2013) – Storm Resources Ltd. (TSX VENTURE:SRX)
Storm has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2013 and for the three months then ended along with the 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, 2013, appears below and should be read in conjunction with the related financial statements and MD&A.
|Three Months Ended||Three Months Ended|
|Thousands of Cdn$, except volumetric and per-share amounts||March 31, 2013||March 31, 2012|
|Revenue from product sales(1)||9,048||3,390|
|Funds from operations(2)||3,227||(63||)|
|Per share – basic ($)||0.05||0.00|
|Per share – diluted ($)||0.05||0.00|
|Net income (loss)||(261||)||(1,615||)|
|Per share – basic ($)||0.00||(0.04||)|
|Per share – diluted ($)||0.00||(0.04||)|
|Field capital expenditures||20,136||3,216|
|Proceeds on disposition of oil and gas properties||(19,499||)||(1,009||)|
|Debt including working capital deficiency||42,106||50,300|
|Weighted average common shares outstanding (000s)|
|Common shares outstanding (000s)|
|Oil equivalent (6:1)|
|Barrels of oil equivalent (000s)||224||112|
|Barrels of oil equivalent per day||2,488||1,229|
|Average selling price (Cdn$ per Boe)(1)||40.37||30.31|
|Thousand cubic feet (000s)||880||515|
|Thousand cubic feet per day||9,780||5,659|
|Average selling price (Cdn$ per Mcf)||3.46||2.24|
|Barrels per day||261||77|
|Average selling price (Cdn$ per barrel)||67.08||81.96|
|Barrels per day||597||208|
|Average selling price (Cdn$ per barrel)(1)||82.21||87.44|
|(1)||Excludes hedging gains.|
|(2)||Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 8 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.|
FIRST QUARTER 2013 HIGHLIGHTS
- First quarter production averaged 2,488 Boe per day with 34% being oil plus NGL. This is a year-over-year increase of 102%, or 33% on a per-share basis, resulting from growth at Umbach plus the acquisitions of Storm Gas Resource Corp. (“SGR”) and Bellamont Exploration Ltd. (“Bellamont”) which closed during the first quarter of 2012. Compared to the previous quarter, production declined by 327 Boe per day as a result of first quarter asset dispositions and from production at Umbach being shut in for a total of 20 days. In addition, three completed and tied in horizontal wells (1.8 net) at Umbach were shut in for most of the first quarter due to capacity constraints with third party field compression. Production in April increased to average 3,400 Boe per day with the start-up of three Montney horizontal wells (2.2 net) at Umbach and after completing the acquisition of capacity in an existing facility.
- The field operating netback was $20.14 per Boe excluding hedging gains, with operating costs of $13.54 per Boe being $1.86 per Boe higher than the previous quarter. The increase in operating costs was due to repair costs associated with downhole equipment failures on wells in the Grande Prairie area and downtime at Umbach.
- Funds from operations was $3.2 million, or $0.05 per basic share, an increase from funds flow of $0.00 per basic share in the year ago period. The increase in funds from operations is the result of production growth at Umbach and from production added in the Grande Prairie area through the Bellamont transaction which closed March 23, 2012.
- Net capital investment was $0.6 million which includes investment in operations of $20.1 million which was mostly offset by net proceeds of $19.5 million from two asset dispositions that closed in the first quarter. The majority of operations capital expenditures were at Umbach with $9.5 million invested in drilling and completions and $2.4 million to expand infrastructure.
- First quarter activity was focused on the Montney formation at Umbach where two horizontal wells (1.6 net) were drilled and two horizontal wells (1.6 net) were completed and pipeline connected. A six kilometer gathering pipeline was constructed at Umbach to connect Storm’s first 100% working interest horizontal well to a facility where Storm acquired 20 Mmcf per day of capacity ($4.5 million purchase closed April 1, 2013).
- Net loss was $0.3 million or $0.00 per basic share, an improvement from the net loss of $0.04 per basic share a year earlier. The improvement was primarily due to a gain on the disposal of oil and gas properties plus increased production from growth at Umbach and from the acquisitions of Bellamont and SGR in the first quarter of 2012.
- Debt plus the working capital deficiency was $42.1 million which is a quarter-over-quarter decrease of $2.6 million. The adjusted net debt at the end of the first quarter was $38.6 million after including the market value of $3.5 million for Storm’s investment in a publicly listed company at the end of the quarter. Storm’s bank credit line is $52.0 million.
- Subsequent to the quarter end, two equity financings were completed whereby Storm issued 15.6 million shares at a price of $1.88 per share for gross proceeds of $29.3 million. This included a bought deal financing under a short form prospectus for 12.6 million shares and a non-brokered financing where 3.0 million shares were issued to certain directors, officers and employees of Storm. Estimated net proceeds from both financings is approximately $28.0 million. Including the net proceeds from the equity financing completed on May 1, 2013, pro-forma adjusted net debt decreases to $10.7 million.
Storm has a focused asset base with large land positions in resource plays at Umbach and in the Horn River Basin (“HRB”) each of which has multi-year drilling upside, while the Grande Prairie Area with its shallower decline provides cash flow available for investment.
Umbach, North East British Columbia
Storm’s land position at Umbach totals 108 net sections (134 gross section) or 76,000 net acres and is split into two project areas with one consisting of 73 sections of land at a 100% working interest and the other with 61 gross sections of jointly owned lands (35 net sections with an average Storm working interest of 57%). First quarter production averaged 534 Boe per day (30% liquids) and was impacted by 20 days of total downtime including a two week shut-in in order to repair a third party field compression facility. NGL recovery was 72 barrels per Mmcf sales which included 45% condensate plus pentanes recovered during processing, 27% butane and 28% propane. The first quarter operating netback was $16.54 per Boe with revenue of $32.62 per Boe, a royalty rate of 14% and operating costs were $11.55 per Boe. Operating costs were $1.75 per Boe higher than the previous quarter primarily because of downtime. Production in April increased to approximately 1,600 Boe per day.
On the joint lands, nine horizontal wells have been drilled with seven of those having been completed and tied in through third party field compression to the Stoddart Gas Plant where NGL recovery was 72 barrels per Mmcf sales gas in the first quarter. Three horizontal wells (1.8 net) were shut in for most of the first quarter because of capacity constraints with third party field compression. In April, two of the shut-in horizontal wells were brought on at restricted rates after pipeline modifications were completed which increased capacity from 7 to 10 Mmcf per day gross raw gas. One completed and tied-in horizontal well with sustainable production capability of 400 net Boe per day is still shut-in and there are also two standing horizontal wells awaiting completion and tie-in. In the near term, capacity constraints are expected to result in production from the joint lands being restricted to 1,000 to 1,200 net Boe per day. A pipeline to interconnect three of the joint horizontal wells to Storm-owned field compression will be constructed during June or July and is expected to increase production from the joint lands to 1,500 net Boe per day. The remaining two standing horizontal wells are expected to be completed and tied in during the second half of 2013 as production declines and field compression capacity becomes available.
On the 100% working interest lands, one horizontal well has been drilled, completed and began producing April 2nd into a field compression facility where 20 Mmcf per day of capacity was acquired by Storm for $4.5 million on April 1st. A six kilometer gathering pipeline was constructed in the first quarter to connect this well to the facility and this pipeline will also be used to connect future horizontal wells. Production through this facility is directed to the McMahon Gas Plant for processing with NGL recovery forecast to be 40 to 45 barrels per Mmcf sales. Although NGL recovery is lower than on the joint lands, the field netback is forecast to be $4 to $5 per Boe higher as a result of lower operating costs (primarily from eliminating third party fees for field compression). In the second half of 2013, four additional horizontal wells are expected to be drilled on the 100% working interest lands and will be tied in to this facility.
The gross cost to drill and complete horizontal wells in the first quarter averaged $4.9 million and the pipeline tie-ins were $0.5 million. Drilling and completion costs are expected to decrease in the second half of 2013 as activity transitions from resource delineation to development on Storm’s 100% working interest lands.
Grande Prairie Area, North West Alberta and North East British Columbia
Production in this area comes from properties acquired through the transaction with Bellamont which closed in the first quarter of 2012. Production in the first quarter averaged 1,584 Boe per day (44% oil plus NGL) at an operating netback of $24.22 per Boe. During the first quarter, the Rycroft property was sold January 18th (30 Boe per day) and the Saddle Hills and Gold Creek properties were sold February 15th (275 Boe per day) with net proceeds from both transactions totaling $19.5 million. Production in April averaged approximately 1,400 Boe per day (34% oil plus NGL).
There was minimal activity in the first quarter. Downhole failures on four wells were repaired in the Grimshaw Montney and Grande Prairie Montney pools which increased operating costs by $190,000. At Grimshaw, initial response from water injection into the Montney A pool has been very encouraging with no decline in pool production since injection began in August 2012.
Horn River Basin, North East British Columbia
Storm’s has a 100% working interest in 135 sections in the HRB (87,700 net acres) which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. First quarter production in the HRB averaged 370 Boe per day at an operating netback of $8.42 per Boe. Production is from a horizontal well with 12 fracture stimulations that began producing in March 2011 and is currently producing 2.7 Mmcf per day gross raw gas with cumulative production of 3.1 Bcf gross raw gas.
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. This area includes 30 sections at a 100% working interest and represents 22% of Storm’s total land holdings in the HRB. Productivity has been proven across the core producing area with one horizontal well that has been producing for 27 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.
Guidance for 2013 is being revised to reflect increased capital investment in the Umbach area, higher natural gas prices and the net proceeds received from the equity financing completed May 1, 2013. Capital investment will increase to $47 million net of asset acquisitions and dispositions, an increase of $22 million from previous guidance provided February 28, 2013. Updated guidance is provided below:
|Revised 2013 Guidance||Previous|
|Year-end adjusted debt plus working capital deficiency (1)||$||37 million||$||44 million|
|Average operating costs||$||10 – $11 per Boe||$||10 – $11 per Boe|
|Average royalty rate (on production revenue before hedging)||13% – 14||%||11% – 12||%|
|Operations capital, excluding dispositions||$||62.0 million||$||40.0 million|
|Asset dispositions||$||19.5 million||$||20.0 million|
|Asset acquisitions||$||4.5 million||$||4.5 million|
|Cash G&A||$||3.7 million||$||3.9 million|
|Exit or fourth quarter average production||4,500 – 5,000 Boe/d||4,000 – 4,500 Boe/d|
|(25% oil + NGL||)||(25% oil + NGL||)|
|(1)||Includes value of publicly listed securities.|
Production in the second quarter of 2013 is expected to be 3,200 to 3,500 Boe per day which includes the effect of shutting in the horizontal well in the HRB for the month of June due to a turnaround at the Fort Nelson Gas Plant.
Major expenditures in the 2013 capital investment program include:
- $15 million to drill seven horizontal wells (6.2 net) at Umbach which includes five horizontal wells at a 100% working interest;
- $19 million to complete and tie in seven horizontal wells (6.2 net) at Umbach which includes five horizontal wells on 100% working interest lands and two horizontal wells (1.2 net) on joint lands;
- $6 million to expand infrastructure at Umbach.
Storm’s 2013 budget assumes an average natural gas price at AECO of $3.25 per GJ and an Edmonton Par oil price of $87 per barrel. Adjusted net debt is forecast to decrease to $37 million at the end of 2013 (including public company investments) which is well within Storm’s current bank line of $52 million and would be approximately 1.5 times funds from operations for the year.
In 2013, we are focused on growing production and cash flow at Umbach in order to validate the large scale and economics of exploiting the liquids-rich natural gas resource in the Montney formation. The recent purchase of 20 Mmcf per day of capacity in a field compression facility at Umbach was a critical first step in providing Storm with access to Company-owned and controlled infrastructure as cost effectively as possible. Results from recent horizontal wells at Umbach where completion techniques have been modified are encouraging as evidenced by production to date in the second quarter averaging 1,700 net Boe per day, a significant increase from 534 net Boe per day in the first quarter. Approximately 32% of Storm’s land position at Umbach has been delineated with well control, and reserves at the end of 2012 were assigned on 5% of Storm’s land position (10 gross sections or 6 net sections) in the upper Montney only. Based on results in the area, the mid/lower Montney is also likely productive and represents an additional layer of future development. At the end of 2012, no reserves were assigned to Storm’s 100% working interest lands. If results at Umbach are supportive of doing so, development may be accelerated later in 2013 with funding being provided by additional asset sales or from Storm’s bank line and growing cash flow.
Total cash costs of $20.81 per Boe in the first quarter are recognized as being relatively high and will be reduced during 2013. Cash G&A costs are fixed and will decrease on a per-Boe basis as production grows during the year. Operating costs will decline with production growth from new horizontal wells on Storm’s 100% working interest lands at Umbach which will be directed through Company-owned field compression where operating costs are expected to be $4 to $5 per Boe lower than on the joint lands.
Storm’s land position in the HRB remains a core, long term asset. The large scale and productivity of the resource provides significant leverage to any sustained increase in natural gas prices or to LNG development on Canada’s west coast.
Brian Lavergne, President and Chief Executive Officer
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, 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.