CALGARY, ALBERTA–(Marketwired – Aug. 14, 2013) – Storm Resources Ltd. (TSX VENTURE:SRX) –
Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2013 and for the three and six 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 and six months ended June 30, 2013, appears below and should be read in conjunction with the related financial statements and MD&A.
Thousands of Cdn$, except volumetric
|Revenue from product sales(1)||11,974||9,443||21,022||12,833|
|Funds from operations(2)||5,077||3,669||8,304||3,606|
|Per share – basic ($)||0.07||0.06||0.12||0.07|
|Per share – diluted ($)||0.07||0.06||0.12||0.07|
|Net income (loss)||661||947||400||(668)|
|Per share – basic ($)||0.01||0.03||0.01||(0.01)|
|Per share – diluted ($)||0.01||0.03||0.01||(0.01)|
|Field capital expenditures||16,729||7,223||36,865||10,439|
|Proceeds on disposition of oil and gas properties||(19)||–||(19,518)||(1,009)|
|Debt including working capital deficiency, net of investments||22,671||53,667||22,671||53,667|
|Weighted average common shares outstanding (000s)|
|Common shares outstanding (000s)|
|Oil equivalent (6:1)|
|Barrels of oil equivalent (000s)||315||235||539||347|
|Barrels of oil equivalent per day||3,460||2,584||2,977||1,906|
|Average selling price (Cdn$ per Boe)(1)||38.02||40.16||39.01||36.99|
|Thousand cubic feet (000s)||1,374||809||2,254||1,324|
|Thousand cubic feet per day||15,098||8,895||12,453||7,277|
|Average selling price (Cdn$ per Mcf)||3.96||2.04||3.76||2.12|
|Barrels per day||484||186||373||132|
|Average selling price (Cdn$ per barrel)||67.68||71.22||67.47||74.38|
|Barrels per day||460||915||528||562|
|Average selling price (Cdn$ per barrel)(1)||84.96||78.97||83.46||80.54|
|(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 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 18 of the MD&A.|
SECOND QUARTER 2013 HIGHLIGHTS
- Production increased 39% from the previous quarter to average 3,460 Boe per day (27% oil plus NGL) which leaves Storm on track to meet guidance for fourth quarter production of 4,500 to 5,000 Boe per day. Compared to the same period a year ago, the increase is 34%, or 14% on a per-share basis. Increased production was the result of growth at Umbach where production averaged 1,792 Boe per day in the second quarter, an increase of 1,268 Boe per day from the first quarter and 1,479 Boe per day from a year ago.
- NGL production averaged 484 barrels per day, an increase of 85% from the first quarter and 160% from the year earlier period. The increase is the result of production growth from the Montney formation at Umbach. The NGL price was $67.68 per barrel which was 73% of the average Edmonton Par price for the quarter.
- Funds from operations was $5.1 million, or $0.07 per basic share, an increase of 57% from the first quarter and 38% from the year ago period. The increase in funds from operations is largely the result of higher natural gas prices and from increased production levels.
- The field operating netback was $20.12 per Boe excluding hedging gains, with operating costs of $11.08 per Boe. Operating costs decreased by $2.46 per Boe from the first quarter primarily due to production growth at Umbach where operating costs were $8.79 per Boe in the second quarter.
- Capital investment totaled $16.7 million with major expenditures including $4.5 million to acquire a field compressor at Umbach with capacity of 19 Mmcf per day and $7.8 million to acquire undeveloped land also at Umbach. Through the first half of 2013, $15.0 million has been invested to acquire 27.2 net sections with Montney rights at Umbach.
- Field activity in the quarter was focused on the Montney formation at Umbach where one horizontal well (1.0 net) was drilled and one horizontal well (0.6 net) was completed in June with both horizontal wells being pipeline connected in August.
- Net income was $0.7 million or $0.01 per basic share, a decrease from net income of $0.03 per basic share a year earlier. The decrease was primarily due to a year-over-year decrease in the unrealized gain on hedges in place at quarter end and from the issuance of additional common shares.
- Debt plus working capital deficiency, net of investments, ended the quarter at $22.7 million which is one times annualized second quarter cash flow. Storm’s bank credit line is $52.0 million.
- Equity financings were closed on May 1st whereby Storm issued 15.6 million shares priced at $1.88 per share for net proceeds of $27.7 million. The related financings comprised 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.
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 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 is prospective for liquids-rich natural gas from the Montney formation and totals 112 net sections (140 gross sections), or 79,000 net acres. There are two project areas, one area consisting of 79 net sections of land at a 100% working interest, while the other area consists of 33 net sections of jointly owned lands (61 gross sections with an average Storm working interest of 55%). Year-to-date, Storm has invested $15.2 million to acquire 27.2 net sections (29 gross).
Second quarter production grew to 1,792 net Boe per day (22% liquids) as a result of reduced downtime plus the start of production from 1.6 net Montney horizontal wells in April, including Storm’s first 100% working interest horizontal well. NGL recovery averaged 48 barrels per Mmcf sales for the quarter which comprises approximately 54% condensate/pentanes, 24% butane and 22% propane. The operating netback in the second quarter was $19.50 per Boe with revenue of $33.22 per Boe, a royalty rate of 15%, and operating costs were $8.79 per Boe. Operating costs decreased $2.75 per Boe from the first quarter because of reduced downtime and the start of production through a recently acquired field compression facility where operating costs are lower because fees are no longer paid for third party field compression. The field compression facility has capacity of 19 Mmcf per day and was purchased for $4.5 million on April 1st.
On the joint lands, nine horizontal wells (5.4 net) have been drilled since 2010 in the Montney formation with eight horizontals (4.8 net) having been completed and tied in through third party field compression to the Stoddart Gas Plant where NGL recovery was 60 barrels per Mmcf sales in the second quarter and processing shrinkage was 20%. NGL recovery declined from 72 barrels per Mmcf sales in the first quarter due to a scheduled turnaround at the Stoddart Gas Plant which resulted in production being re-directed to the McMahon Gas Plant for three weeks in May. The remaining standing horizontal well (0.6 net) will be completed and tied in during the fourth quarter of 2013 as field compression capacity becomes available with normal production declines.
On the 100% working interest lands, the first horizontal well began producing April 2nd into the Storm-owned field compression facility. Production from this facility is directed to the McMahon Gas Plant for processing where NGL recovery averaged 34 barrels per Mmcf sales in the second quarter with processing shrinkage of 12%. Although NGL recovery is lower than on the joint lands, the field netback is forecast to be $2.00 per Boe higher as a result of lower operating costs (third party fees for field compression are eliminated). Five additional horizontal wells (5.0 net) will be drilled on the 100% working interest lands in 2013 and will be tied in to this facility with the first coming on production in August, the next two in September, one in the fourth quarter, and the last one in the first quarter of 2014.
Production rates per well over the first 90 days have averaged 3.2 Mmcf per day gross raw gas on an operating day basis (approximately 590 Boe per day sales) for the most recent four horizontal wells (2.8 net) that started production since October 2012. This is an increase of approximately 35% when compared to earlier horizontal wells. Operating day rates were used for comparison as downtime due to capacity constraints at a third party facility in the fourth quarter of 2012 and first quarter of 2013 reduced production from horizontal wells on the joint lands. Several changes were made to recent horizontal wells including drilling the wellbore lower in the Montney formation and increasing the number of fracture stimulation stages in the completion. Initial declines are very similar for all of the horizontal wells which implies that first year average rates for the last four horizontal wells will improve to approximately 2.0 Mmcf per day gross raw gas (370 Boe per day sales) per well, a 35% increase from 1.5 Mmcf per day gross raw gas for earlier horizontal wells. Additional fracture stimulation stages will be added on future horizontal wells to try and further improve production rates and ultimate reserves. More information on production rates and declines is provided in the presentation on Storm’s website stormresourcesltd.com.
Cost reductions are being realized as a result of the transition to development in 2013 (activity in 2012 was focused on resource delineation). Most of the horizontal wells to be drilled in 2013 will be on common pads or will be drilled from existing pads which reduces the cost of rig moves and lease construction. Since mid-June, three horizontal wells (3.0 net) have been drilled at an average cost of $2.0 million with drilling times averaging 14 days and two horizontal wells (1.6 net) have been completed at an average cost of $2.3 million. Tie-in costs are expected to average $0.6 million per horizontal well (not including cost of longer gathering pipelines to connect multi-well pads to field compression facilities). Total cost to drill, complete, equip and tie in a horizontal well is now estimated to be $4.9 million.
Total investment in infrastructure at Umbach in 2013 is expected to be $11.0 million which includes the acquisition on April 1st of field compression for $4.5 million and construction of large diameter field gathering pipelines. This strategic investment provides Storm with operational control and will result in reduced operating costs plus significant low cost growth in production into 2014.
Horn River Basin, North East British Columbia
Storm 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. Production in the second quarter averaged 332 Boe per day at an operating netback of $11.63 per Boe and was reduced by approximately 40 Boe per day due to the scheduled 14-day turnaround at the Fort Nelson Gas Plant. Production is from one 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 3.4 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. The area that was evaluated includes 30 sections at a 100% working interest and represents 22% of Storm’s total land holdings in the HRB. Commerciality has been proven across the core producing area with a horizontal well that has been producing for 30 months plus two vertical wells that were completed and tested with final test rates of 900 Mcf per day over the final 24 hours of each flow test.
Grande Prairie Area, North West Alberta and North East British Columbia
Production in the second quarter averaged 1,336 Boe per day (41% oil plus NGL) at an operating netback of $23.10 per Boe. Based on field estimates, July production averaged approximately 1,375 Boe per day (42% oil plus NGL). No drilling activity is planned in this area in 2013. This area has a relatively shallow decline which allows Storm to re-invest the cash flow to grow production at Umbach.
Production in the third quarter of 2013 is expected to be 3,600 to 4,000 Boe per day depending on the timing of completing and pipeline connecting new horizontal wells at Umbach. Based on field estimates, July production averaged approximately 3,500 Boe per day. Production growth in 2013 will come from Umbach where two new horizontal wells (1.6 net) are expected to begin producing in August and an additional two horizontal wells (2.0 net) are currently being completed with production expected in early September. Fourth quarter production is forecast to increase to 4,500 to 5,000 Boe per day with the completion and tie-in of one more horizontal well (1.0 net) which is currently being drilled. Guidance for 2013 has not been changed since the update on May 15, 2013 and is provided below:
|Year-end adjusted debt plus working capital deficiency (1)||$36.0 – $40.0 million|
|Average operating costs||$10.00 – $11.00 per Boe|
|Average royalty rate (on production revenue before hedging)||13% – 14%|
|Operations capital, excluding dispositions||$62.0 million|
|Asset dispositions||$19.5 million|
|Asset acquisitions||$4.5 million|
|Cash G&A||$3.7 million|
|Exit or fourth quarter average production||4,500 – 5,000 Boe/d|
|(25% oil + NGL)|
|(1) Includes value of publicly listed securities.|
Major expenditures in the 2013 capital investment program include:
- $33.0 million at Umbach to drill 6.6 net horizontal wells (7 gross) with 6.2 net horizontal wells (7 gross) being completed and tied in;
- $16.0 million to acquire undeveloped land prospective for the Montney formation at Umbach;
- $7.0 million to expand infrastructure at Umbach which is primarily constructing gathering pipelines;
- $4.5 million to acquire a field compressor at Umbach on April 1st; and
- $19.5 million net proceeds from asset dispositions which closed in the first quarter.
Storm’s 2013 budget assumes an average natural gas price at AECO of $2.95 per GJ and an Edmonton Par oil price of Cdn $95.00 per barrel. Assumed commodity prices reflect year-to-date prices plus forward strip pricing as of August 5, 2013. Adjusted net debt is forecast to be $36.0 million to $40.0 million at the end of 2013 (including public company investments) which would be approximately 1.5 times annualized fourth quarter funds from operations.
A large proportion of capital investment in 2013 (25% of operations capital) is being directed towards acquiring undeveloped land in the Montney formation at Umbach. To date, 27.2 net sections (29 gross sections) have been acquired for $15.2 million with most of this land being further west in an area with vertical well control where log response is similar to vertical wells that offset Storm’s horizontal wells producing from the upper Montney. In addition, there is a lower Montney interval that appears to be productive based on results from other operators in the area. This is a large investment in undeveloped land that is based on what Storm has learned in the area since drilling and completing the first horizontal well in 2010.
Since 2010, Storm has accumulated 112 net sections in the Montney at Umbach and approximately 25% has been delineated to date with vertical and horizontal wells while reserves have been assigned on just 5% of this land position in the upper Montney only. Using flat pricing of $3.00 per GJ for natural gas and Cdn $92.00 per barrel for Edmonton Par (WTI US $95.00/bbl), Storm management estimates that rates of return for horizontal wells are 25% on an unrisked basis. This assumes a field netback of $19.00 per Boe, a first year average rate of 2.0 Mmcf per day gross raw gas, ultimate reserves of 4.0 Bcf gross raw gas per horizontal well and $4.9 million to drill, complete and tie in a horizontal well. The cost to add production is approximately $13,000 per Boe per day using the first year average sales rate of 370 Boe per day. Based on results to date, it is likely that production rates and ultimate reserves could be further improved with additional enhancements to completion methods. In addition, operating costs will continue to decline as production through Storm’s owned infrastructure increases. With ownership and control of field infrastructure and improving production rates from recent Montney horizontal wells, growth from Storm’s 100% working interest lands at Umbach is expected to result in corporate production volumes increasing to 5,500 to 6,000 Boe per day over the next 12 to 18 months.
Storm’s land position in the HRB continues to be a core, long term asset which provides significant leverage to increased natural gas prices or to LNG development on Canada’s west coast.
Brian Lavergne, President and Chief Executive Officer
August 14, 2013
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 and six months ended June 30, 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.