CALGARY, ALBERTA–(Marketwired – Aug. 14, 2014) – Storm Resources Ltd. (TSX VENTURE:SRX) –
Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2014 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, 2014, appears below and should be read in conjunction with the related financial statements and MD&A.
|Thousands of Cdn$, except volumetric and per-share amounts||Three
|Revenue from product sales(1)||21,701||11,974||42,508||21,022|
|Funds from operations(2)||11,076||5,077||19,736||8,304|
|Per share – basic ($)||0.10||0.07||0.19||0.12|
|Per share – diluted ($)||0.10||0.07||0.18||0.12|
|Net income (loss)||6,598||661||6,804||400|
|Per share – basic ($)||0.06||0.01||0.06||0.01|
|Per share – diluted ($)||0.06||0.01||0.06||0.01|
|Operations capital expenditures||33,640||16,729||55,983||36,865|
|Acquisitions and dispositions||0||(19)||88,051||(19,518)|
|Debt including working capital deficiency||41,837||22,671||41,837||22,671|
|Weighted average common shares, during period(000s)|
|Common shares (000s), end of period|
|Oil equivalent (6:1)|
|Barrels of oil equivalent (000s)||497||315||953||539|
|Barrels of oil equivalent per day||5,462||3,460||5,266||2,977|
|Average selling price (Cdn$ per Boe)(1)||43.66||38.02||44.60||39.01|
|Thousand cubic feet (000s)||2,321||1,374||4,455||2,254|
|Thousand cubic feet per day||25,506||15,098||24,613||12,453|
|Average selling price (Cdn$ per Mcf)||5.20||3.96||5.40||3.76|
|Barrels per day||762||484||743||373|
|Average selling price (Cdn$ per barrel)||80.57||67.68||82.47||67.47|
|Barrels per day||449||460||420||528|
|Average selling price (Cdn$ per barrel)(1)||99.27||84.96||96.40||83.46|
|(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.|
SECOND QUARTER 2014 HIGHLIGHTS
- Production was 5,462 Boe per day (22% oil plus NGL), an increase of 58% from the same period last year and 8% from the previous quarter. On a per-share basis, the year-over-year increase was 11% using common shares outstanding at the end of each period. The increase was due to growth from the Umbach property where production was 3,979 Boe per day in the second quarter which is 122% higher than a year ago and 12% higher than the previous quarter.
- NGL production was 762 barrels per day, a year-over-year increase of 278 Boe per day, or 57%. Increased NGL production was the result of production growth from the liquids-rich Montney formation at Umbach. The NGL price of $80.57 per barrel was 76% of the average Edmonton Par light oil price.
- Activity was focused on Storm’s 100% working interest lands at Umbach South where seven Montney horizontal wells (7.0 net) were drilled, six horizontal wells (6.0 net) were completed and major equipment was delivered for the new 24 Mmcf per day field compression facility which is expected to start up in late August.
- Only three horizontal wells (2.6 net) have started production in 2014 (all at Umbach) which has more than offset declines, with corporate production increasing from 5,068 Boe per day in the first quarter to approximately 5,600 Boe per day in July.
- At Umbach, Montney horizontal well performance continues to improve with the first 2014 horizontal well with enough production history averaging 4.8 Mmcf per day gross raw gas (870 Boe per day sales) over the first 90 calendar days, a 30% improvement from the average 2013 horizontal well.
- The corporate field operating netback, excluding hedging gains or losses, was $27.78 per Boe, an increase of $7.62 per Boe, or 38% from the previous year. The year-over-year improvement was due to lower operating costs, lower royalties and an increase in the natural gas price to $5.20 per Mcf from $3.96 per Mcf in the previous year. The operating cost was $9.41 per Boe, a decrease of 15% from the prior year. Royalties were reduced by a $1.6 million royalty credit ($3.22 per Boe) received through the British Columbia Infrastructure Royalty Credit Program.
- Funds from operations totaled $11.1 million or $0.10 per basic share, a year-over-year increase of 43% on a per-share basis. The funds from operations netback was $22.27 per Boe, an increase of 38% or $6.15 per Boe from the previous year. A hedging loss reduced the netback by $3.02 per Boe. Controllable cash costs (operating, transportation, cash G&A, interest expense) were $13.73 per Boe, a year-over-year decrease of 16%, or $2.65 per Boe.
- Net income was $6.6 million, or $0.06 per share, a per-share increase of 600% when compared to the previous year.
- Capital investment was $33.6 million with major expenditures being $5.8 million for facilities and pipelines plus $26.4 million for drilling and completions.
- Debt plus working capital deficiency, net of investments, totaled $41.8 million at the end of the quarter which is 0.9 times annualized second quarter cash flow. Storm’s banker, ATB Financial, increased the revolving bank facility to $90.0 million in May 2014 and the facility was syndicated in June by adding two additional banks.
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, the focus has been on exploiting the upper and middle Montney intervals. There are three project areas:
- Umbach South with 88 net sections at a 100% working interest where second quarter production was 3,158 Boe per day;
- Umbach North with 33 net sections of jointly owned lands (59 gross sections with Storm’s working interest being 60% on most of the lands) where second quarter production was 820 Boe per day;
- Nig with 20 net sections at a 100% working interest.
Second quarter production from Umbach was 3,979 net Boe per day (18% NGL), a year-over-year increase of 122% and an increase of 12% from the previous quarter. NGL recovery was 35 barrels per Mmcf sales or 695 barrels per day with approximately 60% being higher priced condensate plus pentanes. The operating netback was $28.81 per Boe with revenue, after deducting transportation costs, of $38.94 per Boe ($5.31 per Mcf sales and $80.10 per barrel of NGL), a royalty rate of 6% and operating costs of $7.83 per Boe. In the second quarter, $1.6 million was received from the British Columbia Infrastructure Royalty Credit Program which reduced the royalty rate from 17% to 6% or by $4.26 per Boe.
Activity in the second quarter included drilling seven Montney horizontal wells (7.0 net), completing six Montney horizontal wells (6.0 net) and finishing site preparation work for the new field compression facility at Umbach South. Including activity to date in the third quarter, 13 Montney horizontal wells (13.0 net) have been drilled in 2014 and the last well in this year’s program was spudded August 7:
- Nine horizontal wells (8.6 net) have been completed including two wells (1.6 net) drilled in 2012 and 2013;
- Three horizontal wells (2.6 net) started producing in 2014 on February 27 (1.0 net), June 17 (1.0 net) and July 28 (0.6 net);
- Six horizontal wells (6.0 net) that have been completed will start producing when the new field compression facility is completed in late August;
- Six standing horizontal wells (6.0 net) will be completed when facility capacity is available.
At Umbach South, a second field compression facility is being constructed with initial capacity of 24 Mmcf per day and start-up is expected in late August 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 $15.0 million. The cost of the expansion is higher than the previous estimate of $9.0 million mainly due to various equipment upgrades. Timing to expand the new facility is being accelerated with expansion to 36 Mmcf per day in March of 2015 and to 48 Mmcf per day in July of 2015 (previously the facility was to be expanded to 48 Mmcf per day in one step in mid-2015).
Storm has now drilled a total of 28 horizontal wells (24.4 net) into the Montney formation. There are 16 producing horizontal wells (12.4 net) and production performance of recent horizontal wells has continued to improve with the 15th horizontal well averaging 4.8 Mmcf per day raw gas or 870 Boe per day sales over the first 90 calendar days (‘IP 90’) since starting production on February 24. This is a 30% improvement from the average 2013 horizontal well. The 16th horizontal well began producing June 17 with performance to date being very similar to the 15th horizontal well (both were drilled adjacent to one another from the same pad). Following is a comparison of calendar day rates for all of the producing Montney horizontal wells.
Start of Production
|IP 90 Cal Day
Mmcf Per Day
|IP 180 Cal Day Gross Raw
Mmcf Per Day
|IP 365 Cal Day
Mmcf Per Day
|Hz’s 1 – 4||60%||Umbach
|2010 – 2011||7 – 11||2.0 Mmcf/d
360 Boe/d sales
270 Boe/d sales
235 Boe/d sales
|Hz’s 5 – 9||60%||Umbach
|2012||14 – 16||2.0 Mmcf/d
360 Boe/d sales
290 Boe/d sales
270 Boe/d sales
|Hz’s 10 – 14||100%||Umbach
|2013||17 – 18||3.6 Mmcf/d
660 Boe/d sales
550 Boe/d sales
420 Boe/d sales
|Hz’s 15 – 16*||100%||Umbach
880 Boe/d sales
|* Note that horizontal 16 started producing June 17 and there is not yet 90 calendar days of production history.|
To date in 2014, the cost to drill a horizontal well has averaged $2.2 million and the completion cost has averaged $2.3 million. Drilling times have averaged approximately 14 days. Tie-in costs have been approximately $0.4 million per horizontal well which doesn’t include the cost of longer gathering pipelines to connect multi-well pads to field compression facilities. The total cost of $4.9 million to drill, complete and tie in a horizontal well results in a payout of 19 months using a 4.4 Bcf type curve and a natural gas price of $3.50 per GJ (see presentation on website for further details). Performance to date of the 2014 horizontal wells is exceeding the 4.4 Bcf type curve by approximately 30% and, should this continue, the payout and rate of return will improve significantly.
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. Second quarter production averaged 347 Boe per day (100% natural gas) at an operating netback of $12.96 per Boe. Production is from one horizontal well with 12 fracture stimulations which currently produces 2.4 Mmcf per day gross raw gas with cumulative production of 4.2 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 41 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 second quarter averaged 1,136 Boe per day (45% oil plus NGL), a year-over-year decline of 15%. The operating netback was $29.61 per Boe. Production was reduced by approximately 90 Boe per day as a result of scheduled turnarounds at gas processing plants. 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 (14,500 GJ per day) of natural gas with an average wellhead floor price of approximately $4.16 per Mcf and an average wellhead ceiling price of $4.38 per Mcf (AECO monthly index $3.38 per GJ for the floor and $3.57 per GJ for the ceiling). In addition, an oil price of WTI Cdn$101.96 per barrel (WTI price in US$ per barrel converted to Cdn$ per barrel) has been fixed on 450 barrels per day.
For 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). An oil price of WTI Cdn$104.05 per barrel (WTI price in US$ per barrel converted to Cdn$ per barrel) has been fixed on 400 barrels per day.
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. A maximum of 50% of current production (most recent monthly or quarterly average), before royalties, will be hedged; production growth is unhedged.
Production in July averaged 5,600 Boe per day based on field estimates, and third quarter production is forecast to be 6,100 to 6,500 Boe per day. Corporate production will increase by approximately 4,100 Boe per day when the new field compression facility is operational at Umbach in late August 2014.
Storm’s 2014 guidance is unchanged from the most recent revision in May 2014 and 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 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 to be drilled||10 gross (10.0 net)||14 gross (14.0 net)|
|Umbach horizontal wells to be completed & tied in||9 gross (9.0 net)||13 gross (12.6 net)|
Adjusted net debt at the end of 2014 is forecast to be $50.0 to $55.0 million which would be approximately 0.9 times annualized funds from operations in the fourth quarter of 2014 (assuming commodity prices in the third and fourth quarters of 2014 are AECO $3.75 per GJ and Edmonton Par Cdn $94.00 per barrel).
At Umbach, drilling and completion operations continued through spring break-up and there are currently six Montney horizontal wells (6.0 net) that have been completed and pipeline connected that will begin producing in September 2014 when the new 24 Mmcf per day field compression facility is operational. An additional six Montney horizontal wells have been drilled and will be completed and tied in as facility capacity becomes available. As a result of improving horizontal well performance, timing to expand the new facility is being accelerated with capacity increasing to 36 Mmcf per day at the end of the first quarter of 2015 and to 48 Mmcf per day early in the third quarter of 2015. With increasing confidence in the repeatability and improved productivity of horizontal wells at Umbach plus a strong balance sheet (year-end debt is forecast to be less than one times cash flow), acceleration of development activities is likely in 2015 if the natural gas price is equal to or greater than $3.50 per GJ at AECO.
Approximately one-third of Storm’s land position at Umbach (47.6 net sections) has been delineated with 24.4 net horizontal wells leaving 165.6 net horizontal locations remaining to drill in the upper Montney interval (assuming four horizontal wells per section). The remaining two-thirds of Storm’s land position has not yet been tested but remains highly prospective given results from horizontal wells drilled by other operators on offsetting acreage.
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
August 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 and six months ended June 30, 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.