CALGARY, ALBERTA–(Marketwired – May 13, 2013) – Crew Energy Inc. (CR.TO) of Calgary, Alberta is pleased to present its operating and financial results for the three month period ended March 31, 2013 and the results of its 2013 Montney Resource Evaluation.
- An independent Total Petroleum Initially in Place (“TPIIP”) evaluation has confirmed that Crew’s 292 net Montney sections are a world class hydrocarbon accumulation of 76 TCFE made up of 33.7 TCF of natural gas and seven billion barrels of light oil;
- Increase in the Company’s credit facility from $400 million to $430 million;
- Funds from operations were $34.2 million or $0.28 per share in the first quarter of 2013;
- Production in the first quarter averaged 25,961 boe per day and has increased to average approximately 28,000 boe per day in April;
- Drilled 39 wells in the quarter with a 100% success rate;
- Closed the acquisition of 59 net sections of Montney rights in northeast British Columbia for $20 million;
- Drilled a new pool discovery well at Princess, Alberta which averaged 176 bbls of oil per day in April;
- Recently completed two Septimus, BC Montney wells drilled in the first quarter that are exceeding type curves with the first producing 8.2 mmcf per day at 1,250 psi flowing casing pressure after 10 days and the second producing 6.6 mmcf per day flowing at 1,720 psi after 14 days, each with associated liquids of approximately 28 bbls/mmcf (57% condensate);
- Plans to expand the Septimus gas plant capacity from 40 mmcf per day to approximately 65 mmcf per day are on track for a fourth quarter commissioning and the Company has commenced engineering work for a second facility to significantly increase the natural gas processing capacity in the Septimus area to up to 180 mmcf per day.
|Financial||Three months ended||Three months ended|
|($ thousands, except per share amounts)||March 31, 2013||March 31, 2012|
|Petroleum and natural gas sales||91,267||123,075|
|Funds from operations (note 1)||34,188||48,057|
|Per share – basic||0.28||0.40|
|Per share – basic||(0.18||)||(0.05||)|
|Exploration and Development expenditures||65,252||128,743|
|Property acquisitions (net of dispositions)||14,663||–|
|Net capital expenditures||79,915||128,743|
March 31, 2013
December 31, 2012
|Working capital deficiency (note 2)||50,341||48,522|
|Current bank facility||430,000||400,000|
|Common Shares Outstanding (thousands)||121,620||121,620|
|(1)||Funds from operations is calculated as cash provided by operating activities, adding the change in non-cash working capital, decommissioning obligation expenditures and the transportation liability charge. Funds from operations is used to analyze the Company’s operating performance and leverage. Funds from operations does not have a standardized measure prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies.|
|(2)||Working capital deficiency includes only accounts receivable less accounts payable and accrued liabilities.|
|Operations||Three months ended
March 31, 2013
|Three months ended
March 31, 2012
|Daily production (note 1)|
|Princess and other oil (bbl/d)||4,936||6,770|
|Lloydminster oil (bbl/d)||5,441||6,162|
|Natural gas liquids (bbl/d)||2,984||3,105|
|Natural gas (mcf/d)||75,597||86,056|
|Oil equivalent (boe/d @ 6:1)||25,961||30,380|
|Average prices (notes 1 & 2)|
|Princess and other oil ($/bbl)||64.36||81.10|
|Lloydminster oil ($/bbl)||50.61||71.04|
|Natural gas liquids ($/bbl)||54.43||53.05|
|Natural gas ($/mcf)||3.42||2.34|
|Oil equivalent ($/boe)||39.06||44.52|
|Operating netback (note 3)||17.82||20.35|
|Interest on bank debt||1.19||1.06|
|Funds from operations||14.64||17.38|
|Working interest wells||36.8||57.8|
|Success rate, net wells||100||%||97||%|
|(1)||Princess, Alberta oil (20°to 26°API oil) has historically been classified as medium or conventional oil. Effective December 31, 2012 Crew’s reserves attributable to its Princess property have been classified as heavy oil to accord with definitions in the royalty regulations in Alberta. Princess and other oil production and pricing are shown separately from Lloydminster heavy oil volumes for clarity and comparison with historical classification.|
|(2)||Average prices are before deduction of transportation costs and do not include hedging gains and losses.|
|(3)||Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts less royalties, operating costs and transportation costs calculated on a boe basis. Operating netback and funds from operations netback do not have a standardized measure prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies.|
Crew commissioned Sproule Associates Ltd. (“Sproule”) to complete an independent Resource Evaluation of the Company’s Montney lands in Northeast British Columbia which validates the Company’s strategy of acquiring prospective acreage at an attractive valuation. Crew’s 292 Montney sections have a resource assignment of 76 TCFE (12.5 billion boe) of TPIIP with the opportunity to materially add to this total in the coming months. Crew also plans to become more active drilling in the northeast British Columbia Montney formation given the improved economics of this play. The detailed results of the Resource Evaluation are described below.
During the first quarter of 2013, Crew continued to add to its Montney land position with the closing of the second tranche of its multi-option acquisition in the greater Septimus/Groundbirch area. The transaction closed in late February and added an additional 59 net sections of land for $20 million. The Company has one additional option as part of this transaction which, if exercised, is anticipated to close in early July for $36 million adding significant additional resource on 81 net sections of Montney lands. To aid in funding this acquisition the Company has increased its bank facility to $430 million as a result of the Company’s increased December 31, 2012 proved developed producing reserves.
Crew’s first quarter drilling program was active while remaining disciplined with exploration and development spending coming in 12% under its initial budget at $65.2 million. During the quarter the Company drilled a total of 39 (36.8 net) wells including 23 (20.8 net) heavy oil wells in the Lloydminster area, 9 (9.0 net) wells at Princess, 3 (3.0 net) wells in the Deep Basin and 4 (4.0 net) Montney gas wells at Septimus.
First quarter production averaged 25,961 boe per day, a reduction of 4% over the fourth quarter of 2012 due to the sale of 625 boe per day of Kobes, BC production at the end of December and unplanned natural gas production outages at Septimus, BC and Kakwa, AB. The Company’s successful first quarter drilling program has increased production to a field estimate average of approximately 28,000 boe per day in April which approximates current estimated levels.
The Company’s first quarter funds from operations decreased, as compared to the fourth quarter of 2012, to $34.2 million or $0.28 per share. This decline resulted from the 4% quarter over quarter production decrease noted above and lower netbacks caused by lower first quarter oil prices and higher winter operating costs. The Company’s price received (excluding hedging losses) for its production decreased 5% while total cash costs per boe including royalties, operating costs, transportation, general and administrative and interest costs were up 1% due to higher winter operating costs and higher first quarter general and administrative costs associated with annual reporting requirements. The Company’s net loss for the quarter of $22 million was in large part impacted by a $16 million loss from realized and unrealized hedging losses.
Crew’s first quarter revenue from natural gas was positively impacted by pricing that was higher than previously forecasted as extended winter temperatures have impacted the highly populated eastern regions of Canada and the U.S. The above average heating demand has drawn North American natural gas inventories below 2012 and five year average levels which continues to bolster both NYMEX and AECO prices. The price for natural gas delivered at the Canadian AECO hub during the first quarter averaged $3.24 per mcf, which was consistent with prices in the fourth quarter of 2012. The average price received for Crew’s natural gas sales during the first quarter was $3.42 per mcf, which was also consistent with fourth quarter 2012 pricing.
Prices received for the Company’s liquids production including conventional oil, heavy oil and natural gas liquids were down 6% compared to those received for the fourth quarter 2012. West Texas Intermediate (“WTI”) oil, denominated in Canadian dollars, increased 9% during the quarter compared to the fourth quarter of 2012. The prices received for the Company’s conventional and heavy oil sales correlate closely to the price of Western Canadian Select (“WCS”), which traditionally trades at a discount to WTI. During the first quarter the differential between WTI and WCS increased to 34% from 21% in the fourth quarter which resulted in the WCS price decreasing 7% from fourth quarter of 2012 levels. The Company’s overall liquids pricing was positively impacted by a 15% increase in the price received for the Company’s natural gas liquids. This increase was driven by the increase in the underlying price of WTI and an increase in prices received for condensate, ethane and propane.
The Company’s hedging strategy is focused on partially protecting against significant declines in commodity prices that would negatively impact the cash flow needed to fund the Company’s on-going capital program. Crew currently has hedged approximately 47% of its forecasted 2013 natural gas production at a price of approximately $3.22 per mcf. The Company also protects its liquids production from a significant decline in WTI and WCS pricing. The Company has approximately 38% of its forecasted 2013 liquids production protected against a decline in WTI pricing with hedged prices fixed at a floor of approximately $92.00 per barrel. The Company has further hedged the differential between WTI and WCS pricing on 4,200 barrels per day at a differential of $21.08 for the second quarter of 2013, 4,500 barrels per day at $22.29 for the third quarter and 2,500 barrels per day at $22.58 for the fourth quarter. Crew has begun building its hedge position to provide a base level of cash flow for 2014. The Company currently has hedged approximately 14.0 mmcf per day of natural gas for 2014 at a price of approximately $3.90 per mcf and 1,500 barrels per day of WTI oil hedged at an average floor price of approximately $95.70 per barrel for 2014 with additional hedges fixing the differential between WTI and WCS pricing on an average of 1,000 barrels per day for 2013 at a differential of $22.75 per barrel
Septimus/Tower, British Columbia
Crew’s Septimus development program maintained its active pace into the first quarter with the drilling of four (4.0 net) Montney horizontal wells. Production for the quarter averaged 6,170 boe per day as a compressor outage at the Septimus gas plant in February curtailed production in the quarter by approximately 265 boe per day. Three wells were completed and brought on production in the first quarter which led to record March production of 6,790 boe per day. Production into the second quarter has continued this trend with April field estimates at approximately 7,000 boe per day and more recently approaching 7,500 boe per day (40 mmcf per day plus associated liquids). In addition, approximately 1,100 boe per day of existing production is currently backed out due to the high flowing pressure of the new wells and one additional new well has yet to come on production. One of the wells completed in the first quarter confirmed a more liquids rich area of the Montney producing 74 bbls/mmcf of natural gas liquids in the first 25 days when compared to a field average of approximately 28 bbls/mmcf. Crew now has eight wells which have been completed incorporating advanced completion practices. Based on the initial performance of seven of these wells, the Company’s estimated ultimate recoveries (“EURs”) of 4.6 BCF per well is a 44% improvement over the average year end 2012 2P booked EURs. In addition, well costs consisting of drilling, completion and equipping have declined 22% to $4.7 million per well which when combined with the improved per well performance results in a very competitive rate of return for Septimus development at current natural gas prices.
Completion operations were also undertaken on Crew’s first water disposal well at Septimus which came into service early in the second quarter. This well is expected to eliminate approximately $1.1 million in annual trucking and third party disposal charges. Installation of the fourth compressor at the Crew operated Septimus gas plant is on track for start-up in the fourth quarter of 2013 which will increase the capacity of the plant by 50% to approximately 65 mmcf per day with the intent of reaching plant capacity by the end of the first quarter 2014. Crew has undertaken initial scoping work on a second gas processing facility that would increase the total capacity for the Septimus area to up to 180 mmcf per day.
Included in the 76 TCFE of Montney TPIIP, the Resource Evaluation included a light oil TPIIP of seven billion bbls. This represents a significant light oil growth opportunity for Crew as the completion technology in this oil window continues to evolve along with a corresponding improvement in economics. Crew is in the process of planning a development program for the Tower area that will likely be included as part of the Company’s 2014 budget plan.
Deep Basin, Alberta
First quarter production in the Deep Basin averaged 5,540 boe per day. Third party facility outages and natural gas liquids apportionment in January and February negatively impacted production in the quarter by 370 boe per day. Despite the challenges early in the year, March production was on target at 6,020 boe per day and production continues to be on track into the second quarter between 5,700 and 6,000 boe per day. Crew drilled three (3.0 net) horizontal wells for production from the Cardium formation, two of which are expected to be completed and brought on production in the second quarter.
At Princess, Crew drilled nine (9.0 net) wells including five horizontal wells. A successful horizontal well at North Alderson has confirmed a new Pekisko oil pool located east of the Company’s current development. The well came on production in February, 2013 and produced an average of 176 bbls of oil per day in April. A Mannville vertical well drilled in the quarter confirmed the Company’s geological interpretation of this play and is currently producing 30 to 40 bbls of oil per day. Crew has plans to drill two to three horizontal wells to further test and delineate this play. Expansion of the waterflood program continued in the quarter with the initiation of injection into the Pekisko GG pool bringing the total to nine pools currently under waterflood with an additional two to four pools expected to be brought on by the end of the year. Approximately 36% of the developed Pekisko resource is now under waterflood with a plan to have it over 40% by the end of the year. Production for the quarter averaged 5,650 boe per day with third party natural gas facility downtime impacting production by approximately 100 boe per day on average. With six new wells completed and brought on late in the quarter and ongoing waterflood support, current production levels are approximately 6,000 boe per day consistent with expectations.
Crew drilled 23 (20.8 net) wells in the quarter and has been very pleased with the results of this program. Three (3.0 net) horizontal wells at Wildmere were successfully placed into the Lloydminster formation as a follow-up to our fourth quarter of 2012 program. Four (4.0 net) vertical wells at Epping encountered up to three productive horizons in the GP, Sparky and Colony zones. Crew initiated a development program in the Swimming area with six (6.0 net) successful wells in the Sparky sand. Throughout the winter season and particularly in the first quarter, the Lloydminster area was subjected to unusually high snow fall levels resulting in production being curtailed for the quarter to 5,520 boe per day. Crew’s Lloydminster operating staff did a commendable job recovering from these frequent and intense storms and were able to restore production levels in April to approximately 6,000 boe per day based on field estimates. With the return of warmer weather and the official start of spring break-up, Crew expects Lloydminster production will vary between 5,000 to 6,000 boe per day in the coming weeks.
Crew is maintaining its forecasted average annual production of 27,500 to 28,500 boe per day. In April, production averaged approximately 28,000 boe per day based on field estimates, 8% above the first quarter average, positioning the Company to exit 2013 at its 29,000 to 30,000 boe per day guidance. First quarter funds from operations were impacted by WCS differentials widening dramatically to average 34% of WTI as well as facilities related downtime. Second quarter production is forecasted to average 27,500 boe per day and with narrowing differentials, we are expecting to generate significantly more funds from operations in the second quarter. The Company was disciplined in the first quarter, spending $65.2 million or 12% less than initially budgeted exploration and development expenditures and exited the quarter with $339 million of net debt on a $430 million bank facility. Crew also purchased 59 net sections of land in northeast British Columbia for $20 million and disposed of a non-core asset producing 65 boe per day for $5.2 million. Crew’s exploration and development budget of $219 million is currently planned to be funded by funds from operations, bank debt and non-core asset dispositions.
The recently completed Resource Evaluation validates the Company’s strategy of acquiring prospective acreage at an attractive valuation. Crew’s 292 Montney sections have a resource assignment of 76 TCFE (12.5 billion boe) of TPIIP with the opportunity to materially add to this total if we exercise the option to acquire 81 additional sections for $36 million. Crew plans to become more active drilling in the northeast British Columbia Montney play and will drill three exploratory horizontal wells and will continue with development drilling targeting to fill the expanded Septimus gas plant to approximately 65 mmcf per day by the end of the first quarter of 2014.
Crew would like to welcome Mr. Jamie L. Bowman to its management team as Vice-President, Marketing. Mr. Bowman has over 25 years of oil and gas industry experience and will be a valuable addition to the Company’s executive team.
We would like to thank our shareholders for their continued support as well as our employees, consultants and Board of Directors for their hard work and dedication. We look forward to reporting our second quarter results and our progress for long-term value creation initiatives in August, 2013.
NORTHEAST BRITISH COLUMBIA MONTNEY RESOURCE EVALUATION
The following discussion in “Northeast British Columbia Montney Resource Evaluation” is subject to a number of cautionary statements, assumptions and risks as set forth therein. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” for additional cautionary language, explanations and discussion and “Forward Looking Information and Statements” for a statement of principal assumptions and risks that may apply. See also “Definitions of Oil and Gas Resources and Reserves”. The discussion includes reference to TPIIP, DPIIP, UPIIP and Contingent Resources per the Sproule Associates Ltd. (“Sproule”) Resources Evaluation effective as at May 1, 2013, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Unless indicated otherwise in this news release, all references to Contingent Resource volumes are Best Estimate Contingent Resource volumes.
Sproule was engaged to conduct an independent Montney resource evaluation of Crew’s 292 net Montney sections located in Northeast British Columbia (“NEBC”) (the “Evaluated Areas”) effective as of May 1, 2013 (the “Resource Evaluation”). The Resource Evaluation confirms the development and resource potential on the Company’s land base. Crew’s NEBC Montney assets allow us to navigate through commodity price cycles given the range of Crew’s Montney landholdings with exposure to liquids rich gas, crude oil and dry natural gas (gas containing greater than 95% methane). The Resource Evaluation reaffirms Crew’s belief in the considerable potential that exists to further increase our current reserve base, highlighting the world class potential of the NEBC Montney.
The Resource Evaluation has included the recognition of Crew’s lands in the Montney “oil window” where Crew has 99.7 net sections. Previously there was very little production or analysis in the Montney in this area, however, the last two years have provided evidence of the potential on these lands.
Crew started acquiring land on the Montney play in 2007 recognizing there was a significant resource in this Formation. Technology at the time was limited to horizontal drilling and plug and perforation energized frac completions using low volumes of water. At the time, the Company was producing 83% natural gas and 17% oil and liquids. With the coming unconventional natural gas boom, Crew elected to diversify its asset mix to become more liquids weighted. In 2008, Crew bought Gentry Resources Inc. to gain access to the Princess play in southeast Alberta. The Company continued to build its Montney land base, slowly growing production but focused on the newly acquired oil assets as a growth vehicle with high netbacks. Given the challenges with short-term production growth at Princess and as part of Crew’s ongoing evaluation of its portfolio of assets, the Company concluded that the northeast British Columbia Montney play had evolved to where the economics were competing with other plays in our portfolio. Costs were decreasing, results were improving, infrastructure is readily accessible, our understanding of the play was evolving, type curves were improving, well results were becoming more predictable and most importantly Crew had developed a significant acreage position with an associated world class resource. With this as a backdrop, we made a decision to divest of our 23 net section Kobes asset for $108 million and purchase 200 sections for $78 million proximal to our lands and infrastructure between the two Spectra pipelines that provide a west coast delivery option and an east takeaway option through Aux Sable and the Alliance pipeline.
The Resource Evaluation that is presented below and the results we have had at Septimus to date highlight the quality of the lands that Crew has successfully acquired over the past six years. With the improved economics of this play and the visibility of continued development of infrastructure in the Septimus corridor we are committed to continue to pursue opportunities in this region and it is our intent to aggressively exploit the 34 TCF and seven billion barrels of TPIIP on our acreage in order to grow production, reserves and cashflow into the future.
The following tables summarize the results of the Resource Evaluation.
|Natural Gas Resource Categories (1)(2)(3)||Tcf|
|Total Petroleum Initially In Place (TPIIP)||33.7|
|Discovered Petroleum Initially In Place (DPIIP)||12.0|
|Undiscovered Petroleum Initially In Place (UPIIP)||21.7|
|(1)||All volumes in table are company gross and raw gas volumes.|
|(2)||Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney.|
|(3)||Crew’s acreage was divided into six (6) areas in the “gas window”. Crew owns 192 net sections in the gas window at May 1, 2013.|
|Oil Resource Categories (1)(2)(3)(4)||Mmbbls|
|Total Petroleum Initially In Place (TPIIP)||7,031.5|
|Discovered Petroleum Initially In Place (DPIIP)||880.0|
|Undiscovered Petroleum Initially In Place (UPIIP)||6,151.5|
|(1)||All volumes in table are company gross.|
|(2)||The oil volumes are quoted as Stock Tank Barrels (“STB”).|
|(3)||Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney.|
|(4)||Crew’s acreage was divided into five (5) areas in the “oil window”. Crew owns 100 net sections in the oil window at May 1, 2013.|
|Reserves and Contingent Resources (1)(2)||Best Estimate|
|Natural Gas (Tcf)|
|Contingent Resources (6)||2.3|
|Natural Gas Liquids (mmbbls) (4)(5)|
|Contingent Resources (6)||102.1|
|(1)||All DPIIP other than cumulative production, reserves, and Contingent Resources has been categorized as unrecoverable at this time.|
|(2)||All volumes in table are company gross and sales volumes.|
|(3)||For reserves, the volume under the heading Best Estimate are proved plus probable reserves as at December 31, 2012.|
|(4)||The liquid yields are based on average yield over the producing life of the property.|
|(5)||Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.|
|(6)||Project economic Status is currently undetermined. There is no certainty that it will be commercially viable to produce any of the resources.|
|Prospective Resources (1)(2)||Best Estimate|
|Natural gas (Tcf)||3.8|
|Natural gas liquids (mmbbls)||158.7|
|(1)||All UPIIP other than Prospective Resources has been categorized as unrecoverable at this time.|
|(2)||All volumes in table are company gross and sales volumes.|
Based upon the foregoing analysis and Crew’s expertise in the Montney formation in NEBC, it is expected that significant additional reserves will be developed in the future with continued drilling success on currently undeveloped Montney acreage together with further development, completion refinements and improved economic conditions. Additional drilling, completion, and test results are required before Crew can commit to development and these contingent resources can be converted to reserves and a larger component of Prospective Resources is converted to Contingent Resource.
The Prospective Resources have not been risked for chance of discovery. There is no certainty that any portion of the Prospective Resources will be discovered. The Prospective and Contingent Resources have not been risked for chance of development. There is no certainty that it will be commercially viable to produce any portion of the Prospective (if discovered) or Contingent Resources. The Contingent Resource contingencies are identified as economic or non-technical, there are no technical contingencies. Significant positive factors are historic drilling success and production history on the more fully developed Montney acreage, abundant well log and production test data. Potential negative factors include lack of long term production history over the majority of Crew lands, lack of infrastructure, potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the substantial amount of capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost and topographic or surface restrictions.
Definitions of Oil and Gas Resources and Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Cumulative Production is the cumulative quantity of petroleum that has been recovered at a given date.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. “Total resources” is equivalent to “Total Petroleum Initially-In-Place”. Resources are classified in the following categories:
Total Petroleum Initially-In-Place (“TPIIP”) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.
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. Contingences may include such factors 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 in the early evaluation stage.
Undiscovered Petroleum Initially-In-Place (“UPIIP”) given date, to be contained in accumulations yet to be petroleum initially in place is referred to as “prospective is that quantity of petroleum that is estimated, on a discovered. The recoverable portion of undiscovered resources” and the remainder as “unrecoverable.”
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise specified. Throughout this press release, the terms Boe (barrels of oil equivalent), Mmboe (millions of barrels of oil equivalent), and Tcfe (trillion cubic feet of gas equivalent) are used. Such terms when used in isolation, may be misleading. Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and oil and liquids have been converted to natural gas equivalent on the basis of 1 bbl:6 mcfe. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on “company gross reserves” using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2012 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51- 101, and is contained within our Annual Information Form which is available on our SEDAR profile at www.sedar.com.
This news release contains references to estimates of oil and gas classified as TPIIP and DPIIP in the Montney region in northeastern British Columbia which are not, and should not be confused with, oil and gas reserves. See “Definitions of Oil and Gas Resources and Reserves”. TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cutoff.
Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, Crew’s policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of Crew on gas prices, the results of exploration and development activities of Crew and others in the area and possible infrastructure capacity constraints. As with any resource estimates, the evaluation will change over time as new information becomes available.
Crew’s belief that it will establish significant additional reserves over time with the conversion of Prospective Resource into Contingent Resource, Contingent Resource into probable reserves and probable reserves into proved reserves is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading “Forward Looking Information and Statements”.
Forward-Looking Information and Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volume and product mix of Crew’s oil and gas production; production estimates including 2013 forecast average production; the recognition of significant resources under the heading “Northeast British Columbia Montney Resource Evaluation”; future oil and natural gas prices and Crew’s commodity risk management programs; future liquidity and financial capacity; projected debt levels; future results from operations and operating metrics; management’s expectations in regards to waterfloods at Princess; anticipated reductions in operating costs; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition and development activities and related capital expenditures and the timing thereof; the number of wells to be drilled, completed and tied-in and the timing thereof; the number of potential drilling locations; the amount and timing of capital projects; operating costs; the total future capital associated with development of reserves and resources; and methods of funding our capital program.
Forward-looking statements or information are based on a number of material factors, expectations or assumptions of Crew which have been used to develop such statements and information but which may prove to be incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Crew can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; the timely receipt of any required regulatory approvals; the ability of Crew to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Crew has an interest in to operate the field in a safe, efficient and effective manner; the ability of Crew to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Crew to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Crew operates; the ability of Crew to successfully market its oil and natural gas products. There are a number of assumptions associated with the potential of resource volumes assigned to the Evaluated Areas including the quality of the Montney reservoir, future drilling programs, continued performance from existing wells and performance of new wells, the growth of infrastructure, well density per section, and recovery factors and discovery and development necessarily involves known and unknown risks and uncertainties, including those identified in this press release.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; the early stage of development of some areas in the Evaluated Areas; the potential for variation in the quality of the Montney formation; changes in the demand for or supply of Crew’s products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Crew or by third party operators of Crew’s properties, increased debt levels or debt service requirements; inaccurate estimation of Crew’s oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Crew’s public disclosure documents (including, without limitation, those risks identified in this news release and Crew’s Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Crew does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Test Results and Initial Production Rates
A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.
Crew is an oil and gas exploration and production company whose shares are traded on The Toronto Stock Exchange under the trading symbol “CR”.
Financial statements and Management’s Discussion and Analysis for the three month periods ended March 31, 2013 and 2012 will be filed on SEDAR at www.sedar.com and are available on the Company’s website at www.crewenergy.com.
President and C.E.O.
Crew Energy Inc.
Senior Vice President and C.F.O.
Crew Energy Inc.
Senior Vice President and C.O.O.