CALGARY, ALBERTA–(Marketwired – May 7, 2014) – Crew Energy Inc. (“Crew” or the “Company”) (TSX:CR) of Calgary, Alberta is pleased to present its operating and financial results for the three month period ended March 31, 2014.
- Funds from operations in the first quarter increased 52% over the first quarter of 2013 and 8% over the prior quarter to $51.8 million while the funds from operations netback increased by 40%;
- Funds from operations per diluted share increased 50% over the first quarter of 2013 and increased 5% over the previous quarter to $0.42 per share;
- First quarter production was previously announced on April 9, 2014 and averaged 28,021 boe per day, an 8% increase over the same period in 2013 and a 2% decrease from the previous quarter;
- Operating netbacks improved 55% over the first quarter of 2013 to $28.49 per boe, before risk management losses, as a result of improved commodity prices and lower costs;
- Operating costs per boe decreased 6% over the same period in 2013 to $11.35 per boe;
- Crew completed and tied-in two wells at Septimus that are producing into the Company’s gathering system averaging 1,200 boe per day and 1,180 boe per day (16% ngl);
- The Company updated its Montney Resource Evaluation which increased 20% to 109 TCFE of Total Petroleum Initially in Place (“TPIIP”) and the Contingent Resource increased 44% to 5.0 TCFE;
- Crew added strategic production, reserves, land and infrastructure in northeast British Columbia acquiring 1,400 boe per day of production, 8.5 million boe of proved plus probable reserves, 75 net sections of Montney rights and over 130 kilometers of pipelines and 6,000 hp of field compression for $105 million;
- Subsequent to the quarter end, Crew announced the disposition of approximately 7,000 boe per day of production concentrated in the Deep Basin area of Alberta, 254,000 net acres of land and 60.4 million boe of proved plus probable reserves for $222 million in cash plus approximately 400 boe per day of heavy oil production.
($ thousands, except per share amounts)
|Three months ended
|Three months ended
|Petroleum and natural gas sales||130,368||91,267|
|Funds from operations (note 1)||51,810||34,188|
|Exploration and Development expenditures||66,140||65,252|
|Property acquisitions (net of dispositions)||102,532||14,663|
|Net capital expenditures||168,672||79,915|
|Capital Structure ($ thousands)||As at
|Working capital deficiency (note 2)||53,121||40,098|
|Net assets held for sale (note 3)||(231,677||)||–|
|Senior unsecured notes||145,785||145,623|
|Total net debt||268,441||383,409|
|Bank facility after closing of the Alberta Gas Disposition||350,000||420,000|
|Common Shares Outstanding (thousands)||121,679||121,635|
|(1)||Funds from operations is calculated as cash provided by operating activities, adding the change in non-cash working capital, decommissioning obligation expenditures and accretion of deferred financing charges. 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 shown above includes accounts receivable less accounts payable and accrued liabilities.|
|(3)||Net assets held for sale reflects the amounts reclassified from property, plant and equipment and decommissioning obligations for the assets less liabilities associated with the Alberta Gas Disposition as described below.|
|Daily production (note 1)|
|Princess and other oil (bbl/d)||3,298||4,936|
|Lloydminster oil (bbl/d)||6,128||5,441|
|Natural gas liquids (bbl/d)||3,435||2,984|
|Natural gas (mcf/d)||90,959||75,597|
|Oil equivalent (boe/d @ 6:1)||28,021||25,961|
|Average prices (notes 1 & 2)|
|Princess and other oil ($/bbl)||81.81||64.36|
|Lloydminster oil ($/bbl)||69.50||50.61|
|Natural gas liquids ($/bbl)||64.59||54.43|
|Natural gas ($/mcf)||5.84||3.42|
|Oil equivalent ($/boe)||51.69||39.06|
|Realized commodity hedging loss||(3.47||)||(0.55||)|
|Operating netback (note 3)||25.02||17.82|
|Interest on long-term debt||(2.36||)||(1.19||)|
|Funds from operations||20.53||14.64|
|Working interest wells||19.0||36.8|
|Success rate, net wells||100||%||100||%|
|(1)||Princess, Alberta oil (20 degree to 26 degree 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 gains and losses on financial instruments.|
|(3)||Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity based financial instruments 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 continued to execute on its corporate strategy in the first quarter culminating in the closing of two separate transactions that resulted in the Company acquiring certain strategic Montney liquids rich natural gas properties in northeast British Columbia for approximately $105 million (the “Montney Acquisition”). The acquired assets include 75 net sections of land that are either contiguous with existing Crew land or increase Crew’s working interest in joint interest lands. The acquired lands include production of 1,400 boe per day of predominantly natural gas production and 8.5 million boe of proved plus probable reserves. Subsequent to the end of the first quarter, Crew entered into an agreement to sell certain petroleum and natural gas assets including approximately 7,000 boe per day of 75% natural gas production and 60.4 mmboe of proved plus probable reserves focused primarily in the Deep Basin of Alberta (the “Alberta Gas Disposition”). Consideration for the Alberta Gas Disposition will include approximately $222 million in cash, before closing adjustments, plus approximately 400 bbls per day of heavy oil production. This disposition is scheduled to close on or about May 30, 2014, subject to satisfaction of customary industry closing conditions. In conjunction with the announcement of these transactions, the Company increased its 2014 capital budget to $285 million with the incremental $39 million directed exclusively to the Company’s Montney resource development and an acceleration of Crew’s Montney five year growth plan.
As previously announced, Crew’s first quarter production averaged 28,021 boe per day as the severe winter weather along with an unusual number of wells temporarily shut-in due to third party drilling operations in the Lloydminster area impacted volumes by approximately 1,000 boe per day. Toward the end of March, the majority of the Company’s 21 (19.0 net) wells drilled in the quarter came on production resulting in the Company achieving field estimated production rates of 30,400 boe per day in the month of April (inclusive of the 1,400 boe per day acquired at the end of March) consistent with budget expectations. During the first quarter, exploration and development capital expenditures were $66.1 million allocated $35.0 million to the northeast British Columbia Montney, $15.4 million to Princess Mannville development, $13.8 million to Lloydminster and $1.9 million to the Deep Basin and Other Alberta areas.
Crew’s first quarter funds from operations increased 8% over the prior quarter and 52% over the same period in 2013 to $51.8 million or $0.42 per diluted share. The Company’s funds from operations benefited from stronger oil and natural gas pricing experienced during the quarter that were partially offset by a $8.7 million realized loss on the Company’s risk management program. The Company’s $130 million first quarter net loss was impacted by realized and unrealized losses of $27.8 million incurred on the Company’s risk management program and a non-cash impairment charge of $153.5 million on assets related to the Alberta Gas Disposition that have been reclassified as held for sale.
An extended cold winter across North America has reduced natural gas storage levels to 52% below last year’s level and 55% below the five year gas storage average level. Natural gas prices continue to reflect the reduced storage levels as the Company’s realized natural gas price increased 53% over the previous quarter to average $5.84 per mcf for the first quarter of 2014. Oil prices strengthened during the quarter as the discount for Canadian heavy oil, measured as the Western Canadian Select (“WCS”) price differential to West Texas Intermediate (“WTI”), narrowed to average CDN$25.55 per bbl as compared to CDN$33.89 for the previous quarter. A number of positive catalysts provided support for the increase in WCS oil prices including increased crude-by-rail exports and increased rail loading facilities and expansions scheduled for 2014.
The Company’s hedging strategy is focused on protecting against significant declines in commodity prices that would negatively impact the funds from operations needed to fund the Company’s on-going capital program. Strengthening commodity prices have significantly affected Crew’s realized and unrealized losses from its risk management program in the first quarter of 2014. In the first quarter, the Company incurred a realized hedging loss of $8.7 million or $3.47 per boe as compared to $1.3 million or $0.55 per boe in the same period in 2013. During the first quarter of 2014, the Company also incurred unrealized losses on financial instruments of $19.0 million.
The Company had a successful first quarter exploration and development program which saw Crew spend $66.1 million focusing on development of liquids rich natural gas from the Montney formation at Septimus. Quarter-end net debt totaled $268 million which included a reclassification of the Alberta Gas Disposition assets from property, plant and equipment to current assets held for sale. Following the closing of the Alberta Gas Disposition, the Company’s bank facility will be renewed at $350 million.
Septimus/Tower, British Columbia
Crew achieved the fourth consecutive quarter of production growth at Septimus with average production of 10,140 boe per day and a March average of 10,650 boe per day as new wells in the quarter were brought on during the month and with the Septimus gas plant running at 95% to 102% of projected capacity. With sub-$5 per boe operating costs, an attractive and improving royalty structure and improved pricing, the operating netback at Septimus has increased 62% to $29.42 per boe compared to the first quarter of 2013 levels. The Company projects that an annual capital program of $40 to $50 million is required to maintain the Septimus gas plant at capacity and combined with the current pricing environment this would result in $40 to $50 million of annual free cash flow being generated from this first phase of Crew’s Montney development. Future economics have been further enhanced with the announcement of a second tier to the British Columbia Deep Well Credit Program effective April 1, 2014. Based on this addition to the program the majority of Crew’s Montney liquids rich natural gas drilling program will now qualify resulting in an increased NPV10 of approximately $0.8 million per well.
During the quarter, Crew conducted a second production test on the Montney oil exploration well drilled in the fourth quarter of 2013 located 11 kilometers northwest of the Company’s existing Montney oil production. Following an 80 day shut in period, the well was brought back on production for an 11 day test during which it produced an average of 540 barrels of oil per day and 1.1 mmcf per day of natural gas for a total average rate of 723 boe per day. The well is expected to be tied into Crew’s gathering system in the third quarter. The Company is planning to begin drilling its first well of a six well pad at Tower in June.
At Septimus, Crew drilled five (5.0 net) horizontal wells in the quarter with two of the wells on production at 6 to 8 mmcf per day as of the end of the quarter. With the evolution of the Company’s development strategy to pad drilling to capture additional cost efficiencies, Crew is currently drilling the third well on a six well pad which is expected to be completed in the third quarter and will be brought on production following the planned turnaround at the Septimus gas plant in August. A second rig is operating in the Groundbirch area where the Company is drilling the second well on a two well pad. These wells are expected to be completed and tested in the third quarter along with one of the Attachie wells drilled in 2013. Crew also began ordering major equipment for the second Septimus facility anticipated to be on stream mid-2015 with a designed capacity of 60 mmcf per day of raw gas.
At Lloydminster, Crew drilled nine (7.6 net) oil wells and recompleted 16 (15.1 net) wells for $10.8 million. Production for the quarter averaged 6,150 boe per day and the Company is expecting to maintain production in the 6,000 boe per day range throughout the year with total capital expenditures of $35 million.
During the first quarter, production at Princess averaged 3,950 boe per day as the majority of the wells in the Company’s first quarter drilling program came on production early in the second quarter. Current production is approximately 4,500 boe per day based on field estimates with new wells still being optimized. Crew drilled six (6.0 net) wells with total capital expenditures of $14 million including well optimizations. The first quarter drilling program targeted new Mannville opportunities on the Company’s Crown acreage and represents the first phase of delineation of a number of these lands. Crew is projecting to maintain production in the 4,000 to 4,500 boe per day range throughout the year as the Company continues to delineate its Mannville acreage.
Deep Basin, Alberta
Crew’s Deep Basin and other minor Alberta properties produced an average of 7,220 boe per day during the quarter. Crew has announced an agreement to sell these assets pursuant to the Alberta Gas Disposition with an anticipated closing date of May 30, 2014.
With the announced Alberta Gas Disposition, the Company revised forecasted 2014 average production to 25,500 to 26,500 boe per day and forecasts to exit the year at 26,000 to 27,000 boe per day, subject to closing the disposition on May 30, 2014. Exploration and development capital expenditures are now budgeted at $285 million, a $39 million increase over the previous budget. Net debt after closing of the transaction is forecasted to be approximately $280 million.
For the remainder of 2014, Crew plans to:
- Continue to develop and delineate our Montney resource which is now over 109 TCFE of TPIIP and 5.0 TCFE of Contingent Resource;
- Apply new and evolving drilling and completion technologies to improve Expected Ultimate Recoveries and initial production rates;
- Invest in Montney production infrastructure which is estimated at $35 million in 2014 in addition to pre-drilling the majority of the 18 wells planned to initially fill the new 60 mmcf per day facility;
- Evaluate the Montney potential at Crew’s Attachie, Groundbirch and Tower, British Columbia properties;
- Continue to high-grade our asset base and consolidate acreage in the Montney in northeast British Columbia;
- Maintain aggregate production levels at Lloydminster and Princess with free funds from operations to be distributed to our Montney growth initiatives.
Our 2014 capital program has positioned the Company with an expanded resource and drilling inventory, important infrastructure as well as land that is strategic to our future growth plans. Crew’s five year growth plan anticipates the construction of facilities to process 240 mmcf per day of natural gas and 10,000 bbls per day of light oil with targeted exit 2018 Montney production of approximately 45,000 boe per day.
We would like to thank our employees and Board of Directors for their steadfast commitment to Crew’s success and our shareholders for their continued support. We are excited about our prospects and future and look forward to reporting our second quarter operating and financial results in August.
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 April 30, 2014, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Unless indicated otherwise in this news release, all references to Contingent and Prospective Resource volumes are Best Estimate Contingent and Prospective Resource volumes.
Sproule was engaged to conduct an updated independent Montney resource evaluation of Crew’s 452 net Montney sections located in Northeast British Columbia (“NEBC”) (the “Evaluated Areas”) effective as of April 30, 2014 (the “Resource Evaluation”). The Resource Evaluation confirms the development and resource potential on the Company’s land base providing us with significant opportunities to add reserves above the current booked reserves and to increase the current Contingent Resource. The commodity diversity of 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.
TPIIP in the Montney “gas window” increased to 60.6 TCF from 44.6 TCF due to the Montney Acquisition completed in the first quarter. The Resource Evaluation also included recognition of Crew’s lands in the Montney “oil window” where Crew has 138 net sections. On the oil bearing lands, TPIIP increased from 7.8 billion barrels of oil to 8.1 billion barrels of oil. The tight Montney oil potential is in the early stages of development and requires additional data to realize the recoverable potential of these lands. The continued improvement of technology and the early results are very encouraging to the recovery of this vast resource.
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 60.6 TCF and 8.1 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)||60.6|
|Discovered Petroleum Initially In Place (DPIIP)||26.1|
|Undiscovered Petroleum Initially In Place (UPIIP)||34.5|
|(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 276 net sections in the gas window at April 30, 2014.|
|Oil Resource Categories (1)(2)(3)(4)||Mmbbls|
|Total Petroleum Initially In Place (TPIIP)||8,052|
|Discovered Petroleum Initially In Place (DPIIP)||1,363|
|Undiscovered Petroleum Initially In Place (UPIIP)||6,689|
|(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 138 net sections in the oil window at April 30, 2014.|
|Reserves and Contingent Resources (1)(2)(3)(6)(7)||Best
|Natural gas (Tcf)|
|Natural gas liquids (Mmbbls) (4)(5)|
|(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, 2013.|
|(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)||There is no certainty that it will be commercially viable to produce any of the resources.|
|(7)||Contingent Resources includes an 85% development factor.|
|Prospective Resources (1)(2)(5)(6)||Best
|Natural gas (Tcf)||6.3|
|Natural gas liquids (Mmbbls) (3)(4)||254.4|
|(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.|
|(3)||The liquid yields are based on average yield over the producing life of the property.|
|(4)||Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.|
|(5)||There is no certainty that it will be commercially viable to produce any of the resources.|
|(6)||Prospective Resources includes an 85% development factor.|
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. 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. Crew anticipates that a large portion of the Contingent Resources will be economically viable to develop. 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.
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. Contingencies 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”) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as “prospective 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, 2013 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 proved plus probable reserves attributed to the assets acquired by the Company pursuant to the Montney Acquisition. Such reserves reflect Company internally estimated “gross” reserves prepared by a qualified reserves evaluator effective December 31, 2013 in accordance with the definitions and provisions contained in the COGE Handbook. Estimates of proved plus probable reserves contained herein attributed to the assets being disposed of pursuant to the Alberta Gas Disposition reflect “gross” reserves assigned by the Company’s independent reserves evaluator, Sproule Associates Limited, effective December 31, 2013.
This news release contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and Contingent Resources 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: completion of the Alberta Gas Disposition and the timing thereof and anticipated benefits to be derived therefrom; the effect of the Alberta Gas Disposition on continuing operations and plans to expand the 2014 capital program on a post-transaction basis; forecasted net debt after closing of the Alberta Gas Disposition; the volume and product mix of Crew’s oil and gas production; production estimates including 2014 forecast average and exit productions; 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; future results from operations and operating metrics; anticipated reductions in operating costs and potential to improve ultimate recoveries and initial production rates; 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 amount and timing of capital projects including anticipated timing of the new Septimus facility; the total future capital associated with development of reserves and resources; and methods of funding our capital program, including possible non-core asset divestitures and asset swaps. In this news release reference is made to the Company’s five year growth plan including future processing capacity in Northeast British Columbia and a 2018 Montney production target of 45,000 boe per day which are not estimates or forecasts of rates that may actually be achieved. Such information reflects internal projections used by management for the purposes of making capital investment decisions and for internal long range planning and budget preparation. Accordingly, undue reliance should not be placed on same.
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: that all conditions to closing of the Alberta Gas Disposition are satisfied or waived; 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 and the funding thereof, 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 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.
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 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. 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 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.
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 period ended March 31, 2014 and 2013 will be filed on SEDAR at www.sedar.com and are available on the Company’s website at www.crewenergy.com.
Crew Energy Inc.
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.