CALGARY, ALBERTA–(Marketwired – May 5, 2016) – Crew Energy Inc. (TSX:CR) (“Crew” or the “Company”) is pleased to announce our operating and financial results for the three month period ended March 31, 2016, along with an updated independent Montney Resource Evaluation. Our Financial Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three month period ended March 31, 2016 are available on Crew’s website and filed on SEDAR.
- Increased production to 23,832 boe per day, an increase of 15% over the previous quarter and an increase of 25% over the same period in 2015. The year-over-year production growth is highlighted by a 97% increase in condensate production from the continued strong performance of wells drilled at our Northeast British Columbia (“NE BC”) Montney areas;
- Realized a 15% improvement in natural gas pricing over the previous quarter despite a 26% decline quarter over quarter in AECO benchmark pricing, as a result of Crew’s firm transportation arrangement on the Alliance Pipeline system (“Alliance”) and further supported by our ongoing efforts to secure natural gas sales contracts into diversified markets;
- Reduced operating costs per boe by 30% year over year and 6% quarter over quarter to $6.45 per boe with our liquids-rich Montney Septimus / West Septimus operating costs now at $4.43 per boe;
- Lowered total cash costs per boe by 24% over the same period in 2015 and continued to benefit from capital cost reductions achieving all-in drilling, completion and tie-in costs of approximately $3.5 million per well;
- Generated funds from operations of $11.7 million ($0.08 per diluted share), supported by stronger production volumes, improved natural gas pricing and lower cash costs;
- Invested $18.7 million in capital expenditures in the quarter, 24% less than budgeted, directed at drilling the last four wells of an eight well pad, completing three liquids-rich wells at West Septimus and concluding construction of a pipeline beneath the Pine River which connects our West Septimus and Septimus facilities;
- Increased sand loading by 40% on two Upper Montney wells which tested at an average 12 mmcf per day at a flowing casing pressure of 1,135 psi, a 114% increase from the three wells completed on the same pad in Q4 2015, at a drill, complete and tie-in cost of $3.5 million per well;
- Maintained a strong balance sheet with significant liquidity supported by a 51% increase in our proved developed producing reserves and a newly approved $235 million credit facility, which was 58% undrawn at March 31, 2016; and
- Updated our independent Montney Resource Evaluation which reflected an 8% increase to the Best Estimate Economic Contingent Resource (“ECR”) assessment to 9.0 TCFE and a modest increase to the Total Petroleum Initially In Place (“TPIIP”) estimate to 111.7 TCFE, primarily due to the improved liquid yields on our developed lands. The year-over-year increase in our resource estimate underpins Crew’s ongoing Montney-focused drilling strategy designed to develop this massive resource and realize significant long-term value through reserves additions.
|FINANCIAL & OPERATING HIGHLIGHTS:|
($ thousands, except per share amounts)
March 31, 2016
March 31, 2015
|Petroleum and natural gas sales||36,343||39,940|
|Funds from operations(1)||11,714||20,720|
|Per share||– basic||0.08||0.16|
|Per share||– basic||(0.05||)||(0.12||)|
|Exploration and Development expenditures||17,763||91,092|
|Property acquisitions (net of dispositions)||956||258|
|Net capital expenditures||18,719||91,350|
March 31, 2016
Dec. 31, 2015
|Working capital deficiency(2)||858||10,737|
|Senior Unsecured Notes||146,854||146,679|
|Total Net Debt||245,820||238,396|
|Current Debt Capacity(3)||385,000||400,000|
|Common Shares Outstanding (thousands)||141,073||141,067|
|(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 costs. 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 cash and cash equivalents plus accounts receivable less accounts payable and accrued liabilities.|
|(3)||Current Debt Capacity reflects the newly approved bank facility of $235 million plus $150 million in senior unsecured notes outstanding.|
March 31, 2016
March 31, 2015
|Light crude oil (bbl/d)||303||657|
|Heavy crude oil (bbl/d)||2,799||4,735|
|Natural gas liquids (bbl/d)||3,359||2,060|
|Natural gas (mcf/d)||104,224||69,498|
|Total (boe/d @ 6:1)||23,832||19,035|
|Average prices (1)|
|Light crude oil ($/bbl)||37.34||49.28|
|Heavy crude oil ($/bbl)||20.45||36.63|
|Natural gas liquids ($/bbl)||25.95||27.17|
|Natural gas ($/mcf)||2.34||2.62|
|Oil equivalent ($/boe)||16.76||23.31|
|(1)||Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.|
March 31, 2016
March 31, 2015
|Realized commodity hedging gain||2.21||6.61|
|Operating netback (1)||9.13||16.68|
|Interest on long-term debt||(1.98||)||(2.40||)|
|Funds from operations||5.39||12.10|
|Working interest wells||4.0||6.0|
|Success rate, net wells (%)||100||%||100||%|
|(1)||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 realized a successful first quarter of 2016 and effectively navigated through persistently challenging market conditions. The Company realized production growth of 15% quarter over quarter and 25% year over year, attributable to our successful Montney drilling and development program, as well as the ramp-up of volumes processed through our West Septimus facility that occurred with the commencement of our Alliance pipeline service on December 1, 2015.
The first quarter of 2016 was Crew’s first full reporting period with the Alliance transportation service which facilitates the sale of a portion of our natural gas into markets priced off of the Chicago City Gate hub, realizing a premium to AECO benchmark pricing during the quarter. Crew’s actively-managed portfolio approach to transportation and gas marketing has positioned the Company well to mitigate risk through diversifying sales points and pricing optionality for our gas. We added incremental marketing arrangements in late 2015 which further strengthen our position for 2016 and beyond.
Crew continues to focus on maintaining our strong balance sheet, exiting the quarter with more than $136 million of capacity available on our newly approved $235 million credit facility. We were very pleased with our lending review, which due to Crew’s strong underlying asset base, resulted in a modest 6% reduction to our borrowing base. The significant portion of undrawn capacity provides Crew with substantial financial flexibility that we plan to maintain by aligning 2016 capital investments with our cash flow. As a result of taking this conservative approach, we are confident in Crew’s ability to withstand the ongoing market volatility while advancing our Montney development.
MONTNEY RESOURCE EVALUATION UPDATE
Crew is pleased to report the results of its annual updated independent Montney resource evaluation conducted by Sproule Associates Ltd. (“Sproule”) on our principal NE BC Montney lands including Septimus, West Septimus, Groundbirch / Monias, Attachie and Tower, effective December 31, 2015 (the “Resource Evaluation”). Sproule performed detailed mapping across the evaluated areas which included section by section estimates of reservoir parameters, such as pressure, temperature, porosity, and water saturation, which make up the TPIIP determination. At 111.7 TCFE, Crew’s TPIIP estimate provides the Company with significant opportunities to continue increasing the current ECR estimates plus add reserves with further drilling. Crew’s risked best estimate ECR on natural gas increased 5% to 7.5 Tcf, natural gas liquids (“NGL”) ECR was 32% higher at 225 mmbbls, a result of our highly successful West Septimus drilling program, while our crude oil ECR remained stable at 23 million bbls.
The updated Resource Evaluation demonstrates the significant potential of our lands, offering multiple years of future running room and significant value creation opportunities. Although the play remains in its early stages of development, with new and enhanced drilling and completions techniques, Crew and other area operators continue to further delineate and de-risk the potential of this massive play, demonstrating results from the Montney that continue to improve.
Crew’s strong financial position, operational and market optionality, and ongoing focus on preserving balance sheet strength enable the Company to make decisions that are in the long-term interests of our shareholders. Given the high quality nature of our asset base, we continue to generate compelling long-term returns from our projects despite persistent commodity price weakness. Crew’s historical commitment to maintaining diversity in our long-term funding strategy has afforded the Company financial flexibility provided by our credit facility which remained 58% undrawn at quarter end. Total net debt at the end of the quarter was $245.8 million, including working capital deficiency and $150 million ($146.9 million net of deferred financing costs) of senior unsecured notes that are not due for repayment until the fourth quarter of 2020. Given that the Company has no near-term debt maturities and has maintained substantial liquidity in a challenging market, Crew is well positioned to manage through sustained weak commodity prices.
During the quarter, commodity prices remained weak and declined further. Crude oil prices reached their lowest level since 2003 due to continued oversupply and uncertain global demand. North American natural gas was also weaker, driven lower by the warmest North American winter in over 100 years and a prolonged supply glut, with Western Canadian natural gas prices at AECO and Station 2 trading below $1 per mcf during the quarter. With the onset of Crew’s arrangements on the Alliance pipeline in early December, the Company accessed new markets, including selling approximately 40% of our natural gas at Chicago City Gate prices, which realized a significant premium to AECO benchmark pricing and helped support our funds from operations in the quarter. Although Crew was able to access better markets, significantly increase production and reduce costs, first quarter funds from operations was $11.7 million ($0.08 per diluted share), 43% lower than the first quarter of 2015.
Net capital expenditures during the first quarter totaled $18.7 million, including exploration and development expenditures of $17.8 million, with $0.9 million spent on a minor acquisition. Net expenditures are inclusive of the $10.8 million Government of British Columbia infrastructure credit earned for construction of the Pine River Pipeline which concluded in first quarter and started flowing subsequent to the end of the quarter. At West Septimus, Crew also drilled four (4.0 net) wells and completed three (3.0 net) wells. First quarter 2016 capital expenditures were 24% under our quarterly budget as capital cost savings continued to be realized and we undertook fewer well completions due to the strong performance of the three West Septimus wells which were completed during the quarter.
NE BC MONTNEY – SEPTIMUS / WEST SEPTIMUS OVERVIEW
During the quarter, Crew achieved record average production at Septimus and West Septimus of 18,149 boe per day representing approximately 76% of the Company’s total production volumes. This is a 27% increase over the previous quarter, and a 79% increase over the same period in 2015, highlighted by a 97% increase in condensate production due to strong well performance, particularly at West Septimus. Crew’s operating costs per unit for the Septimus/West Septimus complex declined 23% from the previous quarter to $4.43 per boe on increased throughput and continuing cost reduction initiatives.
Montney Liquids-Rich Natural Gas
|Production & Drilling||First Quarter 2016||Fourth Quarter 2015|
|Average Daily Production (boe/d)||18,149||14,321|
|Wells drilled (gross / net)||4 / 4.0||5 / 5.0|
($ per boe)
|First Quarter 2016||Fourth Quarter 2015|
Crew completed and brought into service the Pine River sales gas pipeline connecting our West Septimus and Septimus facilities. This commissioning facilitated the conversion of an existing six inch gas pipeline into a condensate transportation line between the two facilities. With both of these pipelines now in service, Crew’s immediate realized cost savings are approximately $3 to $4 per bbl of condensate with the elimination of trucking from the West Septimus facility. The Company now has the necessary infrastructure in place to handle sales volumes associated with a future expansion of our West Septimus facility to 120 mmcf per day. With the successful drilling program at West Septimus through the latter part of 2015 and into 2016, Crew has increased production and reduced costs while realizing improved pricing due to marketing arrangements that commenced in December of 2015.
During the first quarter, the Company drilled the last four wells of an eight well pad, and completed three wells at West Septimus. The eight well pad is expected to be completed in the third quarter including Crew’s second Lower Montney well. Crew’s initial Lower Montney well continues to exhibit a positive production trend averaging 3.6 mmcf per day of raw gas production over a 125 day period with average wellhead condensate of 46 bbls per mmcf.
Crew continues to optimize completion practices in West Septimus which has contributed to a significant improvement in well performance over time. Early in the second quarter, Crew completed the last two wells of a five well pad at West Septimus, utilizing 40% higher sand loading on a per meter basis than the previous three wells. The two wells were production tested over a 6 day period and achieved a final raw gas rate of 12 mmcf per day, each at an average flowing casing pressure of 1,135 psi. This rate is an increase of 114% from the initial average raw gas rate of the original three wells completed in Q4 2015. With lower costs for completions, and factoring in our current drilling and tie-in costs, projected all-in well costs at Crew’s West Septimus Montney area are coming in at a very attractive $3.5 million including the higher sand loading. Although the commodity price environment continues to be weak, the project economics at West Septimus and Septimus remain compelling, supported by continued costs reductions, particularly on completions and improved pricing through diversified markets.
Transportation & Marketing
The firm Alliance transportation service Crew contracted beginning in December 2015 has allowed the Company to diversify our gas marketing arrangements leading to stronger realized gas pricing. This contract diversification, combined with Crew’s Montney gas that has a heat content 18% higher than the Alliance standard, contributed to higher first quarter realized natural gas prices, which averaged $0.51 per mcf or 28% higher than the quarterly AECO daily spot average of $1.83 per mcf. Crew currently has approximately 40% of our natural gas volumes priced off of Chicago City Gate prices, 22% priced off of AECO, 30% priced off of ATP (Alliance Trading Pool), 4% priced at Sumas, WA and only 4% priced off of Station 2. Optionality in our marketing and sales points affords Crew significant flexibility to respond to changing market conditions, and focus on projects or markets offering the best returns and pricing.
NE BC MONTNEY – TOWER OVERVIEW
Crew’s Montney Tower area continues to represent significant future development opportunity for the Company as crude oil prices strengthen. With an inventory of four drilled and uncompleted wells at Tower, Crew is preparing to implement improvements in completion techniques which have resulted in increased initial production rates and ultimate recoveries from area wells. With an improvement in commodity prices, Crew may elect to complete these wells in 2016, which would substantially increase our light oil production.
LLOYDMINSTER, AB/SK OVERVIEW
Production at our Lloydminster heavy oil property averaged 2,837 boe per day in the first quarter of 2016, which reflects an additional 235 boe per day of production that was taken offline at the end of the first quarter due to low commodity prices. In aggregate Crew has approximately 700 boe per day of heavy oil shut-in at present. Our heavy oil team continues to strive to improve the economics of our operations through the rationalization of higher cost production and a focus on optimizing operating efficiencies. Total cash costs per unit for our heavy oil operations have decreased 17% in the first quarter of 2016 compared to the same period in 2015 including operating expenses decreasing 7% to average $16.06 per boe during the quarter.
Crew continues to focus on the prudent and measured development of our high-quality asset base and successful execution of our value creation strategy. Over the past few years we have taken steps to ensure the Company is well positioned for a low commodity price environment. These actions have served us well during the past 18 months of price weakness. We have assembled a sizeable and ideally situated land base of 474 net sections in the Montney with resource of 111.7 TCFE of Total Petroleum Initially In Place. This resource is comprised of 7.9 billion bbls of light oil and 64.3 TCF of natural gas that offers significant exposure to both commodities. Access to owned and operated facilities and infrastructure, firm transportation arrangements and a diversified marketing strategy have enabled the Company to optimize Crew’s realized product prices in the current commodity price environment.
In light of continued commodity price uncertainty and volatility, we have taken a very conservative approach to our capital expenditures this year. Following increased activity through 2015, we have built an inventory of 14 drilled but uncompleted wells that we can complete to maintain or increase production volumes. Further, with continued reductions in drilling and completions costs, there may be opportunities to undertake projects that weren’t included in our original 2016 plans within our existing capital budget. Our ability to invest capital and achieve better results continues to improve with cost reductions and evolving drilling and completions practices. We are excited about recent improvements in well results through enhanced completions, as increased sand loading is yielding materially improved results. We intend to continue increasing our proppant per stage with the completion of our next wells at West Septimus. As a result of drilling, Crew has also identified specific areas of our West Septimus acreage which are generating stronger liquids yields, better initial production rates and greater estimated recoveries per well. We will continue to assess the cost-benefit analysis of enhanced completions in our 2016 program.
In addition to the approximately 700 boe per day of shut-in Lloydminster volumes mentioned above, the low commodity prices have impacted a number of other minor non-operated properties which have experienced shut-in volumes. Most notably, Crew had working interest volumes at properties in NE BC associated with an operating company that served notice of receivership and the shut-in of all of its production on March 18, 2016. Combined with other minor properties, Crew has approximately 700 boe per day of shut-in volumes from these NE BC areas that were generating minimal funds from operations and are not expected to return to production in the near future. The Company plans to make up these volumes from Montney wells that have outperformed expectations, which will also contribute to higher netbacks. Our 2016 annual production guidance remains at 23,000 to 25,000 boe per day on a capital budget of $70 million. Capital expenditures will be adjusted with expected funds from operations, with a priority to maintain total net debt between $235 and $250 million at year end 2016.
Longer term, Crew plans to continue developing our massive Montney resource converting prospective resource to Economic Contingent Resource (“ECR”), to reserves and ultimately, to production and cash flow. Our priorities remain on preserving balance sheet strength while investing capital prudently to maintain production while positioning the Company to ramp up activity levels at the appropriate time. Crew has the option to increase our interest in both the Septimus and West Septimus facilities starting in 2017, which would further improve our cost structure. Longer term, we have the option to buy out the remaining partner in the facilities in 2020 which would further reduce operating costs, and advance Crew’s goal of becoming one of the Montney’s lowest cost operators. Crew will continue to actively manage our marketing and transportation arrangements, making adjustments to optimize our sales points in order to achieve the strongest price for our products.
We are pleased to be moving forward in 2016 with financial flexibility, significant liquidity, and a high quality asset base that is constantly improving. We would like to thank our employees and Board of Directors for their commitment to Crew, and our shareholders for their ongoing support through a challenging market environment.
DECEMBER 31, 2015 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” at the end of this release for additional cautionary language, explanations and discussion, and see “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” in this news release. The discussion includes reference to TPIIP, DPIIP and ECR as per the Resource Evaluation as at December 31, 2015, prepared in accordance with the current COGE Handbook guidelines. Unless otherwise indicated in this news release, all references to ECR and prospective volumes are Best Estimate ECR and Best Estimate prospective volumes, respectively.
Amendments to NI 51-101 that came into effect on July 1, 2015 require significant changes to the way resources are disclosed relative to prior years. The most significant changes require:
- The sub-classification of contingent resources into specified project maturity subclasses. Those that apply to Crew’s resources include:
- Development Pending
- Development on Hold
- Development not Viable
Sproule considers the ‘development pending’ and ‘development on hold’ project maturity subclasses to be economic and are therefore included in ECR. The economic status of the ‘development not viable’ project maturity subclass is undetermined and is therefore not included in the ECR reported. The “development not viable” sub-classification represented less than 2% of the sum of all three sub-classifications on a BOE basis.
- Changes to the product types, including the addition of new product types and providing new definitions for some existing product types;
- The disclosure of the risked, best estimate of the contingent resources volumes for each product type;
- The disclosure of the risked NPV of future net revenues for any disclosed development pending contingent resources, calculated using forecast prices and costs for each product type, on a before tax basis using discount rates of zero %, five %, 10 %, 15 % and 20 %;
- The disclosure of the chance of development risk for each project maturity sub-class the issuer discloses; and
- The disclosure of the estimated total cost to achieve commercial production, the estimated date of first commercial production and the recovery technology to be used.
CREW NORTHEAST BRITISH COLUMBIA MONTNEY RESOURCE EVALUATION
The Montney formation in NE BC has been identified as a world-class unconventional resource play with the potential for significant volumes of recoverable resources. The area includes dry gas, liquids-rich gas and light oil development opportunities, with Crew having access to all three hydrocarbon windows. It is one of the largest and lowest cost natural gas resource plays in North America and Crew’s land base comprises 474 net sections, ideally situated in some of the most prospective parts of the play, with good access to infrastructure and multiple egress options.
Sproule was engaged to conduct an updated independent Montney resource evaluation of Crew’s principal lands in the NE BC Montney region including Septimus, West Septimus, Groundbirch/Monias, Attachie and Tower (the “Evaluated Areas”) effective as of December 31, 2015, and based on Sproule’s forecast price deck as at December 31, 2015 (the “Resource Evaluation”). The Resource Evaluation highlights the development potential on the Company’s undeveloped land base providing Crew with significant opportunities to progress conversion of Resource to ECR and ultimately to increased reserve bookings over time. . Further, the diversity of Crew’s NE BC Montney assets with exposure to liquids rich gas, crude oil and dry natural gas allows us to effectively navigate through commodity price cycles.
TPIIP for the natural gas-bearing lands in the Evaluated Areas remains unchanged relative to year end 2014 at 64.3 Tcf. Crew achieved a 15% increase in DPIIP for the Evaluated Areas to 35.2 Tcf, primarily attributed to the 2015 petroleum and natural gas rights exchange with the Province of British Columbia announced in July of 2015.
Natural gas ECR was evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ natural gas ECR totaled 7.1 Tcf and the risked ‘development on hold’ ECR totaled 0.4 Tcf. Total risked natural gas ECR increased by 5% primarily attributable to the lands acquired through the July 2015 petroleum and natural gas rights exchange with the Province of BC.
The ECR of our NGL’s was also evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ NGL ECR totaled 209 MMbbl and risked ‘development on hold’ NGL ECR totaled 16 MMbbl. Total NGL ECR increased by 32% due to improved liquids yields resulting from successful development of Crew’s West Septimus lands.
On the oil-bearing Montney lands, TPIIP increased 3% to 7,895 MMbbl and DPIIP increased 7% to 1,613 MMbbl. Oil ECR was evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ oil ECR totaled 19 MMbbl and risked ‘development on hold’ oil ECR totaled 4 MMbbl.
Risking of the contingent resources included a quantitative assessment of the contingencies applicable to the project including evaluation drilling, corporate commitment and timing of production and development. Risking of the prospective resources included a quantitative assessment of these same factors, as well as a quantitative assessment of the chance of discovery.
The following tables summarize the results of the Resource Evaluation along with comparatives to the updated December 31, 2014 evaluation (reflecting the impact of the July 2015 petroleum and natural gas rights exchange with the Province of BC), using the resource categories set out in the COGE Handbook on a “best estimate” case.
|Dec. 31, 2015||Dec. 31, 2014||%
|Conventional Natural Gas Resource Categories (1)(2)(3)(4)||Tcf||Tcf|
|Total Petroleum Initially In Place (TPIIP)||64.3||64.3||0|
|Discovered Petroleum Initially In Place (DPIIP)||35.2||30.5||15|
|Undiscovered Petroleum Initially In Place (UPIIP)||29.1||33.8||(14||)|
|(1)||TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the 2015 report, which means that essentially all gas bearing rock has been incorporated into the calculations.|
|(2)||All volumes in table are Company gross and raw gas volumes.|
|(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 “gas window”.|
|Dec. 31, 2015||Dec. 31, 2014||%
|Light & Medium Crude Oil Resource Categories (1)(2)(3)(4)(5)||Mmbbls||Mmbbls|
|Total Petroleum Initially In Place (TPIIP)||7,895||7,640||3|
|Discovered Petroleum Initially In Place (DPIIP)||1,613||1,501||7|
|Undiscovered Petroleum Initially In Place (UPIIP)||6,282||6,139||2|
|(1)||TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the 2015 report, which means that essentially all oil bearing rock has been incorporated into the calculations.|
|(2)||All volumes in table are Company gross.|
|(3)||The oil volumes are quoted as Stock Tank Barrels (“STB”).|
|(4)||Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney.|
|(5)||Crew’s acreage was divided into five (5) areas in the “oil window”.|
|2015 Reserves and Risked and Unrisked ECR(1)(2)(3)(6)(7)(8)||Chance of Development||Best Estimate Unrisked||Best Estimate Risked|
|Conventional Natural gas (Bcf)|
|Development Pending ECR||87%||8,160||7,090|
|Development on Hold ECR||85%||515||437|
|NGL (Mmbbls) (4)(5)|
|Development Pending ECR||88%||238||209|
|Development on Hold ECR||84%||19||16|
|Light & Medium Crude Oil (Mmbbls)|
|Development Pending ECR||90%||21||19|
|Development on Hold ECR||80%||5||4|
|(1)||All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable at this time. A portion of the Unrecoverable DPIIP may in the future be determined to be recoverable and reclassified as contingent resources or reserves as additional technical studies are performed, 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.|
|(2)||All volumes in table are company gross and sales volumes, before economic cutoff.|
|(3)||For reserves, the volumes are proved plus probable reserves as at December 31, 2015|
|(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)||All ECR are risked for the chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In quantifying the chance of development, contingencies that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development. The chance of development is multiplied by the unrisked resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution.|
|(8)||The economic status of the ‘development not viable’ project maturity subclass is deemed to be undetermined and is therefore not included in the ECR reported, representing, on a risked basis, 127 bcf of conventional natural gas, 3 mmbbls of NGLs and 2 mmbbls of light and medium crude oil.|
An estimate of risked NPV of future net revenues of the development pending contingent resources subclass only is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of Crew proceeding with the required investment. It includes contingent resources that cannot be classified as reserves until the contingencies are lifted. There is uncertainty that the risked NPV of future net revenue will be realized. The other subclasses of resources are not included in this NPV and therefore this is not reflective of the value of the resource base.
|Before-Tax NPV(1) 2015 Risked ECR Development Pending(2)||($ millions)|
|Discounted at 5%||7,403|
|Discounted at 10%||2,459|
|Discounted at 15%||964|
|Discounted at 20%||402|
|(1)||Based on Sproule’s forecast pricing at December 31, 2015 which is set forth in Crew’s press release dated February 17, 2016.|
|(2)||Risk in the above table is the chance of development. ECR are discovered resources by definition|
The estimated cost to fully develop the ‘development pending’ sub-classification is approximately $10.9 billion (is approximately $3.0 billion discounted at 10%). The forecasted timeline to bring these resources onto production is between two and 17 years utilizing the same technology in horizontal drilling and multi-stage fracturing that Crew has already proven to be effective in the Montney formation in NE BC.
|Prospective Resources (1)(2)(3)(4)(5)(6)(7)||Chance of Commerciality||Best Estimate Unrisked||Best Estimate Risked|
|Conventional Natural Gas (Tcf)||65%||10,225||6,695|
|Light & Medium Crude Oil (MMbbl)||66%||145||95|
|(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 are risked for the chance of discovery and the chance of development. For prospective resources, the chance of development multiplied by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an uncertain value that should be used with caution.|
|(7)||All prospective resources are subclassified as either the ‘prospect’ or ‘lead’ project maturity subclass.|
Resource volumes are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The currently producing assets of Crew and other industry parties in the Montney area of NE B.C. are used as performance analogs for ECR within Crew’s areas of operations. The evaluation of ECR is based on an independent third party evaluation that assumes all of Crew’s ECR will be recovered using horizontal multi-stage hydraulic fracturing and multi-well pad drilling, which are established technologies.
Crew’s ability to recover additional resources is subject to numerous factors, that include minimal well data from the Montney formation in certain intervals; access to capital that would enable us to continue development; low commodity prices which could impact economics; the future performance of wells; regulatory approvals; access to required services; overall industry cost structures; and the continued efficacy of fracture stimulation technologies. In order for ECR to be converted into reserves, Crew’s management and technical teams must continue to assess commercial production rates, devise firm development plans that incorporate timing, infrastructure and capital commitments. With continued development and delineation, some resources currently classified as ECR are expected to be reclassified as Reserves.
A key contingency that prevents the classification of ECR as Reserves is the additional drilling, completions and testing required to confirm viable commercial rates. Sproule assigned ECR beyond those areas which were assigned Reserves but which were within three miles of existing wells, or production tests. Further, a lack of infrastructure in the Evaluated Areas which is required to develop the resources, such as gas gathering, processing and natural gas liquids separation facilities, further impedes the reclassification of ECR to Reserves. In addition to these factors, and the general operational risks facing the oil and gas industry, there are several technical and non-technical contingencies that need to be overcome in order to reclassify ECR to Reserves. These include evaluation drilling, corporate commitment and timing of production and development of the ECR.
There is no certainty that any portion of the prospective resources will be discovered. There is uncertainty that it will be commercially viable to produce any portion of the prospective (if discovered) or contingent resources.
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.|
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.|
|Economic Contingent Resources (“ECR”) are those contingent resources which are currently economically recoverable.|
|Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued.|
|Project Maturity Subclass Development On Hold is defined as a contingent resource that has been assigned a reasonable chance of development, but there are major non‐technical contingencies to be resolved that are usually beyond the control of the operator.|
|Project Maturity Subclass Development Unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined.|
|Project Maturity Subclass Development not Viable is defined as a contingent resource where no further data acquisition or evaluation is currently planned and hence there is a low chance of development.|
|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 and without including any royalty interest, 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, 2015 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 press release contains metrics commonly used in the oil and natural gas industry, such as “operating netback”. Such terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
This news release contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in NE BC which are not, and should not be confused with, oil and gas reserves. See “Definitions of Oil and Gas Resources and Reserves”.
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 oil and 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 DPIIP and 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 2016 forecast average production; the volumes and estimated value of Crew’s resources; 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, well costs and G&A expenditures 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; 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.
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 and the adequacy of cash flow to fund its planned expenditures; 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 and development of 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 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 Energy Inc. is a dynamic, growth-oriented exploration and production company, focused on increasing long-term production, reserves and cash flow per share through the development of our world-class Montney resource. Crew is based in Calgary, Alberta and our 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, 2016 and 2015 will be filed on SEDAR at www.sedar.com and are available on the Company’s website at www.crewenergy.com.
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