August 14, 2008
Petrobank Announces Record Second Quarter Results, Entry Into Prolific Northeast British Columbia Resource Plays & Normal Course Issuer Bid
CALGARY, ALBERTA--(Marketwire - Aug. 13, 2008) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce record second quarter 2008 financial and operating results.
FINANCIAL & OPERATING HIGHLIGHTSThe following table provides a summary of Petrobank's financial and operating results for the three and six month periods ended June 30, 2008 and 2007. Consolidated financial statements with Management's Discussion and Analysis ("MD&A") are available on the Company's website at www.petrobank.com and will also be available on the SEDAR website at www.sedar.com.
______________________________Three months ended________ Six months ended __________________________________June 30,______%__________ June 30,______% ______________________________2008____2007 change______ 2008____2007 change -------------------------------------------------------------------- -------- Financial ($000s, except where noted) Oil and natural gas revenue__________________ 241,791__36,859____556____415,395__66,330____526 Funds flow from operations (1)____________177,923__21,580____724____301,411__39,815____657 Per share - basic ($)________2.16____0.28____671______ 3.69____0.54____583 __________ - diluted ($)______1.92____0.26____638______ 3.28____0.51____543 Net income__________________57,636__16,564____248____ 93,173__20,303____359 Per share - basic ($)________0.70____0.22____218______ 1.14____0.27____322 __________ - diluted ($)______0.64____0.22____191______ 1.04____0.27____285 EBITDA (1)________________ 182,349__22,475____711____309,347__41,662____643 Capital expenditures______ 172,356 165,707______4____372,626 238,319____ 56 Total assets____________ 1,826,464 832,132____119__1,826,464 832,132____119 Net debt (1)______________ 176,302__ 4,425__3,884____176,302__ 4,425__3,884 Common shares outstanding, end of period (000s) Basic______________________82,668__76,591______8____ 82,668__76,591______8 Diluted (2)________________98,023__89,775______9____ 98,023__89,775______9 -------------------------------------------------------------------- -------- -------------------------------------------------------------------- -------- Operations Canadian Business Unit ("CBU") operating netback ($/boe except where noted) (1)(3) Oil and NGL revenue __($/bbl)__________________ 117.64__ 67.53____ 74__106.19______65.50____ 62 Natural gas revenue __($/mcf)____________________ 9.83____6.86____ 43____8.73______ 6.97____ 25 Oil and natural gas __revenue__________________ 109.43__ 54.91____ 99__ 97.61______52.87____ 85 Royalties__________________ 11.70____4.35____169____9.43______ 5.06____ 86 Production expenses__________8.88____8.86______-____9.10______ 8.64______5 -------------------------------------------------------------------- -------- Operating netback (4)______ 88.85__ 41.70____113__ 79.08______39.17____102 Latin American Business Unit ("LABU") operating netback ($/bbl) (1) Oil revenue________________115.77__ 63.29____ 83__ 99.96______61.29____ 63 Royalties__________________ 11.11____5.09____118____9.56______ 4.92____ 94 Production expenses________ 10.86____6.74____ 61__ 10.86______ 7.37____ 47 -------------------------------------------------------------------- -------- Operating netback (4)______ 93.80__ 51.46____ 82__ 79.54______49.00____ 62 Average daily production (3) CBU - oil and NGL (bbls)__ 14,205__ 2,132____566__12,778______1,913____568 CBU - natural gas (mcf)____13,871__11,771____ 18__14,550____ 13,093____ 11 -------------------------------------------------------------------- -------- Total CBU (boe)____________16,517__ 4,094____303__15,203______4,095____271 LABU - oil (bbls)__________ 7,339__ 2,848____158__ 7,987______2,447____226 -------------------------------------------------------------------- -------- Total Company conventional (boe)________ 23,856__ 6,942____244__23,190______6,542____254 -------------------------------------------------------------------- -------- -------------------------------------------------------------------- -------- (1) Non-GAAP measure. See "Non-GAAP Measures" section within MD&A. (2) Assumes 8.8 million common shares will be issued upon conversion of ____ the Company's convertible debentures. (3) Six mcf of natural gas is equivalent to one barrel of oil equivalent ____("boe"). Heavy Oil Business Unit bitumen volumes are excluded as ____Whitesands operations are considered to be in the pre-operating stage ____and are capitalized. (4) Excludes hedging activities.
- Average production in the second quarter of 2008 increased to 23,856 barrels of oil equivalent per day ("boepd") compared to 6,942 boepd in the second quarter of 2007, a 244% increase. Canadian Business Unit ("CBU") production increased by 303% to 16,517 boepd and production from the Latin American Business Unit ("LABU") increased by 158% to 7,339 barrels of oil per day ("bopd").
- Production has now increased to over 34,500 boepd mainly due to significant production additions from our Corcel-A4 and C1 wells in Colombia and our ongoing Bakken development drilling program.
- Funds flow from operations increased by 724% to $177.9 million in the second quarter of 2008 or $1.92 per diluted share compared to $21.6 million ($0.26 per diluted share) in the second quarter of 2007.
- Net income increased by 248% to $57.6 million in the second quarter of 2008.
- We achieved record high operating netbacks of $93.80 per bbl in the LABU and $88.85 per boe in the CBU in the second quarter of 2008.
- At Whitesands we drilled, completed and placed on production the world's first THAI(TM) /CAPRI(TM) well which incorporates our revised downhole completion design.
CANADIAN BUSINESS UNIT
- Our aggressive Bakken drilling and facility program is on track to drill 154 net wells in 2008 and add significant new production and reserves.
- We have a discovery well in the Cornwall area of northwest Alberta. The well tested natural gas at a rate of 6.5 mmcf/day and condensate at a rate of 200 bbls/day from the zone. Petrobank plans include several development wells through the remainder of 2008 and construction of a new 25 mmcf/day gas plant with pipeline tie-in for production in early 2009.
- We have signed a definitive agreement to acquire a private company with a strong land position on the Montney formation gas resource play in northeast British Columbia. Petrobank plans to drill and fracture stimulate two horizontal wells on these lands in 2008.
- We have acquired an entry position (25 sections) on resource plays in the Muskwa and Evie shales of the Horn River Basin in northeast British Columbia. The first vertical evaluation well is planned for early 2009.
Petrobank's Canadian Business Unit production averaged 16,517 boepd in the first quarter, a 303% increase from the 4,097 boepd produced in the second quarter of 2007 and a 19% increase from the 13,889 boepd produced in the first quarter of 2008. The quarter's production was dominated by 13,214 boepd of high netback production from the Bakken formation in southeast Saskatchewan. Current production for the Canadian Business Unit is now in excess of 17,500 boepd.
In August 2008, we acquired an additional seven sections of Bakken mineral rights, further increasing our Bakken land base to 221 sections (141,000 net acres) and increasing our inventory of drilling locations by a further 28 locations. In the first six months of the year, 74.8 net Bakken wells have been drilled, although not all wells had been completed and put on production by the end of the second quarter. Our drilling inventory at the end of June was 577 net locations and our plan to drill at least 154 net Bakken locations in 2008 is expected to make Petrobank the most active operator in the play. To achieve our goal, Petrobank is currently operating eight rigs on the Bakken play.
Centralized facilities are necessary to capture the additional value from the associated gas and natural gas liquids production and to maintain low operating costs for our Bakken production. We have started construction of a new satellite facility in the Creelman area which will separate water for local disposal and then move all oil, gas and natural gas liquid production from our Creelman area through pipeline connection to our main Midale facility, ultimately allowing us to capture the associated natural gas and liquids production. Although the water separation portion of this facility is not yet complete, the pipeline is currently transporting the associated gas and liquids to the main Midale facility for processing, and we expect the Creelman facility to be fully operational by the end of August. We also expect to have our Viewfield facility pipeline connected to our Midale plant by the end of September. The planned Freestone facility will also be an oil battery and gas conservation system with a pipeline connection to our main Midale facility for natural gas liquids extraction and gas processing. The Freestone facility is expected to be completed by the end of the October and will likely also gather and process gas for other third parties. These infrastructure enhancements will allow us to maximize our liquids-rich natural gas production and reserves from the play while significantly reducing operating costs and improving our overall project economics.
The Bakken formation produces light oil in close proximity to Canada's main oil pipelines. Operating netbacks are high, particularly when considering the current oil price environment, the attractive Saskatchewan royalty regime, and relatively low operating costs. The operating netback for our operated Bakken oil production during the second quarter of 2008 was $100.93 per barrel, when WTI averaged US$123.80 per barrel.
Late in 2007 we drilled an exploration well in the Cornwall area of northwest Alberta that tested gas at rates of 6.5 mmcf/day plus condensate at rates of 200 bbls/day. This discovery is expected to require several more development wells that we plan to drill through the balance of 2008 as well as initiating the construction of a new 25 mmcf/day gas plant with initial production targeted to begin in the second quarter of 2009.
Entry into Prolific Northeast British Columbia Resource Plays
The Canadian Business Unit seeks to capitalize on our ability to integrate strong geological concepts with the application of technologies that improve oil and gas extraction efficiencies. Complimenting our success in the Bakken, Petrobank is now well positioned on the developing northeast British Columbia gas resource plays in the Montney formation and in the Evie and Muskwa shales of the Horn River Basin.
An arrangement agreement has been signed to acquire 100% of the issued and outstanding shares of a private company ("Private Company") for total consideration of approximately $53 million payable, at the election of the Private Company shareholders, in cash or by the issuance of Petrobank common shares, subject to a maximum of 50% of the total consideration being payable in Petrobank common shares. The Private Company has strong development potential in the Montney formation through the use of horizontal wells and fracture stimulation technologies, similar to those we employ in the Bakken play. The Private Company's independent reserve auditor, GLJ Petroleum Consultants, has assessed the best estimate contingent recoverable resource potential of the lands at 148 Bcf. The Private Company's assets are in the Monias area of northeast British Columbia and include 14 sections of land and current production of approximately 150 mcf/day from two vertical wells, as well as a 5 mmcf/d gas plant. Petrobank plans to further prove the potential of the play by drilling and fracture stimulating two horizontal Montney wells on these lands in 2008. The acquisition of the Private Company will be completed by plan of arrangement, subject to all customary approvals, and is expected to close on or about October 2, 2008.
Petrobank has also acquired a base of 25 sections of land in northeast British Columbia to pursue the developing shale gas play in the Muskwa and Evie shales of the Horn River Basin. We anticipate drilling our first vertical evaluation well in early 2009.
Platform for Growth
The Canadian Business Unit's exploration and development program represents a strong platform for continued growth in both the short and longer-term. Our position and program in the Bakken resource play will continue to positively impact our production and reserves base for years to come. Our success in conventional plays like Cornwall should provide additional near-term impactful growth. Finally, our newly acquired land positions and planned drilling programs for the resource plays in the Montney, Muskwa and Evie formations of northeast British Columbia will provide a platform for further significant longer-term growth in our production and reserve base.
HEAVY OIL BUSINESS UNIT
- We drilled, completed and placed on production the world's first THAI(TM) /CAPRI(TM) well which incorporates our revised downhole completion design.
- The Dawson Project has been initiated, starting with the drilling of our first observation well.
- We are currently acquiring 45 kilometres of 2D seismic over our Sutton Creek Saskatchewan oil sands leases.
- Petrobank's subsidiary Archon has acquired the worldwide use and licensing rights to the CrystaSulf H2S sweetening and sulphur recovery process for all heavy oil production projects.
THAI(TM) operations at Whitesands continue to meet or exceed our technical expectations and provide the basis for implementing our plans to expand Whitesands and develop the Dawson and May River projects. In addition, we continue to mature a number of global joint venture opportunities which should allow us to further expand the potential of the THAI(TM) / CAPRI(TM) processes worldwide.
At Whitesands, we successfully drilled P3-B, the world's first CAPRI(TM) well, late in the second quarter and completion operations commenced on the well in late July. The horizontal wellbore has been preheated and the well has recently been placed on production. The P3-B well incorporates our narrower slot design intended to significantly reduce sand production. This well is also expected to demonstrate the additional upgrading potential of our patented CAPRI(TM) process which places an active catalyst bed within the horizontal production liner. In laboratory tests, CAPRI(TM) has achieved an additional seven degrees API in upgrading effect.
Regulatory and safety requirements imposed during drilling and start-up of the P3-B well, necessitated the reduction of air injection at the other two well pairs (P-1 and P-2) to minimum rates. The regulatory authorities deemed this necessary as a precaution for drilling into the hot combustion zone. The well was successfully drilled with no difficulties encountered. During this same period we completed workovers on the A-2 and A-3 injector wells, to inspect the condition of the wells and upgrade the internal packers. Sand production decreased during this period due to the lower injection rates but continues to cause operational upsets. All three wells are now on production and air injection rates are being increased. The ability to enter both the horizontal production wells and vertical injection wells to perform maintenance workovers and to bring them back on line smoothly is a critical operational success, further reinforcing the robustness of the THAI(TM) process.
The long-term plan for all future wells is to implement a revised down-hole completion design using narrower slots in conjunction with simplified and more robust surface facilities to eliminate the large majority of the produced sand and allow us to produce our new wells at high rates and improved on-stream factors.
The primary wellhead de-sand facilities, which were mechanically complete at the end of 2007, have improved on-stream factors and with these extended on-stream times have more fully demonstrated the unique production characteristic of the initial three wells, whereby they periodically unload large liquid and sand volumes that overload the primary de-sand surface facilities. While these new sand handling facilities have been able to manage production cycles, enabling longer run times, we still have not achieved consistent rateable production as they still require downtime for cleanouts. The present facilities design, while improving operations, will be modified for future facilities. During the first quarter we installed temporary facilities, similar to our revised design for the May River and Dawson projects, which utilizes primary gas separation followed by tank separation of oil, water and sand, rather than using a single pressure vessel. These facilities are being installed on P3-B and, when combined with the narrower liner slot size, should greatly reduce operational challenges caused by any sand production.
Produced oil continues to show a substantial degree of upgrading at the wellhead, ranging between 11 and 17 degrees API and is currently averaging 12 degrees API, compared to the native 8 degree API bitumen in-situ. In addition, we have segregated oil with an API gravity of over 30 degrees from our secondary separation where lighter oil is carried by the overhead gas stream as a vapour, condensing in the secondary separators. We are installing facilities to segregate this higher quality production stream. This lighter oil fraction provides further solid evidence of significant in-situ thermal cracking. Ongoing produced gas analysis during the quarter indicates continuous high temperature combustion with significant levels of free hydrogen production, which will be beneficial for the CAPRI(TM) process. With the upgraded oil and emulsion-free water production, we are able to easily separate the produced oil from the produced water similar to conventional light oil production. These characteristics enable the use of simpler conventional separators to be employed on P3-B and for future wells. Finally, our 4D seismic survey acquired early in the first quarter has provided a clear indication of the area affected by the THAI(TM) process and further confirms the toe-to-heel flow direction.
The regulatory process for the three well expansion project, adjacent to the existing Whitesands site, is awaiting final regulatory approval. The same drilling rig that efficiently drilled P3-B is on site, and all of the facility equipment necessary for the project has been delivered. We expect prompt approval and drilling is expected to commence in the third quarter of 2008.
May River Project
The May River Project is our commercial expansion plan for the THAI(TM) technology on the Whitesands leases. Plant production experience and engineering analysis to date provided the basis for simplifying our central May River processing facility design. The central facilities for the project will be located approximately two kilometres from the current Whitesands site. May River is planned to be built in phases, beginning with initial production capacity of 10,000 to 15,000 bopd of partially upgraded oil, ultimately building capacity to 100,000 bopd. At May River we will also be incorporating power generation from produced gas recovery and elemental sulphur recovery using the CrystaSulf technology. This technology should recover sulphur from the produced H2S more efficiently and with a much lower energy use than competing technologies. We have recently acquired the worldwide use and license rights to the CrystaSulf technology for all heavy oil applications, and we will be incorporating this technology into our planned commercial developments, as well as any new joint venture opportunities that we choose to pursue. We also expect to be able to generate enough power from our produced gas to be more than energy self-sufficient which will further reduce the carbon footprint of the project by effectively offsetting coal fired power generation from the electrical grid and enhancing the future carbon capture feasibility of our produced gas. Produced sulphur is expected to provide additional revenue from the project. Regulatory applications for the first phase are expected to be filed late in the third quarter of 2008. With timely approval, construction could begin in early 2009 with project startup in late 2009/early 2010.
The Dawson project is a joint venture involving our first Alberta- based, third party THAI(TM) license. This project is located in Alberta's Peace River area and is the first THAI(TM) project in a conventional heavy oil reservoir, another important step in taking the technology to a global market. We are planning to implement a two-well project that will also incorporate our simplified facility design. With timely regulatory approval we could commence construction at Dawson later in 2008. We have received approval to drill a stratigraphic well which will initially be used to confirm horizontal well locations for the project application and will then ultimately be used as a thermal observation well.
Sutton Creek, Saskatchewan
In 2007, we acquired a township of land (36 square miles or 23,040 acres) with oil sands potential at Sutton Creek, Saskatchewan. This new land position is located within a new and promising oil sands fairway. A 45 kilometre 2D seismic survey is currently underway over these lands and we expect to conduct an exploration drilling program on the leases this winter.
Technology Development - Archon Technologies Ltd.
In the second quarter of 2008, we achieved a major milestone with the successful manufacturing of the first THAI(TM)/CAPRI(TM) liner. This significant innovation further demonstrates our ability to convert the intellectual property being generated by Archon into practical solutions for the oil industry. This first liner was manufactured in Houston, Texas and we are pleased to report that the three liners for the Whitesands expansion project and future projects will be entirely manufactured in Alberta, Canada.
Archon continues to evaluate and develop complementary technologies to THAI(TM)/CAPRI(TM) and we have recently acquired the worldwide use and licensing rights to the CrystaSulf H2S sweetening and sulphur recovery process for heavy oil production. The ability to efficiently process H2S is a key element in the commercial development of most heavy oil deposits. We have conducted extensive engineering feasibility and economic comparisons with other technologies for produced gas sweetening and concluded that CrystaSulf is lower cost and superior in efficiency, scalability, turndown and overall energy requirements than other processes. This technology is especially compatible with THAI(TM)/CAPRI(TM) and can be used in other heavy oil operations globally.
CrystaSulf was developed by CrystaTech Inc., a privately-held corporation headquartered in Austin, Texas, whose largest shareholder is the Gas Technology Institute. CrystaTech Inc. develops and deploys advanced process technology for the energy industry worldwide specializing in technologies with exceptional environmental, operating and financial impact. The CrystaSulf process efficiently removes H2S from gas streams by a liquid-phase Claus reaction.
We also continue to evaluate a number of heavy oil reservoirs globally with potential third party licensing partners, and have conducted laboratory reactor tests of various oil samples to determine their combustion characteristics and the degree of potential upgrading. These evaluations have demonstrated the feasibility of THAI(TM) in a wide range of heavy oil reservoirs domestically and internationally. In conjunction with these evaluations we are also negotiating several joint venture opportunities.
As part of our ongoing research and development process, we are working with international research institutions. We have entered into a research program with the University of Bath and the University of Birmingham to evaluate the optimization of CAPRI(TM) for the in-situ upgrading of heavy oil. This project has also received $1.5 million of funding from the Engineering and Physical Sciences Research Council (EPRSC) in the United Kingdom.
Archon continues to evaluate a number of innovative engineering, environmental, and other value added technology options to improve operational efficiency and flexibility, and to reduce the overall environmental impact of commercial developments. Other technologies being assessed include enriched oxygen injection, utilizing produced gas to cogenerate enough power to be energy self sufficient, produced water quality enhancement, and partial surface upgrading.
LATIN AMERICAN BUSINESS UNIT - Petrominerales Ltd. (TSX:PMG) (owned 76.2%)
A full operational update of our 76.2% owned Latin American Business Unit, Petrominerales Ltd., was published on August 12, 2008 and can be found at www.petrominerales.com and www.sedar.com. Highlights of the second quarter include:
- Crude oil production increased by 158%, averaging 7,339 bopd in the second quarter of 2008.
- Production increased to 8,717 bopd in the month of June 2008 and has recently increased to over 17,000 bopd due to significant production additions from our Corcel-A4 and C1 wells.
- Operating netbacks increased by 98% to US$92.99 per barrel in the second quarter of 2008.
- Petrominerales funds flow from operations increased by 511% to US$53.2 million.
- Petrominerales net income increased by 153% to US$30.7 million.
NORMAL COURSE ISSUER BID
The boards of directors of Petrobank and Petrominerales have both approved normal course issuer bids (the "NCIBs"), subject to the approval of the Toronto Stock Exchange. Pursuant to the NCIBs, Petrobank plans to repurchase up to 6,444,777 of its common shares, representing approximately 10% of its outstanding public float. Petrominerales plans to repurchase up to 5,032,717 of its common shares, representing approximately 5% of its issued and outstanding shares.
Strong balance sheets and significant increases in cash flow stemming from marked production increases and high commodity prices allow us to try and capitalize on the current valuations of Petrobank and Petrominerales in the market which in our opinion do not fairly represent the value and potential of our unique asset bases.
Petrobank will be holding a conference call on Thursday, August 14, 2008 at 11:00am (Mountain Time) to discuss Petrobank's second quarter financial and operating results. The investor conference call details are as follows:
Dial-in Number:________ 416-641-6105 or 1-866-862-3927 Taped Re-play:__________416-695-5800 or 1-800-408-3053 Reference Number:______ 3268029 Available until:________August 21, 2008
Petrobank Energy and Resources Ltd.
Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada and Colombia. The Company operates high-impact projects through three business units and a technology subsidiary. The Canadian Business Unit is developing a solid production platform from low risk gas opportunities in central Alberta and an extensive inventory of Bakken light oil locations in southeast Saskatchewan, complemented by new exploration projects and a large undeveloped land base. The Latin American Business Unit, operated by Petrobank's 76.2% owned TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), is a Latin American-based exploration and production company producing oil from three blocks in Colombia and has contracts on 15 exploration blocks covering a total of 1.6 million acres in the Llanos and Putumayo Basins. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns 75 net sections of oil sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and operates the Whitesands project which is field-demonstrating Petrobank's patented THAI(TM) heavy oil recovery process. THAITM is an evolutionary in-situ combustion technology for the recovery of bitumen and heavy oil that integrates existing proven technologies and provides the opportunity to create a step change in the development of heavy oil resources globally. THAI(TM) and CAPRI(TM) are registered trademarks of Archon Technologies Ltd., a wholly- owned subsidiary of Petrobank.
Certain information provided in this press release constitutes forward-looking statements. The words "anticipate", "expect", "project", "estimate", "forecast" and similar expressions are intended to identify such forward-looking statements. Specifically, this press release contains forward-looking statements relating to results of operations and the timing of certain projects. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. You can find a discussion of those risks and uncertainties in our Canadian securities filings. Such factors include, but are not limited to: general economic, market and business conditions; fluctuations in oil prices; the results of exploration and development drilling, recompletions and related activities; timing and rig availability, outcome of exploration contract negotiations; fluctuation in foreign currency exchange rates; the uncertainty of reserve estimates; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of the Company. There is no representation by Petrobank that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Except as may be required by applicable securities laws, Petrobank assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.
Resources and Contingent Resources
In this press release, Petrobank has disclosed estimated volumes of "contingent resources" or "resource" estimates that have been prepared by GLJ in respect of the target company for the lands the target company owns. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves" as described below. The following are excerpts from the definitions of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in "National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities": Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. Resources and contingent resources do not constitute, and should not be confused with, reserves.
Barrels of Oil Equivalent ("boe")
Disclosure provided herein in respect of boe units may be misleading, particularly if used in isolation. A boe conversion relationship of 6 mcf to 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.
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