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 HIGHLIGHTS
The 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
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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 ($) 0.64 0.22 191 1.04 0.27 285
EBITDA (1) 182,349 22,475 711 309,347 41,662 643
Capital expenditures 172,356 165,707 4 372,626 238,319 56
Total assets 1,826,464 832,132 119 1,826,464 832,132 119
Net debt (1) 176,302 4,425 3,884 176,302 4,425 3,884
Common shares
outstanding, end of
period (000s)
Basic 82,668 76,591 8 82,668 76,591 8
Diluted (2) 98,023 89,775 9 98,023 89,775 9
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Operations
Canadian Business Unit
("CBU") operating
netback ($/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
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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
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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
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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
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Total Company
conventional (boe) 23,856 6,942 244 23,190 6,542 254
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(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.
OPERATIONAL UPDATE
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.
Exploration Success
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.
Whitesands Project
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.
Dawson Project
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.
Conference Call
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.
Forward-Looking Statements
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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