Petrobank Energy and Resources Ltd. (TSX:PBG) is pleased to announce 2011 first
quarter financial and operating results highlighted by funds flow from
operations of $1.57 per diluted share.
Petrobank's results include the financial and operating results of PetroBakken
Energy Ltd. (TSX:PBN), 59% owned by Petrobank at March 31, 2011. PetroBakken
announced first quarter financial and operating results on May 10, 2011.
All financial figures are unaudited and in Canadian dollars ($) unless noted
otherwise. All financial statements have been prepared in accordance with
International Financial Reporting Standards ("IFRS") including comparative
figures pertaining to Petrobank's 2010 results. A reconciliation of comparative
figures is provided in the notes to the Unaudited Interim Consolidated Financial
Statements for the period ended March 31, 2011.
This news release includes forward-looking statements and information within the
meaning of applicable securities laws. Readers are advised to review
"Forward-Looking Information and Statements" at the conclusion of this news
release. Readers are also referred to "Information Regarding Contingent
Resources" and "Non-GAAP Measures" at the end of this news release for
information regarding the presentation of the financial and contingent resources
information in this news release. A full copy of our 2011 First Quarter
Financial Statements and MD&A have been filed on our website at
www.petrobank.com and under our profile on SEDAR at www.sedar.com.
HIGHLIGHTS
In this report, quarterly comparisons are first quarter 2011 compared to first
quarter 2010 unless otherwise noted. The results of Petrominerales Ltd.
("Petrominerales") (TSX:PMG), previously majority owned by Petrobank, have been
separately disclosed as discontinued operations up until December 31, 2010, the
date this business unit was spun off to Petrobank shareholders.
Q1 2011 Financial Highlights
-- Funds flow from continuing operations increased eight percent to $168.4
million, or $1.58 per basic share, compared to the fourth quarter of
2011 primarily as a result of PetroBakken's higher operating netbacks.
-- PetroBakken's operating netback (excluding hedging activity) of $52.42
per barrel of oil equivalent ("boe") increased nine percent, compared to
the fourth quarter of 2010, primarily as a result of higher pricing, and
decreased slightly by one percent from the prior year period, primarily
due to increased production expenses.
-- Net income attributable to Petrobank shareholders from continuing
operations increased $20.3 million to $20.6 million in the first quarter
of 2011 compared to the first quarter of 2010. The increase is due
mainly to a non-cash gain arising from the revaluation of PetroBakken's
convertible debentures derivative financial liability.
-- Capital expenditures were $361.7 million in the first quarter, up 73
percent from a year ago and 20 percent from the fourth quarter of 2010.
The increases were primarily driven by PetroBakken's aggressive drilling
program and extensive facility investments, and the Heavy Oil Business
Unit's 10 well-pair expansion project at Kerrobert.
-- On January 4, 2011, Petrobank entered into a new three year $200 million
credit agreement with a syndicate of lenders.
Heavy Oil Business Unit 2011 Operations Highlights
-- Start up of Kerrobert expansion project is on schedule with the first of
the new production wells being tied into the central processing
facility.
-- A five year collaboration agreement has been signed with Pemex
Exploracion y Produccion, a subsidiary entity of the Mexican state oil
company Petroleos Mexicanos ("Pemex"), as the first step to licensing
our THAI(R) technology in Mexico.
-- We have acquired and agreed to acquire a further seven sections of land
in Saskatchewan on the Kerrobert Waseca channel trend.
-- Our Dawson demonstration project is moving forward and we anticipate
starting to drill in the third quarter of 2011.
-- The Kerrobert demonstration project production averaged 110 barrels of
oil per day ("bopd") for the first quarter and the two wells are now
being prepared to be tied into the new production facility.
Kerrobert Project
The Kerrobert expansion project has been commissioned and the central processing
facility ("CPF") is ready to accept production. Drilling and completion of the
10 air injection wells is complete, nine of the new horizontal production wells
are drilled, with five completed and the remaining five on schedule to be
completed and tied in by June 30.
We had anticipated the Pre-Injection Heating Cycle ("PIHC") in the new wells to
take up to 60 days; however temperature response was achieved in less than
twenty days, which allowed us to accelerate air injection operations. Air
injection began on three injector wells on the first pad in April. The two
remaining wells on this pad are near the end of their PIHC and will be on air
before the end of May. We expect to begin the PIHC in the injector wells on the
second pad by mid-June. All production will be brought into the CPF as the wells
come on-stream, including the two original wells from the demonstration project.
The production wells are all on schedule to be producing into the CPF by
mid-July.
We are pleased with the final placement of the injection and production wells as
they were drilled within our new design parameters. The new production wells are
larger in diameter, have a higher open flow area to the reservoir, a tighter
mesh in the FacsRite(TM) screen for improved solids control and an improved
wellhead configuration, all of which are expected to result in improved
production and operating capability.
Capital costs for the 10 well-pairs and facilities expansion are estimated at
approximately $95 million versus an original budget of approximately $75
million. Pipeline and facilities costs are on budget and on schedule. Drilling
and completion costs exceeded budget primarily related of the horizontal
production wells. The start-up of the drilling program was behind schedule due
to mechanical and operating problems with the drilling rig, and one well had to
be re-drilled due to intermediate casing failure while cementing. The completion
costs of the injection and production wells are on budget.
During the first quarter of 2011, the initial two wells' production was
approximately 110 bopd. Operations on the initial two wells were impacted by the
drilling and construction activities related to the expansion. During April,
road bans and limited access due to expansion drilling activities resulted in
lower on-stream times with production averaging 105 bopd.
Dawson Project
We received final Energy Resources Conservation Board ("ERCB") and Alberta
Environment ("AENV") approval for our initial Dawson project during the fourth
quarter of 2010. The Dawson project will initially consist of two THAI(R)
well-pairs plus associated surface facilities.
Field activities conducted during the first quarter of 2011 included drilling
two stratigraphic wells that were cored to confirm seismic contours and the
drilling of two ground water monitoring wells. Our plan is to start construction
of access roads and leases late in the second quarter while drilling and
completion activities will begin in the third quarter of 2011.
We will move the surface facilities from our first two wells at the Kerrobert
project to our Dawson project in the third quarter of 2011. PIHC is planned to
commence in the fourth quarter of 2011. Production is also expected to commence
in the fourth quarter.
In order to capitalize on the full potential at Dawson, the environmental
assessment and regulatory application associated with the Dawson expansion is
underway. The Dawson expansion project is being designed as a 10,000 bopd
capacity project and the required regulatory applications for both the ERCB and
AENV are scheduled to be submitted during the third quarter of 2011. We expect
the regulatory review cycle could take up to 18 months.
Conklin Demonstration Project
As part of our on-going evaluation of our Conklin operations, we have abandoned
the original three wells that were previously shut-in as well as P2B and P3B.
During the first quarter of 2011, we observed that the P1B well, where the toe
was drilled well short of the combustion zone, is beginning to heat up. We are
in the process of evaluating the multi-THAI(R) configuration, adding another air
injector on P1B further along this well bore and drilling a new production well
in a better part of the reservoir.
With our Kerrobert and Dawson projects moving forward, we are now primarily
evaluating options for the Conklin demonstration project as a field scale
testing site for future technology enhancements to the THAI(R) process.
May River Project
The May River application is proceeding through the regulatory process. We have
responded to all of the information requests and have recently filed our final
response to the three Statements of Concerns ("SOC") with the ERCB. We do not
believe that the SOCs have merit to warrant the granting of standing; however
this decision rests with the ERCB.
During the first quarter of 2011, we drilled 11 oil sands evaluation wells to
further evaluate resource potential and further delineate the resource for
future expansion phases of the May River property. Based on internal estimates
these wells added approximately 40 million barrels of best estimate contingent
resource and we have asked our external reserve evaluator, McDaniel & Associates
Consultants Ltd., to update our 2010 reserve report to reflect these drilling
results.
Archon Technologies Ltd. ("Archon")
Archon, our wholly-owned technology subsidiary, continues to advance our suite
of technologies, including a novel process to remove H2S in the produced gas
stream that will further enhance our CrystaSulf(TM) process. We plan to field
test this technology during 2011. Our ongoing research and development efforts
have identified new technologies and enhancements to existing intellectual
property that could result in as many as eight new patents in the coming year
which will serve to further strengthen and improve our core THAI(R) and CAPRI(R)
patents.
During the first quarter, we signed a five year non-commercial general
collaboration agreement concerning research, scientific, technological and human
resources development with Pemex Exploracion y Produccion ("PEP"), a subsidiary
entity of the Mexican state oil company, Pemex. This agreement provides for the
sharing of scientific and technological information, pursuant to the regulations
in force, and the evaluation of enhanced oil recovery technologies for heavy oil
deposits in Mexico. This agreement is an important first step in a possible
negotiation, under Mexican law, of a licensing deal that will permit PEP to
utilize Petrobank's THAI(R) technology.
Land Acquisitions
As previously reported Petrobank acquired 3.5 sections (2,240 acres) of
petroleum and natural gas rights at a Saskatchewan Crown Sale in late 2010. The
lands are located in the Plover area on the same trend as our Kerrobert project.
During the first quarter we purchased 3-D seismic and we plan to drill a
stratigraphic well later in 2011 to define the resource potential.
Petrobank closed an acquisition on March 31, 2011 to acquire 6.5 sections (4,160
acres) of petroleum and natural gas rights. These lands are situated two miles
southeast of the acquired Plover lands, and are also located on the same trend
as Kerrobert.
SUMMARY OF FINANCIAL AND OPERATING RESULTS
The following table provides a summary of Petrobank's financial and operating
results for the three month periods ended March 31, 2011 and 2010. Unaudited
condensed interim consolidated financial statements with Management's Discussion
and Analysis ("MD&A") will be available on the Company's website at
www.petrobank.com and on the SEDAR website at www.sedar.com.
Summary of Results (1)
Three months ended March 31, 2011 2010 Change
----------------------------------------------------------------------------
Financial
($000s, except where noted)
Oil and natural gas sales from
continuing operations 281,297 275,706 2%
Funds flow from continuing
operations (2) 168,384 188,371 (11%)
Per share - basic ($) 1.58 1.88 (16%)
- diluted ($) 1.57 1.77 (11%)
Net income from continuing
operations 20,585 321 6,313%
Per share - basic ($) 0.19 0.00 -
- diluted ($) 0.19 0.00 -
Net income attributable to
Petrobank shareholders (3) 20,585 65,057 (68%)
Per share - basic ($) 0.19 0.65 (71%)
- diluted ($) 0.19 0.58 (67%)
Capital expenditures (4)
PetroBakken 307,481 185,116 66%
Heavy Oil Business Unit
("HBU") 54,255 23,935 127%
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Total capital expenditures from
continuing operations 361,736 209,051 73%
Total assets 6,538,606 6,275,007 4%
Common shares outstanding, end
of period (000s)
Basic 106,257 101,839 4%
Diluted (5) 109,953 109,544 -
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Operations
PetroBakken operating netback
($/boe) (2) (6)
Crude oil and NGL sales price
($/bbl) (7) 81.92 76.08 8%
Natural gas sales price
($/Mcf) (7) 4.13 5.20 (21%)
Oil equivalent sales price (7) 74.46 70.41 6%
Royalties 11.84 9.68 22%
Production expenses 10.20 7.80 31%
----------------------------------------------------------------------------
Operating netback (2) (6) (8) 52.42 52.93 (1%)
Average daily production (6)
PetroBakken - oil and NGL
(bbls) 36,140 37,654 (4%)
PetroBakken - natural gas
(Mcf) 32,534 32,662 -
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Total conventional (boe)
(6)(9) 41,562 43,098 (4%)
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(1) Petrominerales Ltd. ("Petrominerales") has been presented as
discontinued operations in the comparative period as this business unit
was spun off to Petrobank shareholders at December 31, 2010.
(2) Non-GAAP measure. See "Non-GAAP Measures" section within this press
release.
(3) Net income attributable to Petrobank shareholders for the three months
ended March 31, 2010 includes the operating results of Petrominerales.
(4) Includes expenditures on property, plant and equipment, exploration and
evaluation and other intangible assets.
(5) Consists of common shares, stock options, directors deferred common
shares, deferred common shares, and incentive shares as at the period
end date.
(6) Six Mcf of natural gas is equivalent to one barrel of oil equivalent
("boe").
(7) Net of transportation expenses.
(8) Excludes hedging activities.
(9) HBU bitumen and heavy oil volumes are excluded from average daily
production as Conklin and Kerrobert operations are considered to be in
the exploration and evaluation phase and accordingly are capitalized.
PETROBANK'S LIQUIDITY AND CAPITAL RESOURCES
Petrobank and PetroBakken manage their capital structure independently and
generate their own cash flows, and have the ability to fund their operations
through the issuance of secured and unsecured debt as well as equity financing.
Petrobank's capital resources are focused on funding corporate and Heavy Oil
Business Unit expenditures. At March 31, 2011, independent of PetroBakken,
Petrobank on a standalone basis had a working capital deficit of $28.7 million
and available credit capacity of $196.2 million.
Based on Petrobank's current ownership and PetroBakken's intentions of paying an
annual dividend of $0.96 per PetroBakken share, Petrobank expects to receive
$105 million of dividends annually from PetroBakken, paid monthly. Petrobank can
also raise funds by selling a portion of its ownership in PetroBakken or by
issuing additional debt secured by this interest.
Petrobank expects to sufficiently fund our HBU capital expenditure program with
available credit, cash from operations and dividends received from PetroBakken.
ANNUAL GENERAL MEETING AND WEBCAST
Petrobank's annual general meeting (the "Meeting") will be held Wednesday, May
25, 2011 at 2:00 p.m. (Calgary time) in the Main Ballroom of The Metropolitan
Centre, 333 Fourth Avenue SW, Calgary, Alberta. The Meeting and corporate
presentation will be webcast live and available for replay at www.petrobank.com
under the "Investors" section. After the formal business of the Meeting and
corporate presentation, management of the Company will provide a question and
answer period. For those participating by webcast, you are invited to also
submit questions. Petrobank's management will endeavour to answer as many
questions as possible during the time frame allotted. Before and after the
Meeting, management and staff of Petrobank and PetroBakken will be presenting
informational displays regarding Company activities and we cordially invite all
guests to attend.
Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas
exploration and production company with operations in western Canada. The
Company operates high-impact projects through two business units and a
technology subsidiary. Petrobank's 59% owned TSX-listed subsidiary, PetroBakken
Energy Ltd. (TSX:PBN), is an oil and gas exploration and production company
combining light oil Bakken and Cardium resource plays with conventional light
oil assets, delivering industry leading operating netbacks, strong cash flows
and production growth. PetroBakken is applying leading edge technology to a
multi-year inventory of Bakken and Cardium light oil development locations,
along with a significant inventory of opportunities in the Horn River and
Montney gas resource plays in northeast BC. PetroBakken's strategy is to deliver
accretive production and reserves growth, along with an attractive dividend
yield. Whitesands Insitu Partnership, a partnership between Petrobank and its
wholly-owned subsidiary Whitesands Insitu Inc., owns 104 net sections of oil
sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and
14 sections of petroleum and natural gas rights in Kerrobert, Saskatchewan, and
operates the Kerrobert and Conklin projects which are field-demonstrating
Petrobank's patented THAI(R) heavy oil recovery process. THAI(R) 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(R)
and CAPRI(R) are registered trademarks of Archon Technologies Ltd., a
wholly-owned subsidiary of Petrobank Energy and Resources Ltd., for specialized
methods for recovery of oil from subterranean formations through in-situ
combustion techniques and methodologies with or without upgrading catalysts.
Used under license by Petrobank Energy and Resources Ltd.
Non-GAAP Measures: This press release contains financial terms that are not
considered measures under generally accepted accounting principles ("GAAP"),
such as funds flow from continuing operations, funds flow per share and
operating netback. These measures are commonly utilized in the oil and gas
industry and are considered informative for management and shareholders.
Specifically, funds flow from continuing operations and funds flow per share
reflect cash generated from operating activities before changes in non-cash
working capital. Management considers funds flow from operations and funds flow
per share important as they help evaluate performance and demonstrate the
Company's ability to generate sufficient cash to fund future growth
opportunities and repay debt or financing obligations. Profitability relative to
commodity prices per unit of production is demonstrated by an operating netback.
Funds flow from continuing operations, funds flow per share and operating
netbacks may not be comparable to those reported by other companies nor should
they be viewed as an alternative to net income or other measures of financial
performance calculated in accordance with GAAP.
The following table shows the reconciliation of funds flow from continuing
operations to cash flow from operating activities from continuing operations for
the periods noted (in $000s):
Three months ended March 31,
----------------------------------------------------------------------------
2011 2010
----------------------------------------------------------------------------
Funds flow from continuing operations: Non-
GAAP 168,384 188,371
Changes in non-cash working capital (37,723) (13,615)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net cash provided by operating activities from
continuing operations: GAAP 130,661 174,756
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Contingent Resources: In this press release, Petrobank has disclosed estimated
volumes of "contingent resources". "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. In respect of the May River
project, contingencies include current uncertainties around the specific scope
and timing of the development of the project; lack of regulatory approvals;
uncertainty regarding marketing plans for production from the subject area; and
need for improved estimation of project costs. Contingent resources do not
constitute, and should not be confused with, reserves. There is no certainty
that it will be commercially viable to produce any portion of the contingent
resources on the May River property.
Forward-Looking Statements: Certain information provided in this press release
constitutes forward-looking statements. Specifically, this press release
contains forward-looking statements relating to financial results, results from
operations, the timing of certain projects, future resource potential, potential
technology enhancements and sources of available financing. 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 forecasted. 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.
Natural gas volumes have been converted to barrels of oil equivalent ("boe").
Six thousand cubic feet ("Mcf") of natural gas is equal to one barrel of oil
equivalent based on an energy equivalency conversion method primarily
attributable at the burner tip and does not represent a value equivalency at the
wellhead. Boes may be misleading, especially if used in isolation.
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