Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is
pleased to announce our first quarter 2009 financial and operating results.
(All references to $ are Canadian dollars unless otherwise noted)
HIGHLIGHTS
(all comparisons are to the first quarter of 2008)
- Petrobank's production almost doubled to 43,856 barrels of oil equivalent per
day ("boepd") in the first quarter of 2009.
- Canadian Business Unit ("CBU") production increased 59% to 22,085 boepd.
- Latin American Business Unit ("LABU") production increased 152% to 21,771
barrels of oil per day ("bopd").
- Our Heavy Oil Business Unit ("HBU") produced 248 bopd in March and 256 bopd in
April.
- Despite a sharp drop in world oil prices funds flow from operations increased
by 1% to $125.2 million ($1.40 per diluted share). We recorded a net loss of
$1.5 million ($0.02 per diluted share) in the first quarter compared to net
income of $35.5 million ($0.40 per diluted share) in the same 2008 period.
- CBU production expenses improved 27% to $6.81/boe and LABU production expenses
improved 32% to $7.40/bbl.
- CBU operating netbacks, excluding hedging gains of $5.31/boe, averaged
$34.68/boe and LABU operating netbacks averaged $30.18/bbl in the first quarter.
- On April 27, 2009, Petrobank agreed to sell 9.9 million shares of our
Petrominerales holdings for gross proceeds of $101.5 million. The transaction is
expected to be completed on May 15, 2009, at which time Petrobank's ownership
interest will be reduced to approximately 66.8%.
FINANCIAL & OPERATING HIGHLIGHTS
Three months ended March 31, 2009 2008 % Change
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Financial
($000s, except where noted)
Oil and natural gas revenue 190,786 179,291 6
Funds flow from operations (1) 125,156 123,488 1
Per share - basic ($) 1.50 1.53 (2)
- diluted ($) 1.40 1.36 3
Net income (loss) (1,542) 35,537 -
Per share - basic ($) (0.02) 0.44 -
- diluted ($) (0.02) 0.40 -
Capital expenditures
Canadian Business Unit ("CBU") 70,024 110,489 (37)
Latin American Business Unit ("LABU") 81,560 68,746 19
Heavy Oil Business Unit ("HBU") 21,410 21,035 2
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Total Company 172,994 200,270 (14)
Total assets 2,414,146 1,737,225 39
Net debt (1) 418,079 181,306 131
Common shares outstanding, end of period
(000s)
Basic 83,598 82,489 1
Fully diluted (2) 99,214 96,889 2
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Operations
CBU operating netback ($/boe except where noted)
(1)(3)
Oil and NGL revenue ($/bbl) (4) 48.57 91.87 (47)
Natural gas revenue ($/mcf) (4) 5.35 7.73 (31)
Oil and natural gas revenue (4) 46.81 83.55 (44)
Royalties 5.32 6.74 (21)
Production expenses 6.81 9.35 (27)
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Operating netback (5) 34.68 67.46 (49)
LABU operating netback ($/bbl) (1)
Oil revenue (4) 42.18 86.53 (51)
Royalties 4.60 8.25 (44)
Production expenses 7.40 10.86 (32)
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Operating netback (5) 30.18 67.42 (55)
Average daily crude oil production (3)
CBU - oil and NGL (bbls) 19,722 11,351 74
CBU - natural gas (mcf) 14,179 15,229 (7)
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Total CBU (boe) 22,085 13,889 59
LABU - oil (bbls) (6) 21,771 8,635 152
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Total Company conventional (boe) 43,856 22,524 95
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(1) Non-GAAP measure. See "Non-GAAP Measures" section.
(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"). HBU bitumen volumes are excluded from average daily production
as Whitesands operations are considered to be in the pre-operating stage
and accordingly are capitalized.
(4) Net of transportation expenses.
(5) Excludes hedging activities. In the first quarter of 2009 the CBU
realized gains of $5.31/boe (2008 - realized loss of $1.25/boe) and no
gain or loss was recognized by the LABU (2008 - realized loss of
$2.36/bbl).
(6) Actual production sold for the three months ended March 31, 2009 was
21,409 bopd (2008 - 8,635 bopd).
OPERATIONAL REVIEW
Petrobank reported strong funds flow from operations of $125.2 million, or $1.40
per diluted share, in the first quarter of 2009 as year over year sales volumes
almost doubled to 43,856 boepd. Funds flow from operations increased 1% from the
prior year, despite a 56% decrease in world oil prices. CBU infrastructure
investments in 2008 reduced operating expenses to $6.81/boe in the first
quarter, preserving strong operating netbacks of $34.68/boe, excluding hedging
gains of $5.31/boe. Similarly in Colombia, continued improvements in production
operations also decreased operating expenses to $7.40/bbl, leading to operating
netbacks of $30.18/bbl.
CANADIAN BUSINESS UNIT (CBU) OPERATIONAL UPDATE
Following an aggressive drilling program through 2008, our first quarter 2009
production averaged 22,085 boepd, a 59% increase from the 13,889 boepd produced
in the first quarter of 2008. In response to the lower oil price environment in
early 2009 we reduced our drilling program to 20 (16.14 net) Bakken horizontal
wells during the first quarter. Despite lower activity levels, production was
down less than 1% from the fourth quarter of 2008. Our efforts in the field to
continue optimizing well performance and operating efficiencies minimized the
impact of the reduced activity on our production. Outside of the Bakken, our
activities are targeted toward building our expertise and drilling inventory in
other large resource accumulations, including the Montney and Horn River Basin.
In 2009, our primary focus will be to maintain our low-cost advantage through
selective drilling in the Bakken. We are positioned for continued long term
reserve and production growth, despite our reduced pace of development at the
beginning of 2009. At current commodity prices we expect to drill a further 50
wells this year and if oil prices improve we are prepared to drill as many as
120 wells in 2009. All of our Bakken drilling emphasizes testing and refining
different technologies that have the potential to increase ultimate resource
recovery.
The Bakken Resource
Petrobank pioneered the horizontal fracture stimulation techniques that opened
up the true potential of this substantial resource, and we continue to find new
ways to improve well performance and expected ultimate recoveries from the
Bakken. Our recent efforts to further improve Bakken production have focused on
increasing the intensity of fracture stimulation completions (fracs) by 38% in
our long (1400 metre) horizontals, by 200% in our short (700 metre) horizontals,
and by 400% in our short bilateral (two 700 metre horizontal legs from a single
vertical well bore) horizontal wells. We continue to build on our innovative
approach to maximizing value from the Bakken resource and we are monitoring
production performance from these wells to optimize future drilling and fracture
stimulation design. Our production and reserves are heavily weighted (over 85%)
to high value Bakken light oil and associated gas and liquids. This allows
Petrobank to achieve industry-leading netbacks and demonstrates our high quality
asset base.
Of our year-end inventory of over 550 undrilled Bakken locations, only 162 have
been assigned 2P reserves with an additional 19 assigned possible reserves. Our
current drilling inventory is based on only four wells per section and could
easily double with the advances being realized by increasing well density and
frac intensity. We believe the 3P reserve estimates come closer to reflecting
the true potential of our assets as our reserves are derived largely from low
risk, extensive resource accumulations. CBU 3P reserves increased by 83%
year-over-year to 86.2 million boe and reserve additions of 45.5 million boe
replaced our 2008 production more than seven times. These 3P reserves have a net
present value, discounted at 10%, before tax of $2.0 billion, an 85% increase
from 2007 despite steep declines in commodity prices.
Part of our strategy in the Bakken is to operate centralized facilities to
capture additional value from the gas and natural gas liquids associated with
the light oil, and to ensure field efficiencies that maintain low operating
costs. To strengthen our infrastructure, three new facilities at Viewfield,
Creelman, and Freestone were connected to our main Midale plant through 100
kilometres of new pipelines. Together our facilities are now conserving more
than 7 mmcf/d of natural gas plus associated natural gas liquids, allowing us to
maintain low operating costs while improving our overall project economics.
The enhanced operational efficiencies achieved through our extensive
infrastructure investments resulted in a reduction of our Bakken production
costs to $6.03/boe. This brings the average first quarter production costs for
all of our CBU operations down to $6.81/boe, a 27% decrease from the $9.35/boe
recorded in the first quarter of 2008. Our future plans include two more
pipeline-connected facilities that are scheduled to be built as drilling
activity extends to the north. At our current drilling pace, construction is
expected to commence in late 2009 or 2010.
Beyond Bakken
Petrobank has also established strong positions in two massive natural gas
resource plays; the Montney and the Horn River Basin. The key to unlocking the
potential of these plays is through the use of horizontal wells and multi-stage
fracture stimulation technologies, similar to those pioneered by Petrobank in
the Bakken. We intend to capitalize on our evolving experience with advanced
fracturing techniques, with the goal of building a substantial, long-term
inventory of drilling locations at a low near-term cost.
In October 2008, through the acquisition of a private company, we acquired a
highly prospective position in the Montney tight gas play at Monias in
northeastern B.C. We now have a 100% working interest in 17 sections of land,
and a 5.0 mmcf/d gas plant.
In December 2008, we drilled our first Montney horizontal well, and in February
2009 we performed a seven-stage fracture stimulation in the upper portion of the
135 metre thick Montney interval. The well flow tested at initial rates in
excess of 7.5 mmcf/d plus 180 barrels of natural gas liquids per day. The well
was put on production at the end of the first quarter at a restricted rate of
5.5 mmcf/d. This well is currently producing at approximately 2.2 mmcf/day
showing a typical production profile where the rate drops quickly and then
flattens at a much lower decline rate. The consistent geology across our 17
sections of land establishes a 67-well inventory of prolific Montney drilling
locations. Our next steps will be to install additional compression to increase
our plant capacity to 10.0 mmcf/d and then drill another well later in 2009 to
test new technology ideas and improve our economics for the play. Our
independent reserve evaluators have only assigned reserves to the first well in
this multi-well development.
A second resource play where we can apply our innovative completion experience
is in the Horn River Shale Basin in northeast B.C. As this emerging play
developed we began to build an acreage position, which has now expanded to 82
B.C. sections (54,721 acres) of 100% working interest lands and 14 B.C. sections
of 15.5% working interest lands. Our first horizontal evaluation well was
drilled in the first quarter of 2009 in an area with all-season access close to
the Alaska Highway. The majority of the basin is characterized by a short
three-month operating season (January to March) due to the presence of thick
muskeg. All-season access at this first location allowed us to complete the
multi-stage fracture stimulation during the second quarter of 2009. Our
immediate focus will be on drilling test wells and developing a multi-year
inventory of drilling locations in the Muskwa and Evie shales. No reserves have
been assigned to our Horn River asset base as at December 31, 2008.
Cornwall
Late in 2007, we drilled an exploration well in the Cornwall area which tested
gas at 6.5 mmcf/day with 200 barrels per day of condensate. We completed a short
pipeline tie-in with compression installation during the quarter, and brought
the well on production April 1st to take advantage of recently announced royalty
incentives in the province of Alberta. Production from the well has been
pipeline restricted at rates between 2.0 to 2.5 mmcf/day.
HEAVY OIL BUSINESS UNIT (HBU) OPERATIONAL UPDATE
- Achieved stable production rates from our P3B well with air injection at
one-third of design rates
- Effectively eliminated sand production with revised P3B liner design
- Produced at restricted rates of 248 bopd in March and 256 bopd in April
- Sustained P3B wellbore temperatures in the catalyst activation range
- Filed the Kerrobert project application with the Saskatchewan regulatory
authorities
- Advanced the May River and Dawson project applications through the Alberta
regulatory process
Whitesands Project
During March and into the second quarter of 2009, P3B operations were stabilized
and rateable production was achieved. In the first quarter, P3B operations were
ramped up following the A3 injection well workover and the commissioning of new
plant facilities. Production averaged 248 bopd in March and 256 bopd in April,
these restricted production rates correspond to a reduced air injection rate
required to balance P2 production operations. The highest daily oil rate from
the P3B well was 378 bopd in March and 404 bopd in April. During April,
production from the P1 well was suspended and maintenance work on the P3B
wellhead and primary separator reduced on-stream factors.
Since the initiation of production operations on P3B the well has exhibited
negligible sand production, irrefutably proving the effectiveness of the new
liner design. Produced gas volumes and rates are also in balance with the air
injection rate, confirming the toe to heel process. Wellbore temperatures are
now between 300 and 400 degrees Celsius, within the CAPRI(TM) catalyst
activation range. Preliminary analysis of produced oil from P3B indicates
upgrading to 12 degrees API, similar to the other wells. However, P3B oil has
shown a significant reduction in asphaltene content, an increased volume of
condensed light oil production and higher hydrocarbon content in the produced
gas. Now that the well is operating in the optimum catalyst temperature range,
conclusive, quantitative evidence confirming catalytic upgrading is expected
with further testing. Associated water production continues to be high quality
and is easily separated from the produced oil. Continuous upgrading and the
composition of the produced gas indicate sustained high temperature combustion.
We have a drilling rig on-site and plan to have our P1 replacement well, P1B,
drilled in the second quarter incorporating our new liner design. We have
decided to cost-effectively convert Whitesands into a modified three well
THAI(TM)/CAPRI(TM) demonstration site, which will enable us to test any other
new technology options, such as oxygen enrichment, using the existing
facilities.
Kerrobert Project
Pre-development work is currently underway on our two well, THAI(TM)
conventional heavy oil project at Kerrobert. This third party THAI(TM) license
project is located in west central Saskatchewan. We filed the Saskatchewan
Ministry of Energy and Resources enhanced oil recovery regulatory application
for the project on April 22nd. This filing begins the approximately one month
approval process. Pending regulatory approval we expect to begin site
preparation and drilling early in June, with the Pre-ignition Heating Cycle
beginning in July and first production expected by the fourth quarter.
A public open house was held on April 17th in Kerrobert. A broad cross section
of the local communities, land owners, and government representatives attended
the open house. We received a positive response and encouragement for the
project and its potential.
This joint project will highlight the applicability of the THAI(TM) technology
in the conventional heavy oil resource base in Saskatchewan. We consider that a
significant portion of the estimated 20 billion of barrels of unrecovered
conventional heavy oil resources in Saskatchewan can be commercialized using
THAI(TM). In addition, Saskatchewan is actively encouraging oil and gas
development and the application of advanced technologies.
May River Project
The May River Project is our first large-scale commercial THAI(TM) project on
Petrobank's oil sands leases west of Conklin, Alberta. The May River project
design builds on the experience gained from the Whitesands pilot. This project
will be built in phases, with initial production capacity of 10,000 barrels of
THAI(TM) oil per day, and an ultimate capacity of up to 100,000 bopd.
The regulatory application for May River's first phase was filed with the Energy
Resources Conservation Board and Alberta Environment in December 2008. The
application has been deemed complete and is now moving efficiently through the
regulatory process. The front end engineering and design for the project began
in the fourth quarter of 2008, and we expect to have completed this phase of
engineering by the third quarter of 2009. The design incorporates
self-sufficient power generation utilizing low-energy produced gas, sulphur
recovery, is CO2 capture ready, and will be a net water producer rather than a
water user. These designs contribute to making the May River project a leading
environmentally sustainable process for oil sands and heavy oil development. The
project is also designed to utilize a modular approach with direct applicability
to heavy oil projects world-wide.
Dawson Project
The Dawson Project is a joint project involving our first Alberta-based, third
party THAI(TM) license. Our partner is now Shell Canada Limited who acquired
Duvernay Oil Corp. in August 2008. The project is located near Peace River,
Alberta and will be developed in the Bluesky formation. In August 2008, a
stratigraphic well was drilled on the project site, which will be used as a
thermal observation well during the project's operating phase. The regulatory
application for the project was filed on April 2nd.
Business Development
Our wholly-owned subsidiary, Archon Technologies Ltd., continues to evaluate a
number of innovative engineering, environmental, and other value-added
technology options to improve operational efficiency, increase product quality,
and reduce the overall environmental impact of bitumen and heavy oil recovery.
Technologies being assessed include enriched oxygen injection, power generation
using produced lean gas, enhanced produced water quality, and incremental
surface upgrading.
We continue to receive increasing world-wide interest in our technologies
because of their superior economic and environmental benefits. Our joint project
strategy is to demonstrate and commercialize THAI(TM) in a wide range of large
global resource opportunities. Negotiations are ongoing and we expect to
successfully conclude additional joint projects in the near term.
LATIN AMERICAN BUSINESS UNIT - PETROMINERALES LTD. (TSX: PMG - CURRENTLY 76.9%
OWNED)
A full operational update of our 76.9% owned Latin American Business Unit,
Petrominerales Ltd., was published on May 6, 2009 and can be found at
www.petrominerales.com and www.sedar.com. Highlights of this release included:
- Significant production growth in the quarter; crude oil production increased
152% to 21,771 bopd due to drilling successes at Corcel, Mapache and Neiva.
- Strong operating netbacks resulted in cash flow of US$41.8 million (US$0.42
per share) and net income of US$7.4 million (US$0.07 per share) despite a sharp
drop in world oil prices.
- Solid financial position with net working capital of US$16.3 million, an
undrawn US$80 million credit facility, strong cash flows and operating netbacks
combined with significant production growth.
- Continued drilling success has resulted in production averaging 25,252 bopd to
date in May.
- Repurchased 802,200 common shares under a normal course issuer bid.
ANNUAL GENERAL MEETING
Petrobank's annual general meeting (the "Meeting") will be held today (Tuesday,
May 12, 2009) at 2:00 p.m. (Calgary time) in the Main Ballroom of The
Metropolitan Centre, 333 Fourth Avenue SW, Calgary, Alberta, Canada. The Meeting
will be webcast live and available for replay at
http://www.petrobank.com/invcorporatepresentation.html. To listen to the Meeting
live please enter in your web browser
http://w.on24.com/r.htm?e=143113&s=1&k=EA1AB6BFC032F66E49BDDA2F4662D77A. 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 submit questions to Petrobank any time during this
question and answer session by typing your question into a box displayed on the
webcast page and clicking on the button "submit". Petrobank's management will
endeavor to answer as many questions as possible during the time frame allotted.
Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas
exploration and production company with operations in western Canada and Latin
America. The Company operates high-impact projects through three business units
and a technology subsidiary. The Canadian Business Unit is focused on developing
a solid production platform from the Bakken light oil play in southeast
Saskatchewan, and exploiting a large undeveloped land base through the
application of new technology to large oil and gas resource opportunities. The
Latin American Business Unit, operated by Petrobank's 76.9% owned (to decrease
to 66.8% on May 15, 2009) TSX-listed subsidiary, Petrominerales Ltd. (TSX:PMG),
is a Latin American-based exploration and production company producing oil in
Colombia with 16 exploration blocks covering a total of 1.9 million acres in the
Llanos and Putumayo Basins of Colombia and 2.6 million acres in the Ucayali
Basin of Peru. 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. THAI(TM) 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 financial results, 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.
Non-GAAP Measures
This press release contains financial terms that are not considered measures
under Canadian generally accepted accounting principles ("GAAP"), such as funds
flow from operations, funds flow per share, net debt 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 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. Net debt
includes bank debt plus accounts payable and accrued liabilities less current
assets (excluding future income tax asset) and is used to evaluate the Company's
financial leverage. Profitability relative to commodity prices per unit of
production is demonstrated by an operating netback. Funds flow from operations,
funds flow per share, net debt and operating netbacks may not be comparable to
those reported by other companies nor should they be viewed as an alternative to
cash flow from operations, net income or other measures of financial performance
calculated in accordance with GAAP. The following table shows the reconciliation
of funds flow from operations to cash flow from operating activities for the
periods noted:
Three months ended March 31,
2009 2008 Change
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Funds flow from operations: Non-GAAP 125,156 123,488 1%
Changes in non-cash working capital (13,892) (53,791) (74%)
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Cash flow from operating activities: GAAP 111,264 69,697 60%
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Resources and Contingent Resources
In this press release, Petrobank has disclosed estimated volumes of "contingent
resources" or "resource" estimates. "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
bbl 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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