Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is
pleased to announce second quarter 2010 financial and operating results
highlighted by funds flow from operations of $3.12 per diluted share and net
income of $0.35 per diluted share.
Petrobank's results include the financial and operating results of PetroBakken
Energy Ltd. ("PetroBakken") (TSX:PBN), 58% owned by Petrobank and Petrominerales
Ltd. ("Petrominerales") (TSX:PMG), 66% owned by Petrobank. PetroBakken announced
second quarter financial and operating results on August 10, 2010.
Petrominerales announced second quarter financial and operating results on
August 5, 2010.
All references to $ are Canadian dollars unless otherwise noted. All comparisons
are to the prior year period, unless otherwise noted.
Q2 2010 HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS
-- Petrobank's consolidated production increased 110% to 86,466 barrels of
oil equivalent per day ("boepd") in the second quarter of 2010 compared
to 41,127 boepd in the second quarter of 2009 due to production
increases in PetroBakken and Petrominerales.
-- Funds flow from operations increased 123% to $334.6 million in the
second quarter of 2010. On a per diluted share basis, funds flow from
operations increased 90% to $3.12.
-- Net income increased 18% to $41.1 million in the second quarter of 2010.
On a per diluted share basis, net income decreased 13% to $0.35.
Petrobank's Heavy Oil Business Unit ("HBU")
-- Petrobank incurred $10.7 million of capital expenditures in the second
quarter related to our Kerrobert heavy oil project and the May River /
Conklin oil sands projects.
-- We successfully completed pump reconfigurations at Kerrobert and the
project is now producing at 250 barrels of oil per day ("bopd") and
trending up.
-- Kerrobert production is being consistently upgraded insitu by over six
degrees API.
-- Regulatory approval for the Kerrobert 10 well expansion project was
received on August 6th, 54 working days from the initial application
submission.
-- The May River Project is waiting for final approval from the ERCB,
although Alberta Environment contingent approval for the project was
received April 12, 2010.
PetroBakken
-- PetroBakken's production averaged 42,263 boepd in the second quarter of
2010, a 116% increase over the prior year, primarily driven by the
acquisition of TriStar Oil & Gas Ltd. ("TriStar") on October 1, 2009 and
drilling activities in the Bakken. Production declined 2% compared to
the first quarter of 2010 due to a reduction in drilling activity during
spring break-up.
-- In April 2010, we improved our financial flexibility through a $100
million increase in our revolving credit facility. The borrowing limit
was increased from $900 million to $1 billion.
-- Our operating netback (excluding hedging gains) of $46.10/boe improved
8% over the prior year primarily due to the increase in oil prices.
Compared to the first quarter of 2010, operating netbacks decreased 13%
as a result of lower pricing partially offset by lower royalties and
production expenses.
-- Drilled 37 (27.4 net) wells in the second quarter; including 28 (22.1
net) in the Bakken, and 5 (3.6 net) in conventional plays in southeast
Saskatchewan.
-- PetroBakken completed the acquisition of Result Energy Inc., the third
of our Cardium focused corporate acquisitions, and one non-core property
disposition.
Petrominerales
-- Second quarter crude oil production grew to 44,203 bopd, a 105% gain
over the prior year and a 16% gain over the first quarter of 2010.
-- Generated a solid operating netback of US$50.93 per barrel in the
quarter, a 38% increase.
-- Drilled two new oil discoveries on our Central Llanos Basin acreage in
Colombia, Yenac-1 and Capybara-1.
-- Petrominerales completed the acquisition of PanAndean Resources plc on
April 14, 2010. PanAndean assets include four exploration contracts in
Peru and one in Colombia totalling 6.7 million gross (2.6 million net)
acres.
-- On August 10, 2010, Petrominerales announced a US$550 million
convertible debenture offering (the "Offering"). The debentures are
convertible into common shares of Petrominerales and have an annual
coupon rate of 2.625% and a conversion price of US$34.746 (Cdn$36.254)
per debenture. The debentures will be issued at 100% of their principal
amount and, unless previously redeemed, converted or cancelled, will
mature in 2016. The debentures are expected to be issued on or about
August 25, 2010. The offering is subject certain approvals, including
the approval of the Toronto Stock Exchange.
PETROBANK'S LIQUIDITY AND CAPITAL RESOURCES
Petrobank, PetroBakken and Petrominerales manage their capital structure
independently; they 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 HBU expenditures. At June 30, 2010, independent of PetroBakken and
Petrominerales, Petrobank on a standalone basis had no bank debt outstanding and
positive working capital of $22.4 million. A $30 million credit facility is also
available.
Based on Petrobank's current ownership in PetroBakken, Petrobank expects to
receive $105 million of dividends annually paid monthly. With the recent
commencement of a dividend policy at Petrominerales, Petrobank also expects to
receive $33 million annually from Petrominerales, paid on a quarterly basis.
Petrobank also has an option to raise funds by issuing equity, selling a portion
of its ownership in PetroBakken and Petrominerales or by issuing additional debt
secured by these interests.
We currently intend to fund our HBU capital expenditure program with cash on
hand, available credit, cash from operations and dividends received from
PetroBakken and Petrominerales.
SUMMARY OF FINANCIAL AND OPERATING RESULTS
Three months ended June 30, Six months ended June 30,
% %
2010 2009 Change 2010 2009 Change
---------------------------------------------------------------------------
Financial ($000s,
except where
noted)
Oil and natural
gas revenue 573,040 224,396 155 1,106,173 415,182 166
Funds flow from
operations (1) 334,592 150,350 123 668,546 275,506 143
Per share
- basic ($) 3.18 1.78 79 6.51 3.28 98
- diluted ($) 3.12 1.64 90 6.26 3.03 107
Net income 41,050 34,667 18 123,549 33,125 273
Per share
- basic ($) 0.39 0.41 (5) 1.20 0.39 208
- diluted ($) 0.35 0.40 (13) 1.11 0.39 185
Capital
expenditures
PetroBakken 122,688 38,901 215 307,804 108,925 183
Petrominerales 115,055 93,203 23 231,264 174,763 32
Heavy Oil
Business Unit 10,653 12,318 (14) 34,587 33,728 3
---------------------------------------------------------------------------
Total Company 248,396 144,422 72 573,655 317,416 81
Total assets 7,160,685 2,421,171 196 7,160,685 2,421,171 196
Common shares,
end of period
(000s)
Basic 105,993 92,267 15 105,993 92,267 15
Diluted (2) 110,167 99,270 11 110,167 99,270 11
---------------------------------------------------------------------------
Operations
PetroBakken
operating
netback ($/boe
except where
noted) (1) (3)
Oil and NGL
revenue ($/bbl)
(4) 70.98 62.22 14 73.61 54.88 34
Natural gas
revenue ($/mcf)
(4) 4.11 3.91 5 4.57 4.56 -
Oil and natural
gas revenue (4) 62.86 56.64 11 66.65 51.45 30
Royalties 9.17 7.40 24 9.43 6.30 50
Production
expenses 7.59 6.52 16 7.69 6.67 15
---------------------------------------------------------------------------
Operating
netback (5) 46.10 42.72 8 49.53 38.48 29
Petrominerales
operating
netback ($/bbl)
(1)
Oil revenue (4) 65.15 55.76 17 65.87 49.01 34
Royalties 6.51 5.02 30 7.02 4.81 46
Production
expenses 6.61 7.86 (16) 5.60 7.63 (27)
---------------------------------------------------------------------------
Operating
netback 52.03 42.88 21 53.25 36.56 46
Average daily
production
PetroBakken -
oil and NGL
(bbls) 34,852 16,761 108 36,245 18,233 99
PetroBakken -
natural gas
(mcf) 44,469 16,906 163 38,598 15,550 148
---------------------------------------------------------------------------
Total
PetroBakken
(boe) (3) 42,263 19,579 116 42,678 20,825 105
Petrominerales -
oil (bbls) (6) 44,203 21,548 105 41,218 21,659 90
---------------------------------------------------------------------------
Total Company
conventional
(boe) (7) 86,466 41,127 110 83,896 42,484 97
---------------------------------------------------------------------------
(1) Non-GAAP measure. See "Non-GAAP Measures" section within this press
release.
(2) Consists of common shares, stock options, deferred common shares,
incentive shares and convertible debentures as at the period end date.
(3) Six Mcf of natural gas is equivalent to one boe.
(4) Net of transportation expenses and excludes revenue from purchased oil.
(5) Excludes hedging activities.
(6) Actual production sold for the three and six months ended June 30, 2010
was 49,466 boe and 43,995 bopd, respectively (2009 - 21,390 bopd and
21,399 bopd). After adjusting for oil purchased from
third parties and marketed on their behalf, Petrominerales actual
production sold and used in per barrel calculations was 44,560 bopd and
40,880 bopd, respectively.
(7) HBU bitumen volumes are excluded from average daily production as
Conklin and Kerrobert operations are considered to be in the
pre-operating stage and accordingly are capitalized.
HEAVY OIL BUSINESS UNIT OPERATIONAL UPDATE
Kerrobert Project
Early in the second quarter we installed and commissioned progressive cavity
pumps, modified wellhead configurations and added bottomhole pressure monitoring
appropriate for the new pumps. As a result, the wells were offline for the first
half of the second quarter. We also experienced downtime late in second quarter
and early in the third quarter due to incinerator repairs, well clean up
procedures, and the replacement of a metal-on-metal pump on one of the wells to
an elastomeric design.
The reconfigured wells were brought online and stabilized during mid-May. The
new wellheads and downhole instrumentation will provide us with the ability to
control and optimize well performance. Production rates have ranged from 60 to
150 bopd per well as we lined out the pumps. We established new well operating
parameters, and cleaned up the wells as they continue the transition from
primary heavy oil to THAI(TM) oil production. We are now producing upgraded oil
consistently in the 14 to 18 degree API range. We are seeing minimal solids
production, all of which has been less than the Facsrite(TM) mesh size. Our
Kerrobert project is currently averaging 250 bopd and rising.
Additional compression was installed and became operational at the end of April
and we have ramped up air injection to over 2/3 of designed capacity. Wellbore
temperatures at the toes of the wells have stabilized above 200 degrees Celsius
and we have operated at temperatures of up to 650 degrees Celsius. Temperatures
are rising along both wellbores with heel temperatures up to 90 degrees Celsius
versus an ambient reservoir temperature of 27 degrees Celsius.
Our ten well expansion plans for Kerrobert are progressing and we have received
both our environmental and enhanced oil recovery approvals as of August 6, 2010
which was just 54 working days from the application date and only 14 working
days from receipt of our final freehold consents. We expect drilling to commence
during the third quarter of 2010. Startup operations for the pre-ignition
heating cycle with steam injection are planned for early November 2010 and air
injection is expected to commence in Q1 of 2011.
Conklin Project
During the second quarter the majority of production at Conklin came from our
P3B well with production rates averaging 100 bopd and maximum rates exceeding
535 bopd. Production was adversely impacted by downtime related to surface
equipment issues and while we established full communication between P1B and P2B
and the combustion front.
During the quarter we continued evaluating reconfiguration and pumping options
for the Conklin wells, building on our Kerrobert experience. We also continued
to operate the P3B well at higher bottomhole pressures in April. The testing was
completed late in the month and production rates were measured at up to 480
bopd. The testing has demonstrated that operating at a higher backpressure
improves well control and production. We expect to make minor modifications to
our current surface facilities to enable sustained operations at higher
backpressures in conjunction with the reconfiguration to include pumps. In the
last week of April, the P3B well was shut-in to enable the replacement of a
packer in the A3 injection well. The work was completed and the well was
restarted during mid-May. Upon the restart we encountered a surface casing vent
flow ("SCVF") which, pursuant to ERCB regulations, required the well to be shut
in. After evaluating the potential causes of the SCVF over a 30 day period in
cooperation with the ERCB, it was determined that the SCVF was not material. The
well was brought back on in mid July. During this extended downtime we took the
opportunity to complete preventive maintenance on the P3B well train.
On the P1B well and the P2B well, we progressed towards establishing full
communication with the combustion zone. We now understand that these wells were
drilled further away from the combustion zone than originally projected,
resulting in a longer restart time. We have recorded temperatures in the
offsetting observation wells of between 300 - 500 degrees Celsius indicating the
combustion zone is now in proximity of the wells. Production rates have ranged
from 100 to 150 bopd of partially upgraded oil.
Production on all wells was interrupted by operating problems encountered with
our new high efficiency incinerator design which constrained the produced gas
and liquid production from the wells. Design issues have now been addressed, and
the unit has performed above design specifications as of mid-July. We also
scheduled a five-day maintenance turnaround for the middle of July.
With the facilities fully operational and the maintenance issues addressed, we
have increased air injection rates on the P1B and the P2B wells to up to 100,000
m3/day as we aggressively establish full communication with the combustion zone.
By the end of the third quarter we will have installed a gas lift string and
bottom hole pressure monitor and will have conducted another high bottomhole
pressure run on P3B. We will also maintain high air injection rates on the P1B
and P2B wells to facilitate rapid communication.
In March of 2010 we acquired our fourth seismic survey over the Conklin pilot
area. The new survey has been processed and we are interpreting the results. The
time lapse seismic has proven to provide sensitive analysis of the movement of
the combustion front.
May River Project
Engineering, procurement, and construction management on the project has been
awarded for the wellsites, pipelines, and central processing facility. Petrobank
has initiated ordering long lead materials and equipment, and with timely
regulatory approval, steam start-up could occur in mid-2012. An additional 12
OSE stratigraphic wells and 3D seismic over the project area have been
completed, allowing us to further delineate the reservoir and to optimize well
placements for the 18 well pairs planned for Phase 1 of the project.
The regulatory application for May River's first phase was filed with the ERCB
and Alberta Environment in December 2008. The first round of SIR's from Alberta
Environment and the ERCB were responded to in mid-December 2009. We have
received and responded to the second round of SIR's from Alberta Environment and
they have given the project contingent approval (subject to ERCB approval) on
April 12, 2010. We received the second round of SIR's from the ERCB on May 13,
2010 and responses were submitted on June 1, 2010. The final hurdle to approval
will be the resolution of two Statements of Concern ("SOC"). The SOCs were
recently filed and are general in nature. Pursuant to Section 26 of the Energy
Resources Conservation Act (ERCA), the SOC holders must demonstrate how their
rights are directly and adversely impacted by the project. To date, they have
not provided such information, and the ERCB is soliciting both parties to
determine if they have legitimate concerns and standing before they will issue
the final approval for the project.
The May River design is CO2 capture ready, incorporates power generation
utilizing low energy produced gas, sulphur recovery, and will be a net water
producer rather than a water user, making our May River project a leading
environmentally sustainable benchmark for oil sands and heavy oil development.
The project utilizes a modular approach that is designed to be installed and
operated on heavy oil projects world-wide.
Dawson Project
The second round of SIR's were received from the ERCB in June and responses were
submitted in July. There are no Statements of Concern filed related to this
project. Engineering has been completed and equipment procurement will commence
as soon as final approvals have been received. Dawson is a joint venture project
located near Peace River, Alberta with a significant heavy oil resource in the
Bluesky formation.
Archon Technologies / Business Development
Archon Technologies Ltd. is a wholly-owned subsidiary of Petrobank. Archon
maintains a state of the art laboratory with highly qualified staff, all of whom
are committed to developing, evaluating and patenting new technologies
supporting and protecting the THAI(TM) and CAPRI(TM)technologies. Archon has
eight additional global patents or patents pending related to the THAI(TM)
process. In addition, successful bench scale testing of several new ground
breaking technologies at the lab has encouraged Archon to undertake design of
small scale field pilots at Conklin, Alberta. The technologies tested include
the use of a variation of enriched air injection schemes and conversion of H2S
to elemental sulphur through direct oxidation. This will also enhance the
Crystasulf(TM) technology. These technologies are expected to significantly
improve the economic benefits of THAI(TM) by increasing early stage oil
production rate and simplifying surface handling of H2S. The small scale field
pilots to confirm the merits of these new technologies are planned for the
winter of 2010/11. Additionally, Archon is currently constructing new bench
scale tests to evaluate the effectiveness of alternative sand control systems to
be used for future THAI(TM) projects. The field and lab tests will help further
improve the overall operational robustness and economics of THAI(TM) process.
Economic and environmental benefits of our innovative technology has continued
to generate strong world-wide interest in licensing initiatives. Our joint
venture strategy is to demonstrate and commercialize THAI(TM) and CAPRI(TM) in a
wide range of large global heavy oil resource opportunities. THAI(TM) has many
potential benefits over SAGD, including expected higher resource recovery
(70%-80% versus 30%-50% for SAGD), lower production and capital costs, minimal
usage of natural gas and fresh water, a partially upgraded crude oil product,
reduced diluent requirements for transportation, and lower greenhouse gas
emissions. The THAI(TM) process also has the potential to operate in lower
pressure, lower quality, thinner and deeper reservoirs than current steam-based
recovery processes. The continued field demonstration of THAI(TM) will have an
enormous impact on resource recovery and estimates of reserve volumes.
As we have previously reported, we are in final negotiations with a large
international energy company and progressing towards potential agreements with
others to license THAI(TM) and develop it in their heavy oil fields. These
negotiations are complex and require the integration of many business, legal and
financial aspects within our business model which leads to long negotiation
cycles.
EXECUTIVE APPOINTMENT
Petrobank is pleased to announce the appointment of Peter Cheung, CA as Vice
President, Finance and Chief Financial Officer effective August 14, 2010,
replacing Corey Ruttan who will continue to provide Petrobank with his guidance
and leadership as a member of the Board of Directors and as President and Chief
Executive Officer of Petrominerales.
Peter brings an extensive range of accounting, capital markets, financial
analysis and treasury experience to Petrobank. Most recently, Peter was
Treasurer at Compton Petroleum Corporation, after having founded an investment
management company. Previously, Peter was Vice President and Treasurer at
Pengrowth Energy Trust and Vice President at RBC Capital Markets Energy
Investment Banking. Peter's wide range of experiences will add to Petrobank's
innovative culture as we deliver results for our shareholders.
INVESTOR CONFERENCE CALL
Management of Petrobank will be holding a conference call for investors,
financial analysts, media and any interested persons on Friday, August 13, 2010
at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) to discuss Petrobank's
second quarter financial and operating results. The investor conference call
details are as follows:
Live call dial-in numbers: 416-340-8527 / 877-240-9772
Replay dial-in numbers: 416-695-5800 / 800-408-3053
Replay pass code: 1637151
The live audio webcast link is:
http://events.digitalmedia.telus.com/petrobank/081310/index.php and is also
available on our website at: http://www.petrobank.com/investors/.
CORPORATE PRESENTATIONS
The Petrobank, PetroBakken and Petrominerales corporate presentations have been
updated and can be found at www.petrobank.com, www.petrobakken.com, and
www.petrominerales.com.
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, operated by Petrobank's
58% owned TSX-listed subsidiary, PetroBakken Energy Ltd. (TSX:PBN), is a premier
light oil production company combining, high growth, long-life Bakken reserves
and production with legacy 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. The Latin American Business Unit,
operated by Petrobank's 66% owned TSX listed subsidiary, Petrominerales Ltd.
(TSX:PMG), is a Latin America-based exploration and production company producing
oil in Colombia with 17 exploration blocks covering a total of 2.1 million acres
in the Llanos and Putumayo Basins and five exploration blocks in Peru covering a
total of 9.4 million gross (5.2 million net) acres in the Ucayali and Titicaca
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. 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.
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 and operating netback. These
measures are commonly utilized in the oil and gas industry and are considered
informative for management and shareholders. Management considers operating
netback important as it is a measure of profitability per barrel of production.
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 operations to
cash flow from operating activities for the periods noted:
Three months ended June Six months ended June
30, 30,
2010 2009 2010 2009
---------------------------------------------------------------------------
Funds flow from operations:
Non-GAAP $ 334,592 $ 150,350 $ 668,546 $ 275,506
Changes in non-cash working
capital 45,221 (29,216) (71,065) (43,108)
---------------------------------------------------------------------------
Cash flow from operating
activities: GAAP $ 379,813 $ 121,134 $ 597,481 $ 232,398
---------------------------------------------------------------------------
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 from
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.
Barrels of Oil Equivalent: Disclosure provided in this press release in respect
of barrels of oil equivalent ("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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