PetroBakken Energy Ltd. ("PetroBakken" or the "Company") (TSX:PBN)
is pleased to announce the Company's 2012 year-end reserves and
provide an operational update.
Unless otherwise noted, all reserves herein are "Company
Interest" reserves, which represent the Company's working interest
and royalty interest share of reserves, before deduction of the
Company's royalty obligations. All values in this press release are
based on Sproule's forecast prices and estimates of future
operating and capital costs at December 31, 2012. The Company's
annual audit of our consolidated financial statements is not yet
complete and accordingly all financial amounts herein are
management's best estimates which are unaudited and subject to
change.
HIGHLIGHTS
-- Proved plus probable ("2P") reserves (before dispositions) grew by 10%
to 206.8 million barrels of oil equivalent ("MMboe") at December 31,
2012.
-- The 2012 capital program replaced 229% of 2012 production through the
addition of 35.8 MMboe of 2P reserves and achieved a recycle ratio of
1.8 times, based on our 2012 operating netback of $47.89.
-- The light oil and liquids weighting of our reserves is 82%.
-- In 2012, PetroBakken delivered finding, development and net acquisition
("FD&A") costs, including changes in future development capital ("FDC"),
of $11.45/boe for total proved reserves and $11.91/boe for 2P reserves.
-- 2012 acquisitions and divestitures resulted in the net disposition of
11.1 MMBoe total proved reserves and 16.9 MMBoe of 2P reserves, yielding
disposition metrics (including FDC) of $64.59/boe for total proved
reserves and $43.38/boe for 2P reserves.
-- Our F&D costs (including land purchases) were $26.83/boe for proved
reserve additions and $26.74/boe for 2P reserves.
-- Total FDC for our 2P reserves decreased by $94.6 million in 2012 to $1.8
billion, with FDC per well remaining largely unchanged year over year
across our resource plays. The ratio of proved developed to 2P reserves
increased year-over-year from 36% to 39% and the ratio of total proved
to 2P reserves increased from 59% to 64%.
-- Early stage success in our enhanced oil recovery ("EOR") initiatives
resulted in the initial booking of additional 2P reserves related to our
pilot natural gas flood in the Bakken.
-- Production in January 2013, based on field estimates, was approximately
49,700 barrels of oil equivalent per day ('boepd"). Currently, we have
48 (36 net) wells at various stages of completion waiting to be brought
on production.
-- Our current combined dividend reinvestment plan ("DRIP") and stock
dividend program ("SDP") participation is approximately 30%.
RESERVES
Sproule Associates Limited ("Sproule") has completed their
evaluation of PetroBakken's reserves, effective December 31, 2012
("Sproule Evaluation").
Year-end 2012 2P reserves grew 2% to 206.8 MMboe, with total
organic additions of 35.8 MMboe more than replacing our 16.9 MMboe
of non-core dispositions and 15.7 MMboe of production. Sproule's
net present value of our 2P reserves, discounted at 10%, is $4.0
billion before tax and $3.4 billion on an after tax basis. Our
operating recycle ratio for 2012 was 1.8 times based on an
operating netback of $47.89/boe. These results were driven
primarily by strong performance in the Cardium business unit and
continued maturation of our Bakken business unit.
We had an active program in 2012, drilling 217 net wells with a
98% success rate. Total net capital expenditures in 2012 were $320
million, with $928 million spent on exploration and development
activities (including approximately $75 million of our 2013 capital
that was accelerated into November and December of 2012) and $24
million on land, less net dispositions of $632 million. 2P F&D
costs were $26.74/boe (including FDC), representing an improvement
of 14% over 2011, primarily due to innovations in our drilling and
completion techniques in the Cardium and lower service costs. The
Company's three- year weighted average F&D cost, including land
and FDC, is $28.37/boe, generating an operating recycle ratio of
1.8 times.
2P reserves in the Cardium business unit increased from 72.2
MMboe in 2011 to 93.7 MMboe in 2012, representing a 30% increase
and replacing production by 461%. Our drilling activity led to
additions of 28.0 MMBoe. In 2012, FD&A costs for this business
unit were $18.42/boe, generating an operating recycle ratio of 2.6
times based on our operating netback for the business unit of
$47.76/boe. The Cardium business unit will continue to be a key
source of growth for PetroBakken, with a development drilling
inventory of over 580 net locations, of which 306 net locations
were included in the Sproule Evaluation.
2P reserve growth in the Bakken business unit (before
dispositions) was relatively flat for 2012, replacing approximately
107% of production. This moderation of growth is consistent with
our business plan of relatively stable production generating
positive free cash flow net of capital expenditures. Net reserve
additions in the Bakken business unit (before dispositions) were
7.0 MMboe, resulting in year-end 2P reserves of 78.7 MMboe. The
potential for future EOR-related reserve growth in the Bakken is
encouraging after receiving initial 2P reserve recognition for the
early stage success of our pilot natural gas flood. At year-end, we
had an inventory of over 900 net locations in the business unit, of
which 347 net locations were included in the Sproule
Evaluation.
Reserves
Forecast Prices(1)
As at December 31, 2012
Royalty
Interests Company
Company Gross(2) (3) Interest(4)
---------------------------------------------------------------
Total Natural
Oil NGL Gas Sub-total Sub-total Total
(Mbbl) (Mbbl) (MMcf) (Mboe) (Mboe) (Mboe)
----------------------------------------------------------------------------
Proved
Developed
Producing 61,448 4,766 86,388 80,611 698 81,309
Total Proved 99,185 7,503 143,694 130,637 722 131,359
Proved +
Probable
(2P) 157,156 11,860 219,988 205,681 1,077 206,758
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Net Present Value - Before Tax ($ millions)(5)(6)
Forecast Prices(1)
As at December 31, 2012
0% 5% 10%
----------------------------------------------------------------------------
Proved Developed Producing $ 3,528 $ 2,732 $ 2,258
Total Proved 4,919 3,573 2,792
Proved + Probable (2P) $ 8,186 $ 5,442 $ 4,014
----------------------------------------------------------------------------
Net Present Value - After Tax ($ millions)(5)(6)
Forecast Prices(1)
As at December 31, 2012
0% 5% 10%
----------------------------------------------------------------------------
Proved Developed Producing $ 3,254 $ 2,574 $ 2,160
Total Proved 4,287 3,177 2,521
Proved + Probable (2P) $ 6,700 $ 4,545 $ 3,404
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Company Interest Reserve Reconciliation (Mboe)(4)
Forecast Prices(1)
As at December 31, 2012
Developed Total Proved+
Producing Proved Probable
----------------------------------------------------------------------------
PetroBakken reserves at December 31, 2011 74,110 119,867 203,464
2012 production (15,659) (15,659) (15,659)
Net dispositions (7,693) (11,061) (16,882)
Net additions and revisions 30,551 38,212 35,835
---------------------------------
PetroBakken reserves at December 31, 2012 81,309 131,359 206,758
PetroBakken year-over-year increase in
reserves 10% 10% 2%
PetroBakken production replacement (7) (8) 195% 244% 229%
----------------------------------------------------------------------------
Notes:
(1) Based on the Sproule price forecast effective December 31, 2012.
(2) Company Gross reserves, which represent the Company's working interest
share of reserves excluding the Company's royalty interests in reserves
and before deduction of royalty obligations.
(3) Royalty interest reserves owned by the Company.
(4) "Company Interest" reserves, which represent the Company's working
interest share of reserves including the Company's royalty interests in
reserves and before deduction of the Company's royalty obligations.
(5) Company working interest reserves value plus royalties received less
royalties and burdens.
(6) Estimated values of future net revenue disclosed in this press release
do not represent fair market values.
(7) Represents total reserve additions, including revisions and before
dispositions, as a percentage of 2012 production.
(8) The disclosures required in accordance with National Instrument 51-101
of the Canadian Securities Administrators will be available in the
Company's Annual Information Form to be filed on the SEDAR website at
http://www.sedar.com/ prior to March 31, 2013.
F&D and FD&A Costs(1)
For the year ended December 31, 2012
Acquisitions
F&D & FD&A(3)
Dispositions
----------------------------------------------------------------------------
Capital expenditures (unaudited-
$000s)
Capital expenditures $ 952,556 $ - $ 952,556
Acquisition/(Disposition)
capital - (632,173) (632,173)
-------------------------------------------
Total capital 952,556 (632,173) 320,383
Less: Land value 24,323 - 24,323
-------------------------------------------
Total capital excluding land
value $ 928,233 $ (632,173) $ 296,060
Change in FDC ($000s)
Total Proved $ 72,620 $ (82,252) $ (9,632)
Proved + Probable (2P) $ 5,545 $ (100,109) $ (94,564)
----------------------------------------------------------------------------
Total costs ($000s)
Total Proved $ 1,025,176 $ (714,425) $ 310,752
Proved + Probable (2P) $ 958,101 $ (732,282) $ 225,819
Net reserve additions (mboe)
Total Proved 38,212 (11,061) 27,151
Proved + Probable (2P) 35,835 (16,882) 18,953
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F&D and FD&A costs ($/boe)
(including land)
Total Proved $ 26.83 $ (64.59) $ 11.45
Proved + Probable (2P) 26.74 (43.38) 11.91
FD&A costs ($/boe) (excluding
land)
Total Proved 26.19 (64.59) 10.55
Proved + Probable (2P) $ 26.06 $ (43.38) $ 10.63
----------------------------------------------------------------------------
For the year-ended Dec. 31, 2011
F&D and FD&A costs ($/boe)
(including land)
Total Proved $ 40.20 $ (76.28) $ 39.43
Proved + Probable (2P) 31.22 (55.73) 30.74
F&D and FD&A costs ($/boe)
(excluding land)
Total Proved 39.14 (76.28) 38.35
Proved + Probable (2P) $ 30.51 $ (55.73) $ 30.01
For the 3 years-ended Dec. 31,
2012(2)
F&D and FD&A costs ($/boe)
(including land)
Total Proved $ 33.98 $ (11.65) $ 35.63
Proved + Probable (2P) 28.37 (5.64) 30.71
F&D and FD&A costs ($/boe)
(excluding land)
Total Proved 32.33 (66.70) 29.79
Proved + Probable (2P) $ 27.08 $ (37.66) $ 25.99
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(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserve additions for that year.
(2) FD&A costs for 2010 include the corporate acquisitions of Berens Energy
Ltd., Rondo Petroleum Inc., Result Energy Inc. and certain other asset
acquisitions. For corporate acquisitions, acquisition costs represent
the portion of the purchase prices allocated to property, plant &
equipment and reflect the net present value of each corporate
acquisition as at its acquisition date based on 2P NPV10%, before tax.
(3) The Company uses FD&A as a measure of the efficiency of its overall
capital program including the effect of acquisitions and dispositions.
(4) Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 1 boe for 6 thousand cubic feet of natural gas is
based on an energy equivalency conversion method primarily applicable at
the burner tip and does not represent a value equivalency at the
wellhead.
OPERATIONAL UPDATE
Production in January 2013, based on field estimates, was
approximately 49,700 boepd (83% light oil and liquids), up from our
fourth quarter 2012 average production of 47,192 boepd. In January,
our Bakken business unit produced approximately 19,800 boepd and
our Cardium business unit produced approximately 20,800 boepd, with
the remainder of the production generated by our southeast
Saskatchewan Conventional and AB/BC business units. During the
month of January, production was negatively impacted by
approximately 600 boepd due to restrictions at third-party
facilities in the Cardium.
Currently we have 13 rigs operating in the field, with 6 in the
Cardium, 4 in the Bakken, 1 in Southeast Saskatchewan, 1 in Swan
Hills and 1 in a new play area. Drilling activity year to date has
resulted in 39 (30 net) wells drilled, comprised of 13 (11 net) in
the Bakken, 12 (10 net) in the Cardium, 9 (5 net) in our
Saskatchewan Conventional business unit and 5 (4 net) on our
emerging plays. Currently, we have 48 (36 net) wells at various
stages of completion waiting to be brought on production.
With our active program at the end of 2012 generating strong
production growth leading into year-end, we anticipate a base
production profile that will have steeper declines in the first
part of this year, followed by lower declines in the later part of
the year. We have forecasted an average production decline rate
from December 2012 to December 2013 of 39%. On a quarterly basis,
our base production decline from fourth quarter 2012 to fourth
quarter 2013 is expected to be 31%, normalizing the impacts of our
strong production additions during December 2012. We now forecast
2014 base declines to range from 28% to 33%.
Our 2013 capital expenditure plan of $675 million is more
balanced throughout the year, which will help us reduce production
volatility and manage declines while delivering anticipated
year-over-year average production growth of 8% to 12%.
REALIZED PRICES AND COMMODITY DIFFERENTIALS
North America is currently experiencing infrastructure
challenges resulting from growth in domestic production of oil and
gas due to the development of oil sands assets and the application
of horizontal multi-stage fracturing technology. The impact has
been felt across the continent through lower realized oil and gas
prices, with WTI prices trading at a discount to Brent pricing and
North American natural gas trading well below world prices. To
compound the problem, increased production from Western Canada and
the mid-western United States has resulted in additional discounts
for crude produced in Canada. The biggest impact has been on the
price other producers receive for heavy crudes, where discounts of
25% to 35% of WTI have been experienced. The current differential
for our light oil production is approximately 7% off WTI, allowing
us to benefit from realized pricing that is more favourable than
our internal 2013 forecast of US$90/bbl WTI with a 10%
differential.
Consistent with the rest of our industry, commodity price
volatility will impact our results and we will continue to take
steps to mitigate commodity price risks and attempt to optimize our
rates of return.
DIVIDEND REINVESTMENT PROGRAM AND SHARE DIVIDEND PLAN
PetroBakken has a DRIP in place that is available only to
Canadian PetroBakken shareholders. Our SDP is now available to both
Canadian shareholders and most non-Canadian shareholders. The DRIP
and the SDP allow shareholders to effectively receive their monthly
PetroBakken dividends as PetroBakken shares at a 5% discount to the
market price at the date of the dividend payment. Current combined
DRIP and SDP participation is approximately 30%.
For further information regarding our SDP and DRIP, please visit
PetroBakken's website at www.petrobakken.com or contact Olympia
Trust Company at 403-668-8887, toll free at 1-800-727-4493 or via
email at corporateactions@olympiatrust.com.
PetroBakken Energy Ltd. 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. Our
strategy is to deliver accretive production and reserves growth,
along with an attractive dividend yield.
Forward-Looking Statements
This press release contains forward-looking statements. More
particularly, it contains forward-looking statements concerning
2013 production rates, potential exploration and development
activities, our 2013 capital budget, potential drilling locations,
timing for bringing restricted production on-stream and the future
potential of enhanced oil recovery projects. The forward- looking
statements are based on certain key expectations and assumptions,
including expectations and assumptions concerning the availability
of capital, the success of future drilling, completion,
recompletion and development activities, the performance of
existing wells, the performance of new wells, prevailing commodity
prices and economic conditions, the cost and availability of labour
and services, the ability to market our production, weather and
access to drilling locations.
Although we believe that the expectations and assumptions on
which the forward-looking statements are based are reasonable,
undue reliance should not be placed on the forward-looking
statements because we can give no assurance that they will prove to
be correct. Since forward-looking statements address future events
and conditions, by their very nature they involve inherent risks
and uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and risks.
These include, but are not limited to, risks associated with the
oil and gas industry in general (e.g., operational risks in
development, exploration and production; delays or changes in plans
with respect to exploration or development projects or capital
expenditures; the uncertainty of reserve estimates; the uncertainty
of estimates and projections relating to production, costs and
expenses; reliance on industry partners, availability of equipment
and personnel, uncertainty surrounding timing for drilling and
completion activities resulting from weather and other factors;
changes in applicable regulatory regimes and health, safety and
environmental risks), commodity price and exchange rate
fluctuations and general economic conditions. Certain of these
risks are set out in more detail in our Annual Information Form
which has been filed on SEDAR and can be accessed at www.sedar.com.
There is no representation by PetroBakken 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, PetroBakken 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.
Caution Respecting BOE
When used in this press release, Boe means a barrel of oil
equivalent on the basis of 1 Boe to 6 thousand cubic feet of
natural gas. Boe per day means a barrel of oil equivalent per day.
Boe's may be misleading, particularly if used in isolation . A Boe
conversion ratio of 1 Boe for 6 thousand cubic feet of natural gas
is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead. Given that the value ratio of oil
compared to natural gas based on currently prevailing prices is
significantly different than the energy equivalency conversion
ratio of 6 Mcf to 1 BOE, utilizing a conversion ratio of 6 Mcf to 1
BOE may be misleading as an indication of value.
Contacts: PetroBakken Energy Ltd. John D. Wright President and
Chief Executive Officer (403) 268.7800 PetroBakken Energy Ltd.
Peter D. Scott Senior Vice President and Chief Financial Officer
(403) 268.7800 PetroBakken Energy Ltd. Bill A. Kanters Vice
President Capital Markets (403) 268.7800 www.petrobakken.com