- Published: 07 March 2012
- Written by Editor
PetroBakken Announces Record Fourth Quarter Production of 48,007 boepd and Record Quarterly Funds Flow From Operations of $231 Million
PetroBakken Energy Ltd. (the "Company" or "PetroBakken") (TSX:PBN.TO - News) is pleased to announce our fourth quarter and year-end 2011 financial and operating results.
FINANCIAL & OPERATING HIGHLIGHTS
(In this press release, annual comparisons are 2011 compared to 2010 and quarterly comparisons are fourth quarter 2011 compared to fourth quarter 2010 unless otherwise noted.)
-- December 2011 production averaged 50,250 barrels of oil equivalent per day ("boepd"), exceeding our exit production guidance estimates and setting a new corporate benchmark. This is an 18% increase over December 2010.
-- Fourth quarter production was 48,007 boepd (87% light oil and liquids
weighted), a 23% increase over the third quarter of 2011.
-- Our operating netback for the fourth quarter was $59.21/boe, an 18%
increase over the third quarter of 2011.
-- Record fourth quarter funds flow from operations was $231 million ($1.24
per basic share), a 52% increase over the third quarter of 2011.
-- Proved plus probable ("2P") reserves increased by 19% to 203.5 million
barrels of oil equivalent ("MMboe") at December 31, 2011, replacing 2011
production by 315%.
-- Net capital expenditures totaled $909 million in 2011, with 88% of the
program invested in drilling and completions. 293 (205 net) wells were
drilled in 2011 with a 99% success rate.
-- In late 2011, and early 2012, we implemented a number of initiatives
which further improves our liquidity, with available credit capacity
rising to more than $1.1 billion following the completion of our non-
core Bakken asset disposition in mid-March.
Summary of Results
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Three months ended Year ended
December 31, December 31,
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2011 2010 2011 2010
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Oil and natural gas revenue 366,881 258,359 1,195,476 1,008,556
Funds flow from operations
(1) 231,428 160,817 710,162 646,316
Per share - basic ($) 1.24 0.85 3.79 3.51
Adjusted Net income(1) 76,849 40,401 215,787 150,623
Per share - basic ($) 0.41 0.21 1.15 0.82
Net Capital Expenditures(1) 239,481 259,187 909,169 678,239
Net debt (1) 1,390,563 1,015,774 1,390,563 1,015,774
Dividends per share ($) 0.24 0.24 0.96 0.96
Common Shares, end of period
(000) (2) 187,342 187,140 187,342 187,140
Operating netback ($/boe)
(1) (3) (4) 59.21 48.19 54.76 47.76
Average daily production (3)
(boe) 48,007 41,333 40,998 41,688
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(1) Non-GAAP measure. See "Non-GAAP Measures" section.
(2) Denotes basic common shares outstanding.
(3) Six Mcf (thousand cubic feet) of natural gas is equivalent to one
barrel of oil equivalent ("boe").
(4) Net of transportation expenses.
OPERATING RESULTS
Early in the year we faced a prolonged spring break-up due to extreme weather conditions, particularly in southeast Saskatchewan, which resulted in shut-in production, delayed operations and higher operating costs in the second and third quarters. However, during the later part of the third and fourth quarters we were able to restore shut-in production and continually execute our drilling program, allowing us to successfully drill, complete, and equip all the wells in the 2011 plan, including those that were previously delayed.
Q4 2011 Drilling Activity
Drilled Completed On Production Inventory(1)
Business Unit Gross Net Gross Net Gross Net Gross Net
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Bakken 23 15.8 43 31.0 41 28.5 1 0.3
Conventional (SE SK) 21 11.8 27 15.0 29 14.6 7 3.1
Cardium (central AB) 34 22.3 38 25.7 57 39.6 15 8.0
Alberta/BC 4 4.0 2 2.0 2 2.0 4 4.0
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Total 82 53.9 110 73.7 129 84.7 27 15.4
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(1) Inventory refers to the number of wells pending completion and/or tie-
in.
We drilled 54 net wells and brought another 85 net wells on production in the fourth quarter. Production in the fourth quarter of 2011 averaged 48,007 boepd, representing a 23% increase over the third quarter, and a 16% increase from the fourth quarter of the prior year. With reduced drilling times, utilization of additional rigs and optimization of production, we achieved a monthly production record in December 2011 of 50,250 boepd.
Our average production rate in 2011 was 40,998 boepd, essentially unchanged from 2010, largely due to prolonged weather related challenges in the second and third quarters. Total production for the year was 86% light oil and liquids weighted.
Average Daily Production
Three months ended Year ended
December 31, December 31,
Oil & Oil &
NGL Gas Total NGL Gas Total
Business Unit (bbl/d) (Mcf/d) (boe/d) (bbl/d) (Mcf/d) (boe/d)
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Bakken 21,441 6,882 22,588 19,456 6,223 20,493
Conventional (SE SK) 6,351 1,567 6,612 5,691 1,441 5,931
Cardium (central AB) 12,771 15,643 15,378 8,900 13,792 11,199
Alberta/BC 1,097 13,991 3,429 1,109 13,596 3,375
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41,660 38,083 48,007 35,156 35,052 40,998
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Bakken Business Unit Update
In 2011, operations in the Bakken generated free cash flow as we continued to develop this resource play. We drilled 101 (74 net) wells in the Bakken business unit, of which 47 net were bilateral wells, and achieved a 99% success rate. Our average production in the fourth quarter was 22,588 boepd. The Bakken business unit grew 2P reserves by 7% to 88.5 MMboe as of December 31, 2011, replacing 173% of 2011 production. While our operating costs were negatively impacted by weather in the second and third quarters, they were reduced to $9.11/boe in the fourth quarter, resulting in netbacks of $62.42/boe for the quarter. The business unit generated free cash flow of $130 million in 2011 (after all capital expenditures). We also continued to advance our enhanced oil recovery ("EOR") efforts through the initiation of five EOR projects in the Bakken that are currently at various stages of implementation. Early indications suggest the technology has the potential to increase recovery rates and further attenuate decline rates.
Cardium Business Unit Update
After accumulating substantial land holdings in central Alberta for Cardium formation rights in 2010, the focus of our Cardium business unit in 2011 was the development of these assets. Through a targeted capital program, production more than doubled through the year to average 15,378 boepd in the fourth quarter of 2011, with additional production behind pipe and awaiting tie-in to conserve solution gas. In 2011, we drilled 134 (96 net) wells in the Cardium business unit and increased 2P reserves by 66% to 72.2 MMboe, replacing 2011 production by 800%. The area will continue to be a key source of growth for us with a development drilling inventory of over 650 net locations, of which only 232 net locations have been booked in our year-end 2011 independent reserves report. We will continue to refine our drilling and completion methodologies as we constantly strive to increase production rates and lower costs.
Other Activity
The remainder of our 2011 production came from our southeast Saskatchewan Conventional business unit and our Alberta/BC business unit.
Our southeast Saskatchewan Conventional business unit continued to provide strong individual well economics, and generated free annual cash flow in 2011 of over $40 million (after all capital expenditures). In 2011, we drilled 29 net wells in the area. In the third quarter of 2011, we also completed a facility upgrade improving our water handling and disposal to manage increased water production from our well optimizations. Our improved capacity provided an additional 425 boepd of production from existing wells and also allowed an opportunity for increased drilling activity in both our Bakken and conventional Mississippian plays. We anticipate that further additions to infrastructure in 2012 will continue to increase productive capacity.
In our Alberta/BC business unit, we have assembled over 120,000 net acres in four potential new oil resource plays. Four horizontal test wells were drilled in the second half of 2011 to evaluate the potential of the Nordegg, Montney and Duvernay formations. All of these wells have indicated the presence of light oil. We will commence testing our Swan Hills play in the second half of 2012. In northeast British Columbia, we continue to maintain our land position but, given current natural gas prices, we have no short term growth or development plans in this area.
FINANCIAL RESULTS
Our production and operating netbacks resulted in funds flow from operations of $710 million ($3.79 per basic share) for 2011, a 10% increase over 2010. Fourth quarter funds flow from operations were $231 million ($1.24 per basic share), representing an increase of 44% over 2010 due to higher production and oil prices. 2011 net income was $209 million ($1.12 per basic share), a slight decrease compared to 2010 primarily due to increased cost pressures and production timing delays related to poor weather conditions, and a $50 million impairment charge. The impairment charge was caused by low natural gas prices and a lack of development activity in our northeast British Columbia natural gas assets.
Net capital expenditures totaled $909 million in 2011, an increase of 34% from 2010. The increase in capital expenditures year over year was primarily a result of increased drilling and completion activity in the Cardium business unit and higher service costs. Company-wide drilling and completion costs were $802 million, representing 88% of our total net capital expenditures in 2011.
In 2011, we paid $180 million in dividends compared to $177 million in 2010, having maintained a monthly dividend of $0.08 per share since the Company's inception.
BALANCE SHEET MANAGEMENT
Since the end of the third quarter of 2011, and continuing into early 2012, we have executed on a number of initiatives to increase our liquidity and capitalize on the value of our assets.
-- In December 2011, we announced a Dividend Reinvestment Plan ("DRIP")
that provides shareholders the opportunity to reinvest dividends in new
shares at a five percent discount to market. The DRIP was implemented
for the January 2012 dividend; payable in February. At the end of
February, 35% of issued shares had subscribed to participate in the
plan, which would reduce our cash outlay by over $60 million on an
annual basis.
-- On January 30, 2012, we completed a private placement of US$900 million
of senior unsecured notes ("Notes"). The Notes bear interest at a rate
of 8.625% per annum and mature on February 1, 2020. A portion of the
proceeds were used to repurchase US$450 million of our convertible
debentures at a price of US$99,000 per US$100,000 of principal amount,
with the remaining proceeds, net of fees, applied against our credit
facility.
-- In conjunction with the Notes issuance, we exercised the accordion
feature on our credit facility, which increased the borrowing limit by
$150 million to $1.5 billion on January 31, 2012.
-- On February 24, 2012, we completed the disposition of a minor working
interest in the Weyburn Unit, for gross proceeds of $105 million,
representing sales metrics of $25.85/boe (including 2P future
development capital ("FDC") of $32 million) and $180,000/boepd.
-- On February 16, 2012 we announced the disposition of approximately 2,900
boepd of non-core Southeast Saskatchewan Bakken assets for gross
proceeds of $427 million, representing sales metrics of $47.13/boe
(including 2P FDC of $67 million) and $147,250/boepd. This transaction
is expected to close by mid-March 2012.
Following the completion of these initiatives, we expect to have at least $1.1 billion of available liquidity, from diversified sources of credit with a layered maturity profile that better compliments the long term nature of our light oil focused assets. Our $1.5 billion revolving credit facility expires in 2014, and we anticipate having approximately $300 million drawn following the close of our non-core Bakken asset sale (our lending limit may be reduced by a maximum of $100 million to account for this asset sale, subject to review of our year-end reserves). In addition, we have US$300 million of convertible debentures that are due in 2016 (holders have a one day put right in February 2013 and we can elect to settle any exercised debenture with either cash or shares) and US$900 million of high yield debt that matures in 2020.
SUMMARY, OUTLOOK & REVISED CAPITAL PLAN
In 2011, we demonstrated our ability to execute and deliver results in the face of challenging operating conditions. Although the industry experienced unprecedented weather events and increased service costs, we were able to accelerate on and complete our 2011 program in the second half, resulting in a successful year where we achieved record funds flow from operations in the fourth quarter, exceeded our exit rate production guidance and grew our 2P reserves by 19% year over year.
Mid-February production, based on field estimates prior to dispositions, was in excess of 49,000 boepd, up from our fourth quarter 2011 average production of approximately 48,000 boepd. Our Bakken business unit is currently producing in excess of 21,250 boepd (prior to the pending non-core asset disposition), and our Cardium business unit production exceeds 17,750 boepd, with the remainder of the production generated by our southeast Saskatchewan Conventional and AB/BC business units.
Since the end of the fourth quarter we have drilled an additional 48 (33 net) wells, completed 55 (44 net) wells, and brought 28 (19 net) wells on production. We currently have 11 rigs operating, with six in southeast Saskatchewan and five in the Cardium.
The 2012 capital plan is focused on the continued exploitation of our southeast Saskatchewan Bakken and conventional Mississippian assets, the development of our Cardium light oil properties in central Alberta and the continued exploration and development of our Alberta properties to leverage our significant undeveloped land base into new resource opportunities. Our 2012 capital plan is being updated as a result of the two asset dispositions and we plan to use a portion of the sales proceeds to increase our capital program by $175 million. The majority of the additional capital spending will be directed toward the Cardium play and, as a result of the increased capital expenditures we now expect 2012 exit production rates of between 52,000 boepd and 56,000 boepd.
FOURTH QUARTER AND YEAR-END FINANCIAL & OPERATING TABLES
The following table provides a summary of PetroBakken's financial and operating results for the three and twelve month periods ended December 31, 2011 and 2010. Consolidated financial statements with Management's Discussion and Analysis ("MD&A") is available on the Company's website at www.petrobakken.com and will be available on the SEDAR website at www.sedar.com.
Three months ended Year ended
December 31, December 31,
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% %
2011 2010 change 2011 2010 change
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Financial ($000s,
except where noted)
Oil and natural gas
revenue 366,881 258,359 42 1,195,476 1,008,556 19
Funds flow from
operations (1) 231,428 160,817 44 710,162 646,316 10
Per share - basic
($) 1.24 0.85 47 3.79 3.51 8
- diluted
($)(2) 1.13 0.80 41 3.49 3.27 7
Adjusted Net
income(1) 76,849 40,401 90 215,787 150,623 43
Per share - basic
($) 0.41 0.21 95 1.15 0.82 40
- diluted
($) 0.41 0.21 95 1.14 0.81 41
Net Capital
expenditures(1) 239,481 259,187 (8) 909,169 678,239 34
Total assets 6,477,282 5,865,005 10 6,477,282 5,865,005 10
Net debt (1) 1,390,563 1,015,774 37 1,390,563 1,015,774 37
Total debt(1) 2,153,313 1,761,724 22 2,153,313 1,761,724 22
Dividends 44,999 45,076 - 179,691 177,205 1
Per share ($) 0.24 0.24 - 0.96 0.96 -
Payout ratio(1) 19% 28% - 25% 28% -
Common shares, end
of period (000)
Basic 187,342 187,140 - 187,342 187,140 -
Diluted(2) 220,823 215,011 3 220,823 215,011 3
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Operations
Operating netback
($/boe except where
noted) (1) (3)
Oil and NGL revenue
($/bbl) (4) 92.13 75.19 23 88.65 72.77 22
Natural gas revenue
($/Mcf) (4) 3.44 3.96 (13) 3.92 4.22 7
Oil, NGL and
natural gas revenue
(4) 82.69 67.00 23 79.38 65.28 22
Royalties 12.51 9.84 27 12.41 9.34 33
Production expenses 10.97 8.97 22 12.21 8.18 49
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Operating netback 59.21 48.19 23 54.76 47.76 15
Average daily
production (3)
Oil and NGL (bbls) 41,660 34,754 20 35,156 35,109 -
Natural gas (Mcf) 38,083 39,474 (4) 35,052 39,473 (11)
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Total (boe) 48,007 41,333 16 40,998 41,688 (2)
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(1) Non-GAAP measure. See "Non-GAAP Measures" section.
(2) Consists of common shares, stock options, deferred common shares, and
incentive shares on the same basis as net income. Convertible
debentures have been included as at the period end date based on the
conversion price as of that date.
(3) Six Mcf (thousand cubic feet) of natural gas is equivalent to one
barrel of oil equivalent ("boe").
(4) Net of transportation expenses.
INVESTOR CONFERENCE CALL
Management of PetroBakken will be holding a conference call for investors, financial analysts, media and any interested persons on Wednesday, March 7, 2011 at 9:00 a.m. (MST) (11:00 a.m. EST) to discuss PetroBakken fourth quarter and year-end financial and operating results.
The investor conference call details are as follows:
Live call dial-in numbers: 416-340-8530 / 877-240-9772
Replay dial-in numbers: 905-694-9451 / 800-408-3053
Replay pass code: 4838524
The live audio webcast link will be available at: http://events.digitalmedia.telus.com/petrobakken/030712/index.php.
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.
Non-GAAP Measures. This press release contains financial terms that are not considered measures under IFRS, such as funds flow from operations, adjusted net income, funds flow per share, adjusted net income per share, payout ratio, net debt, total debt, operating netback and net capital expenditures. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, funds flow from operations reflects cash generated from operating activities before changes in non-cash working capital. Adjusted net income is determined by adding back any losses or deducting any gains on the derivative liabilities and adding back impairments. Payout ratio is determined as dividends paid as a percentage of funds flow from operations. Management considers funds flow from operations, funds flow per share, adjusted net income, adjusted net income per share, and payout ratio important as it helps evaluate performance and demonstrate the ability to generate sufficient cash to fund future growth opportunities, pay dividends and repay debt. Net debt includes bank debt outstanding plus accounts payable less accounts receivable and prepaid expenses. Total debt includes net debt plus the full value outstanding on the convertible debentures converted to Canadian dollars at the exchange rate on the period end date. Net debt and total debt are used to evaluate PetroBakken's financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Operating netback reflects revenues less royalties, transportation costs, and production expenses divided by production for the period. Net capital expenditures represent capital expenditures, including exploration and evaluation expenditures, less proceeds from asset dispositions. Funds flow from operations, funds flow per share, adjusted net income, adjusted net income per share, payout ratio, net debt, total debt, operating netbacks, and net capital expenditures may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations or other measures of financial performance calculated in accordance with IFRS. Further information in respect of these non-GAAP measures is set forth in our MD&A.
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, future production rates, proposed exploration and development activities, the potential for EOR projects, our drilling prospect inventory, the timing of certain projects and the proposed sale of non-core Bakken assets and the timing and use of proceeds thereof (the "Asset Sale") and our future debt levels and liquidity position. 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 new and existing wells, prevailing commodity prices and economic conditions, the availability of labour and services, weather and access to drilling locations, the geological nature of the formations targeted and the ability of the parties to the Asset Sale to satisfy the conditions to the transaction and complete the sale. 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, general economic conditions and risks that the proposed Asset Sale is not completed as a result of a failure to satisfy one of the conditions to the sale. 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. 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.
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.
Contact:
John D. Wright
PetroBakken Energy Ltd.
President and Chief Executive Officer
(403) 268-7800
Peter D. Scott
PetroBakken Energy Ltd.
Senior Vice President and Chief Financial Officer
(403) 268-7800
R. Gregg Smith
PetroBakken Energy Ltd.
Senior Vice President and Chief Operating Officer
(403) 268-7800
Bill A. Kanters
PetroBakken Energy Ltd.
Vice President Capital Markets
(403) 268-7800
Eighth Avenue Place, 2800, 525 - 8th Avenue S.W.
PetroBakken Energy Ltd.
Calgary, Alberta, T2P 1G1
(403) 268-7800
(403) 218-6075 (FAX)
This email address is being protected from spambots. You need JavaScript enabled to view it.
www.petrobakken.com
