- Published: 09 November 2011
- Written by Editor
PetroBakken Announces Third Quarter 2011 Results, Current Production in Excess of 47,500 Boepd, and Revision to Exit Guidance
PetroBakken Energy Ltd. ("PetroBakken" or the "Company") (Toronto:PBN.TO), a 59% owned subsidiary of Petrobank Energy and Resources Ltd. (TSX:PBG), is pleased to announce third quarter 2011 financial and operating results and current production in excess of 47,500 boepd (based on field estimates). PetroBakken third quarter 2011 financial and operating results were highlighted by funds flow from operations of $152.4 million ($0.81 per basic share and $0.76 per diluted share), a top decile operating netback of $50.04 per barrel of oil equivalent ("boe") and average production of 39,074 barrels of oil equivalent per day ("boepd") (85% light oil and NGLs).
Third quarter production was significantly impacted by shut-in wells and wet weather which delayed field operations. Since the end of July, production has consistently increased and October production averaged more than 46,000 boepd. Improved weather conditions have allowed us to accelerate our drilling schedule and, with 11 drilling rigs now operating, it is anticipated that an additional 25 net wells will be drilled in the remainder of 2011. With an additional 52 net wells expected to be brought on stream by year-end, we now forecast 2011 exit production rates in excess of 49,000 boepd. FINANCIAL & OPERATING RESULTS The following table provides a summary of PetroBakken's financial and operating results for the three and nine months ended September 30, 2011 and 2010. Interim consolidated financial statements with Management's Discussion and Analysis ("MD&A") are available on the Company's website at www.petrobakken.com and will also be available on the SEDAR website at www.sedar.com.
Three months ended Nine months ended
September 30, September 30,
2011 2010 % change 2011 2010 % change
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Financial
($000s, except
where noted)
Oil and natural
gas sales 272,346 228,537 19 828,595 750,197 10
Funds flow from
operations (1) 152,357 140,761 8 478,734 485,499 (1)
Per share -
basic ($) 0.81 0.75 8 2.56 2.65 (3)
- diluted
($)(2) 0.76 0.71 7 2.36 2.47 (4)
Adjusted Net
income (1) (3) 29,671 36,063 (18) 138,938 110,222 26
Per share -
basic ($) 0.16 0.19 (16) 0.74 0.60 23
- diluted
($)(2) 0.16 0.19 (16) 0.73 0.60 22
Net capital
expenditures(1
) 271,786 233,003 17 669,688 419,052 60
Total assets 6,346,447 5,677,921 12 6,346,447 5,677,921 12
Net debt (1) 1,338,425 858,375 56 1,338,425 858,375 56
Dividends 44,880 45,177 (1) 134,692 132,129 2
Per Share ($) 0.24 0.24 - 0.72 0.72 -
Common shares,
end of period
(000)
Basic 187,237 187,675 - 187,237 187,675 -
Diluted (2) 220,261 215,137 2 220,261 215,137 2
Three months ended Nine months ended September
September 30, 30,
2011 2010 % change 2011 2010 % change
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Operations
Operating netback
($/boe except where
noted) (1) (4)
Oil and NGL
revenue ($/bbl)
(5) 84.61 68.43 24 87.17 71.97 21
Natural gas
revenue ($/Mcf)
(5) 4.01 3.82 5 4.11 4.31 (5)
Oil, NGL and
natural gas
revenue(5) 75.37 60.63 24 77.98 64.71 21
Royalties 12.20 8.64 41 12.36 9.17 35
Production
expenses 13.13 8.38 57 12.73 7.92 61
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Operating netback
(6) 50.04 43.61 15 52.89 47.62 11
Average daily
production (4)
Oil and NGL (bbls) 33,112 33,230 - 32,965 35,229 (6)
Natural gas (Mcf) 35,776 41,193 (13) 34,030 39,473 (14)
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Total (boe) 39,074 40,095 (3) 38,636 41,808 (8)
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(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) Net income has been adjusted for the IFRS accounting effects of the gain/loss on derivative financial liability. For the three months ended September 30, 2011, adjusted net income includes a $10.6 million reduction (2010 - $24.9 million increase) for this gain. For the nine months ended September 30, 2011, adjusted net income includes a $71.7 million reduction (2010 - $69.3 million reduction). Management considers adjusted net income a better measure of the Company's economic performance period over period. (4) Six Mcf of natural gas is equivalent to one barrel of oil equivalent ("boe"). (5) Net of transportation expenses. (6) Excludes hedging activities. HIGHLIGHTS (In this report, quarterly comparisons are third quarter 2011 to third quarter 2010 unless otherwise noted.)
-- PetroBakken's production averaged 39,074 boepd in the third quarter of
2011, representing an 11% increase compared to the second quarter of
2011, and a 3% decrease from the prior year period. The increase in
production over the second quarter was the result of a combination of
restoring production that was shut-in due to the extended spring break-
up and production additions from new wells that were put on production
in the latter part of the third quarter.
-- Our operating netback (excluding hedging activities) of $50.04/boe
decreased 12% compared to the second quarter of 2011, and increased 15%
over the prior year period. The decrease over the second quarter was
primarily as a result of lower pricing that more than offset decreased
royalty and production expenses.
-- Our production and strong operating netback resulted in funds flow from
operations of $152.4 million ($0.81 per basic share and $0.76 per
diluted share), a 1% decrease from the second quarter of 2011, and an 8%
increase from the prior year. The decrease from the second quarter was
primarily due to lower operating netbacks partially offset by higher
production.
-- Net capital expenditures were $271.8 million in the third quarter, up
196% from the second quarter of 2011, and up 17% from a year ago. The
increase from the prior quarter was due to the seasonal nature of
expenditures in our core operating areas, and we remain on budget for
2011.
-- PetroBakken drilled 96 (70.1 net) wells with a 100% success rate in the
third quarter: 44 (31.5 net) wells were drilled in the Cardium, 33 (25.4
net) in the Bakken, 18 (12.2 net) in Saskatchewan Conventional, and 1
(1.0 net) in Alberta/BC.
-- We brought 60 (47.3 net) wells on production in the quarter: 23 (18.7
net) wells in the Cardium, 27 (20.6 net) wells in the Bakken, with the
remaining wells in our Saskatchewan Conventional Business Unit.
OPERATIONAL UPDATE
Average Daily Production
Three months ended Three months ended
September 30, 2011 June 30, 2011
Oil &NGL Gas Total Oil &NGL Gas Total
Business Unit (bbl/d) (Mcf/d) (boe/d) (bbl/d) (Mcf/d) (boe/d)
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Bakken 17,701 5,973 18,697 16,385 5,641 17,325
Conventional
(SE SK) 5,274 1,362 5,501 5,093 1,304 5,310
Cardium
(central AB) 9,004 13,628 11,275 7,040 13,715 9,326
Alberta/BC 1,133 14,811 3,601 1,158 13,086 3,339
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33,112 35,774 39,074 29,676 33,746 35,300
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Average Daily Production
Three months ended
March 31, 2011
Oil &NGL Gas Total
Business Unit (bbl/d) (Mcf/d) (boe/d)
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Bakken 22,327 6,392 23,392
Conventional
(SE SK) 6,046 1,531 6,301
Cardium
(central AB) 6,718 12,148 8,743
Alberta/BC 1,049 12,463 3,126
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36,140 32,534 41,562
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Field operations in Q3 got off to a slow start as weather related challenges that existed in Q2 persisted into July. However, drilling activity commenced where possible and production that had been shut-in due to wet lease conditions was gradually restored. Our field activities were heavily weighted towards the latter part of the quarter, resulting in low average production volumes for the period and rapid growth in production through the end of Q3 and into Q4. Average production in October of more than 46,000 boepd exceeded the low end of our original exit guidance, and production in early November is in excess of 47,500 boepd (based on field estimates). Production for the third quarter averaged 39,074 boepd, comprised of 33,112 bopd of light oil and natural gas liquids and 35,774 Mcf/d of natural gas. Liquids production increased 12% in the third quarter 2011 as compared to the second quarter of 2011, due primarily to the restoration of production that was shut-in for weather conditions. Gas production increased 6% over the second quarter, due primarily to well optimizations in the Alberta/BC Business Unit. Drilling and completion activity commenced later than expected during the quarter because of the unusually long spring break-up and although our drilling program was accelerated, we completed fewer wells than expected. The following table summarizes third quarter 2011 activity and the inventory of wells to be completed and/or brought on production for each business unit.
Q3 2011 Activity
Drilled Completed On Production Inventory(1)
Business Unit Gross Net Gross Net Gross Net Gross Net
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Bakken 33.0 25.4 34.0 28.0 27.0 20.6 18.0 12.6
Conventional (SE
SK) 18.0 12.2 16.0 10.1 10.0 8.0 16.0 6.8
Cardium (central
AB) 44.0 31.5 22.0 14.4 23.0 18.7 37.0 23.5
Alberta/BC 1.0 1.0 - - - - 2.0 2.0
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Total 96.0 70.1 72.0 52.5 60.0 47.3 73.0 44.8
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(1) Inventory refers to the number of wells pending completion and/or tie-in. Since the end of the third quarter we have drilled an additional 39 (26.6 net) wells, completed 33 (24.5 net) wells, and brought 46 (31.2 net) wells on production. Drilling activity continues, and currently we have 11 rigs operating - five in southeast Saskatchewan, five in the Cardium, and one in central Alberta. We expect drilling activity to slow down over the next two months as the consistent weather has allowed us to accelerate our schedule. Completion and tie-in activity will continue as we reduce the number of wells in inventory, resulting in continued production growth through the fourth quarter. Bakken Business Unit Update Bakken production was 8% higher in the third quarter of 2011 compared to the second quarter of 2011, as shut-in production was restored after an unusually long spring break-up (in a typical year, field activity resumes in mid-May). Despite the drilling program commencing later than expected, shorter cycle times and additional rigs allowed us to accelerate our drilling. In addition, we reduced our inventory of wells that were on production but unfrac'd to 8 (6.5 net) from 14 (13.7 net) at the end of the second quarter. Since the end of the third quarter, we have drilled 13 (8.9 net) wells, completed 18 (13.9 net) wells, and brought 13 (9.1 net) wells on production. This activity has resulted in production of more than 21,500 boepd (based on field estimates) at the beginning of November. We continue to see evidence that the new CleanTech(TM) completion technique that we adopted in certain areas of the Bakken play has improved initial oil rates and lowered water cuts. This has provided us with the opportunity to extend the economic limits of the Bakken drilling fairway. We are re-completing our injector well in our first natural gas Enhanced Oil Recovery ("EOR") pilot, providing for more uniform natural gas injection along the length of the horizontal wellbore. We expect to begin natural gas flooding in our next pilot prior to year-end. This pilot is designed to test an injection configuration applicable to both single leg and bilateral horizontal wells. Our third injector well is currently on primary production, and we expect to drill two additional wells in 2012. As previously indicated, it is our intention to place all injector wells on primary production prior to commencing injection. Cardium Business Unit Update Production for the Cardium Business Unit averaged 11,275 boepd in the third quarter, representing an increase of 21% over the second quarter of 2011, due to shut-in production being restored and an active capital program throughout the quarter. Spring break-up for this business unit is typically longer than the Bakken, and the program completed during the quarter was in-line with our original plans. Since the end of the third quarter we have drilled an additional 16 (10.7 net) wells, completed 8 (6.4 net) wells and brought 25 (17.7 net) wells on production, resulting in production of over 15,750 boepd (based on field estimates) in early November. Results from the Cardium play continue to meet or exceed our expectations. All of our Cardium areas are generating strong economic returns, and recent wells in West Pembina, Garrington and Lochend (where we have approximately 75% of our acreage) are typically exceeding our type curve. Although we have seen increases in the cost of certain drilling and completion services, the impact has been attenuated through improved execution efficiencies and reduced cycle times. We have now drilled 176 (132.1 net) horizontal wells since the summer of 2010 and have an inventory of over 650 net remaining locations as we continue to prove up and add to our acreage. OTHER ACTIVITY Our activity in the southeast Saskatchewan conventional Mississippian plays increased significantly from the second quarter. One of the two planned facility upgrades to handle increased water production has been completed, providing for an additional 425 boepd of production from existing wells and also an opportunity for increased drilling activity in both our Bakken and conventional Mississippian plays. The second facility upgrade is expected to be completed in 2012. In our Alberta/BC Business Unit, we continue to evaluate our lands in northeast British Columbia and Alberta. Earlier this year we drilled two Montney wells at Monias in northeast British Columbia to retain our mineral rights and further develop this acreage. The first of these Montney wells has been producing since the beginning of the second quarter while the second well came on-stream in October. We also control 120,000 net acres in emerging oil resource plays in Alberta, and have now drilled three wells to begin evaluating these lands, with a fourth well to commence drilling prior to year-end. FINANCIAL UPDATE PetroBakken's financial performance continued to be strong in the third quarter of 2011 with high operating netbacks due to our light oil focus, resulting in funds flow from operations of $152.4 million ($0.81 per basic and $0.76 per diluted share). Our operating netback of $50.04 decreased 12% compared to the second quarter of 2011, driven primarily by lower WTI prices, which more than offset decreases in operating and royalty expenses. Adjusted net income of $29.7 million ($0.16 per basic and diluted share) decreased 65% compared to the second quarter of 2011, primarily due to an unrealized foreign exchange loss on the convertible debenture, a lower gain on asset dispositions and higher depletion expense, partially offset by an unrealized gain on risk management contracts due to lower WTI prices at the end of the quarter. Net capital expenditures for the quarter were $271.8 million, related to drilling, completions, recompletions, and facilities. Net debt increased from the second quarter by $162.9 million, primarily due to higher activity levels, while drawn credit facility debt remained essentially unchanged at $1.13 billion. At September 30, 2011, our net debt to third quarter annualized funds flow from operations ratio was 2.2 to 1, slightly higher than our target, but with growing production and strong oil prices we expect this ratio to come back below our 2 to 1 target. Debt levels were well within all our credit facility covenants and available bank credit at the end of the quarter was $218 million. OUTLOOK AND SUMMARY Operational challenges that began in the second quarter and persisted into the third quarter are largely behind us now, and execution of our field operations has delivered early November production of over 47,500 boepd (based on field estimates). We now anticipate exit production in excess of 49,000 boepd while maintaining our capital expenditures for the year at approximately $900 million. Assuming a go- forward production rate of approximately 49,000 boepd (87% oil weighted), the estimated cash flow would be approximately $905 million in 2012, assuming US$90 WTI, foreign exchange of 0.975, AECO CDN$3.50 and a 5% differential. During September and October, uncertainties in the global economic climate and market rumours around our Company caused a precipitous decline in our share price. Investors and market participants have been focused on the perceived strength of our balance sheet, due in part to the existence of the convertible debenture we have outstanding, and away from the high quality, light oil assets that underpin PetroBakken. As communicated previously, our management and Board of Directors are very dedicated to managing balance sheet flexibility. In addition to our growing production base and the potential for increased cash flow over time, we have a number of options to provide increased liquidity in the next 15 months to manage the one-time put option that exists with the convertible securities in February 2013. These options include (in no specific order): modifying our capital program and/or altering our cash dividend to provide additional free cash flow, issuing additional debt instruments or equity, instituting a dividend reinvestment program, renegotiating the terms of the existing convertible debentures, or realizing on asset sales. Our team continues to focus on generating long term growth and yield for our shareholders through the continued exploration and exploitation of our existing land holdings, which currently exceed 1 million acres. We have established a long-life base of producing assets in our Bakken and Conventional Business Units, currently generating free cash flow in excess of all sustaining investments. We expect this cash flow to increase over time as decline rates flatten and less capital investment is required to maintain production. Following the same model, we have grown the Cardium Business Unit production from zero to over 15,750 boepd in less than two years and, within the next two years, we expect this business unit to mature and also generate significant free cash flow. In addition to these Business Units, we have prospective natural gas assets in northeast British Columbia, resulting in a total inventory of over 2,150 net drilling locations. Finally, we expect to generate further growth from our expanding inventory of new plays, including some of the prospects currently being tested on oil-focused resource plays in Alberta, where we have accumulated a material land position. INVESTOR CONFERENCE CALL Management of PetroBakken will be holding a conference call for investors, financial analysts, media and any interested persons on Wednesday, November 9, 2011 at 9:00 a.m., MST (11:00 a.m., EST) to discuss PetroBakken's third quarter 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 is: http://events.digitalmedia.telus.com/petrobakken/110911/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 International Financial Reporting Standards ("IFRS"), which are considered to be generally accepted accounting principles ("GAAP"), such as funds flow from operations, adjusted net income, net 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. Management considers funds flow from operations, funds flow per share, adjusted net income, and adjusted net income per share 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 expense and is 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 reflects total capital expenditures less proceeds from dispositions. Funds flow from operations, adjusted net income, net 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. BOEs. 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. 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 capital costs, future production rates, proposed exploration and development activities, the potential for EOR projects, our drilling prospect inventory, the timing of certain projects, capital spending levels and anticipated sources of capital. 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 and cost of labour and services, weather and access to drilling locations and the geological nature of the formations targeted. 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. 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.
Contacts
John D. Wright
PetroBakken Energy Ltd.
President and Chief Executive Officer
(403) 268-7800
(403) 218-6075 (FAX)
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Peter D. Scott
PetroBakken Energy Ltd.
Senior Vice President and Chief Financial Officer
(403) 268-7800
(403) 218-6075 (FAX)
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R. Gregg Smith
PetroBakken Energy Ltd.
Senior Vice President and Chief Operating Officer
(403) 268-7800
(403) 218-6075 (FAX)
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William A. Kanters
PetroBakken Energy Ltd.
Vice President Capital Markets
(403) 268-7800
(403) 218-6075 (FAX)
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www.petrobakken.com
