Attached files
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| 8-K - FORM 8-K - ABRAXAS PETROLEUM CORP | axasye2011.htm |
ABRAXAS PETROLEUM CORPORATION
www.abraxaspetroleum.com
Exhibit 99.1
NEWS RELEASE
Abraxas Announces 2011 Results and Provides an Operational Update
SAN ANTONIO (March 15, 2012) – Abraxas Petroleum Corporation (NASDAQ:AXAS) today reported financial and operating results for the three and twelve months ended December 31, 2011 and provided an operational update.
Financial and Operating Results
Including Abraxas’ equity interest in Blue Eagle’s production, the twelve months ended December 31, 2011 resulted in:
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·
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Production of 1.4 MMBoe (3,762 Boepd), of which 45% was oil or natural gas liquids
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The twelve months ended December 31, 2011 resulted in:
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Production of 1.3 MMBoe (3,484 Boepd), excluding Abraxas’ equity interest in Blue Eagle’s production
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Revenue of $64.6 million
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·
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EBITDA(a) of $31.5 million
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Discretionary cash flow(a) of $24.7 million
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·
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Net income of $13.7 million, or $0.15 per share
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·
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Adjusted net income(a) of $6.3 million, or $0.07 per share, excluding certain non-cash items
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(a)
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See reconciliation of non-GAAP financial measures below.
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Net income for the year ended December 31, 2011 was $13.7 million, or $0.15 per share, compared to a net income of $1.8 million, or $0.02 per share, for the year ended December 31, 2010.
Adjusted net income, excluding certain non-cash items, for the year ended December 31, 2011 was $6.3 million, or $0.07 per share, compared to adjusted net loss, excluding certain non-cash items, of $3.7 million or $0.05 per share for the year ended December 31, 2010. For the year ended December 31, 2011, adjusted net income excludes the unrealized gains on derivative contracts of $7.5 million. For the year ended December 31, 2010, adjusted net loss excludes the ceiling test impairment of $4.8 million and unrealized gains on derivative contracts of $10.3 million.
Unrealized gains or losses on derivative contracts are based on mark-to-market valuations which are non-cash in nature and may fluctuate drastically period to period. As commodity prices fluctuate, these derivative contracts are valued against current market prices at the end of each reporting period in accordance with Accounting Standards Codification 815, “Derivatives and Hedging,” as amended and interpreted, and require Abraxas to either record an unrealized gain or loss based on the calculated value difference from the previous period-end valuation. For example, NYMEX oil prices on December 31, 2011 were $98.83 per barrel compared to $79.20 on September 30, 2011; therefore, the mark-to-market valuation changed considerably period to period.
18803 Meisner Drive
San Antonio, Texas 78258
Phone: 210.490.4788 Fax: 210.918.6675
Operational Update
Rocky Mountain – North Dakota / Montana
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In the Bakken / Three Forks play in the Williston Basin, during the fourth quarter of 2011, 1 gross (<1% net) non-operated well came on-line and 2 gross (0.3 net) wells are currently drilling or awaiting completion. Additionally, we have recently elected to participate in 6 gross (0.6 net) wells that have yet to spud.
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·
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The refurbishment of the Company owned drilling rig has been completed and the rig is currently on its way to McKenzie County, North Dakota to begin drilling its first multi-well pad site.
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Rocky Mountain – Wyoming
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In Campbell County, Wyoming, the Hedgehog State 16-2H, a horizontal well targeting the Turner formation, was recently completed with a 17-stage fracture stimulation. The well is currently flowing back with encouraging initial results. Abraxas owns a 100% working interest in this well.
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South Texas – Eagle Ford
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At December 31, 2011, Abraxas owned a 34.7% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC.
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In McMullen County, Texas, the Cobra 1H, a horizontal well targeting the Eagle Ford Shale, was recently completed with a 15-stage fracture stimulation. The well is currently flowing back at very promising rates. Blue Eagle owns a 100% working interest in this well.
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Canada – Pekisko
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In Alberta, Canada, the pipeline hook-up for three wells is underway and should be completed within the next few weeks. Two wells continue to await stimulation; however, the completions have been delayed as the availability of acid for the stimulations is in short supply. Canadian Abraxas owns a 100% working interest in each of these wells which have targeted the Pekisko formation.
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Commodity Hedges
The Company’s gas hedges were recently monetized for $12.4 million and additional NYMEX-based fixed price oil hedges were entered into at prices above $100 per barrel for the remainder of 2012 through 2014.
Comments
“2011 was an eventful year for us. We embarked on a new endeavor to own and operate our own 2000 hp drilling rig in the Williston Basin. The rig has been completely refurbished, winterized and equipped with a top drive and walking system, as well as many other new components. The rig is currently being trucked to North Dakota and after assembly, it will begin drilling pad development wells in McKenzie County where we have all of the infrastructure, including a semi-permanent man camp for our rig employees, in place and ready to go. We, as are all heavy load transporters, are having to deal with some road detours due to the frost melt but so far we haven’t encountered anything insurmountable. Production in the 4th quarter was negatively impacted from reduced gas production as a number of our dry gas wells were subjected to shut-ins and curtailments due to pipeline and gas plant capacity issues. We determined that spending capital to access alternative delivery points did not make sense in the current gas price environment. We did not make our exit rate guidance due to various delays in getting wells on production, which is becoming standard in our industry in both the U.S. and Canada; nonetheless, the Canadian pipeline construction is almost complete and two new wells in the Eagle Ford and a well in the Turner formation (Wyoming) are currently cleaning up or have recently come on-line. Therefore, we have a good chance of achieving our exit rate guidance, just delayed by a few months. During 2012, all of our activity will be focused on oil and liquids-rich projects as we continue to increase our percentage of oil & NGLs to take advantage of the commodity price arbitrage between oil and natural gas. In addition, we will continue to high-grade our diverse portfolio of assets. Since the Blue Eagle joint venture (Eagle Ford Shale Play, South Texas) has experienced great success since its formation 18 months ago, we will be exploring strategic alternatives this year for this property as well as for an acreage block in the Wolfbone play in Reeves County, Texas and potentially our interest in the Pekisko play in Alberta, Canada,” commented Bob Watson, Abraxas’ President and CEO.
Conference Call
Abraxas invites you to participate in a conference call on Thursday, March 15, 2012, at 2:00 p.m. CT (3:00 p.m. ET) to discuss the contents of this release and respond to questions. Please dial 1.866.713.8310, passcode 40561271, 10 minutes before the scheduled start time, if you would like to participate in the call. The conference call will also be webcast live on the Internet and can be accessed directly on the Company’s website at www.abraxaspetroleum.com under Investor Relations. In addition to the audio webcast replay, a transcript of the conference call will be posted on the Investor Relations section of the Company’s website approximately 24 hours after the conclusion of the call, and will be accessible for at least 60 days.
Abraxas Petroleum Corporation is a San Antonio based crude oil and natural gas exploration and production company with operations across the Rocky Mountain, Mid-Continent, Permian Basin and onshore Gulf Coast regions of the United States and in the province of Alberta, Canada.
Safe Harbor for forward-looking statements: Statements in this release looking forward in time involve known and unknown risks and uncertainties, which may cause Abraxas’ actual results in future periods to be materially different from any future performance suggested in this release. Such factors may include, but may not be necessarily limited to, changes in the prices received by Abraxas for crude oil and natural gas. In addition, Abraxas’ future crude oil and natural gas production is highly dependent upon Abraxas’ level of success in acquiring or finding additional reserves. Further, Abraxas operates in an industry sector where the value of securities is highly volatile and may be influenced by economic and other factors beyond Abraxas’ control. In the context of forward-looking information provided for in this release, reference is made to the discussion of risk factors detailed in Abraxas’ filings with the Securities and Exchange Commission during the past 12 months.
FOR MORE INFORMATION CONTACT:
Barbara M. Stuckey/Vice President – Chief Financial Officer
Telephone 210.490.4788
bstuckey@abraxaspetroleum.com
www.abraxaspetroleum.com
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED
FINANCIAL HIGHLIGHTS
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Three Months Ended
December 31,
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Twelve Months Ended
December 31,
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2011
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2010
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2011
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2010
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Financial Results (In thousands except per share data):
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Revenues
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$ | 16,453 | $ | 13,834 | $ | 64,622 | $ | 58,060 | ||||||||
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EBITDA(a)
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7,742 | 6,330 | 31,504 | 28,200 | ||||||||||||
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Discretionary cash flow(a)
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6,298 | 3,615 | 24,714 | 17,310 | ||||||||||||
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Net income (loss)
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(5,260 | ) | (13,861 | ) | 13,743 | 1,766 | ||||||||||
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Net income (loss) per share – basic
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$ | (0.06 | ) | $ | (0.18 | ) | $ | 0.15 | $ | 0.02 | ||||||
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Adjusted net income (loss), excluding certain non-cash items(a)
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(11,215 | ) | (1,391 | ) | 6,267 | (3,732 | ) | |||||||||
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Adjusted net income (loss), excluding certain non-cash items(a), per share – basic
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$ | (0.12 | ) | $ | (0.02 | ) | $ | 0.07 | $ | (0.05 | ) | |||||
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Weighted average shares outstanding – basic
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91,590 | 75,989 | 90,151 | 75,923 | ||||||||||||
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Production:
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Crude oil per day (Bopd)
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1,564 | 1,369 | 1,479 | 1,366 | ||||||||||||
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Natural gas per day (Mcfpd)
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11,248 | 13,345 | 11,567 | 15,011 | ||||||||||||
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Natural gas liquids (Bblpd)
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111 | 29 | 77 | 28 | ||||||||||||
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Crude oil equivalent per day (Boepd)
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3,549 | 3,621 | 3,484 | 3,896 | ||||||||||||
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Crude oil equivalent (MBoe)
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327 | 333 | 1,272 | 1,422 | ||||||||||||
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Crude oil equivalent per day (Boepd) (b)
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3,749 | 3,621 | 3,762 | 3,896 | ||||||||||||
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Crude oil equivalent (MBoe) (b)
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345 | 333 | 1,373 | 1,422 | ||||||||||||
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Realized Prices, net of realized hedging activity:
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Crude oil ($ per Bbl)
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$ | 77.23 | $ | 66.44 | $ | 76.11 | $ | 66.76 | ||||||||
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Natural gas ($ per Mcf)
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5.58 | 4.96 | 5.64 | 4.97 | ||||||||||||
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Natural gas liquids ($ per Bbl)
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49.77 | 38.54 | 50.07 | 37.81 | ||||||||||||
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Crude oil equivalent ($ per Boe)
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53.28 | 43.68 | 52.13 | 42.81 | ||||||||||||
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Expenses:
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Lease operating ($ per Boe)
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$ | 19.38 | $ | 14.25 | $ | 16.97 | $ | 13.69 | ||||||||
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Production taxes (% of oil and gas revenue)
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9.3 | % | 10.1 | % | 8.9 | % | 10.2 | % | ||||||||
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General and administrative, excluding stock-based compensation ($ per Boe)
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5.49 | 6.27 | 5.85 | 5.14 | ||||||||||||
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Cash interest ($ per Boe)
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2.62 | 6.39 | 3.49 | 6.03 | ||||||||||||
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Depreciation, depletion and amortization
($ per Boe)
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14.77 | 11.15 | 12.73 | 11.40 | ||||||||||||
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(a)
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See reconciliation of non-GAAP financial measures below.
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(b)
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Includes Abraxas’ equity interest in Blue Eagle’s production.
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BALANCE SHEET DATA
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(In thousands)
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December 31, 2011
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December 31, 2010
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Cash
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$ | — | $ | 99 | ||||
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Working capital (a)
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(14,404 | ) | (5,948 | ) | ||||
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Property and equipment – net
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179,552 | 117,248 | ||||||
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Total assets
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241,150 | 182,909 | ||||||
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Long-term debt
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126,258 | 140,940 | ||||||
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Stockholders’ equity (deficit)
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62,651 | (14,976 | ) | |||||
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Common shares outstanding
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92,261 | 76,428 | ||||||
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(a)
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Excludes current maturities of long-term debt and current derivative assets and liabilities.
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ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF OPERATIONS
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(In thousands except per share data)
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Year Ended December 31,
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2011
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2010
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2009
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Revenues:
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Oil and gas production
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$
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64,615
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$
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58,050
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$
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51,829
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Other
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7
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10
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7
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64,622
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58,060
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51,836
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Operating costs and expenses:
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Lease operating
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21,581
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19,475
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20,265
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Production and ad valorem taxes
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5,766
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5,910
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5,803
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Depreciation, depletion, and amortization
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16,194
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16,212
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17,886
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Ceiling test impairment
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—
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4,787
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—
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General and administrative (including stock-based compensation of $1,987, $1,560 and $1,239)
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9,433
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8,869
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7,705
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52,974
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55,253
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51,659
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Operating income
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11,648
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2,807
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177
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Other (income) expense:
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Interest income
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(7)
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(8)
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(15)
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Interest expense
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4,898
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9,106
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11,346
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Amortization of deferred financing fees
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1,762
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2,479
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1,326
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Loss (gain) on derivative contracts - realized
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676
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(526)
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(15,328)
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(Gain) loss on derivative contracts - unrealized
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(7,476)
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(10,285)
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27,650
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Financing fees
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—
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—
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362
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Equity in (income) loss of joint venture
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(2,187)
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473
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—
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Other
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316
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(119)
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2,071
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(2,018)
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1,120
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27,412
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Income (loss) before income tax and non-controlling interest
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13,666
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1,687
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(27,235)
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Income tax benefit (expense)
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77
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79
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(1,290)
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Income (loss) before non-controlling interest
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13,743
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1,766
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(28,525)
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Non-controlling interest
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—
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—
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9,745
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Net income (loss)
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$
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13,743
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$
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1,766
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$
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(18,780)
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Net income (loss) per common share - basic
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$
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0.15
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$
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0.02
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$
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(0.34)
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Net income (loss) per common share - diluted
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$
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0.15
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$
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0.02
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$
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(0.34)
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Weighted average shares outstanding:
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Basic
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90,151
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75,923
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55,499
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Diluted
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92,244
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77,224
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55,499
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ABRAXAS PETROLEUM CORPORATION
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
To fully assess Abraxas’ operating results, management believes that, although not prescribed under generally accepted accounting principles ("GAAP"), discretionary cash flow and EBITDA are appropriate measures of Abraxas' ability to satisfy capital expenditure obligations and working capital requirements. Discretionary cash flow and EBITDA are non-GAAP financial measures as defined under SEC rules. Abraxas' discretionary cash flow and EBITDA should not be considered in isolation or as a substitute for other financial measurements prepared in accordance with GAAP or as a measure of the Company's profitability or liquidity. As discretionary cash flow and EBITDA exclude some, but not all items that affect net income and may vary among companies, the discretionary cash flow and EBITDA presented below may not be comparable to similarly titled measures of other companies. Management believes that operating income calculated in accordance with GAAP is the most directly comparable measure to discretionary cash flow and EBITDA; therefore, operating income is utilized as the starting point for these reconciliations.
Discretionary cash flow is defined as operating income plus depreciation, depletion and amortization expenses, non-cash expenses and impairments, cash portion of other income (expense) less cash interest. The following table provides a reconciliation of discretionary cash flow to operating income for the periods presented.
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(In thousands)
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Three Months Ended
December 31,
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Twelve Months Ended
December 31,
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2011
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2010
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2011
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2010
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Operating income (loss)
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$ | 1,482 | $ | (3,251 | ) | $ | 11,648 | $ | 2,807 | |||||||
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Depreciation, depletion and amortization
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4,823 | 3,717 | 16,194 | 16,212 | ||||||||||||
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Ceiling test impairment
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— | 4,787 | — | 4,787 | ||||||||||||
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Stock-based compensation
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488 | 355 | 1,987 | 1,560 | ||||||||||||
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Realized gain (loss) on derivative contracts
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361 | 136 | (676 | ) | 526 | |||||||||||
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Cash interest
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(856 | ) | (2,129 | ) | (4,439 | ) | (8,582 | ) | ||||||||
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Discretionary cash flow
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$ | 6,298 | $ | 3,615 | $ | 24,714 | $ | 17,310 | ||||||||
EBITDA is defined as net income (loss) plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA to operating income for the periods presented – see consolidated statements of operations for a reconciliation of net income (loss) to operating income.
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(In thousands)
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Three Months Ended
December 31,
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Twelve Months Ended
December 31,
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2011
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2010
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2011
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2010
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Operating income (loss)
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$ | 1,482 | $ | (3,251 | ) | $ | 11,648 | $ | 2,807 | |||||||
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Depreciation, depletion and amortization
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4,823 | 3,717 | 16,194 | 16,212 | ||||||||||||
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Ceiling-test impairment
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— | 4,787 | — | 4,787 | ||||||||||||
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Stock-based compensation
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488 | 355 | 1,987 | 1,560 | ||||||||||||
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Realized gain (loss) on derivative contracts(a)
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949 | 722 | 1,675 | 2,834 | ||||||||||||
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EBITDA
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$ | 7,742 | $ | 6,330 | $ | 31,504 | $ | 28,200 | ||||||||
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(a)
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Excludes realized gain (loss) associated with interest rate derivative contract.
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· This release also includes a discussion of “adjusted net income (loss), excluding certain non-cash items,” which is a non-GAAP financial measure as defined under SEC rules. The following table provides a reconciliation of adjusted net income (loss), excluding ceiling test impairment and change in unrealized derivative contracts, to net income (loss) for the periods presented. Management believes that net income (loss) calculated in accordance with GAAP is the most directly comparable measure to adjusted net income (loss), excluding certain non-cash items.
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·
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(In thousands)
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Three Months Ended
December 31,
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Twelve Months Ended
December 31,
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2011
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2010
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2011
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2010
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Net income (loss)
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$ | (5,260 | ) | $ | (13,861 | ) | $ | 13,743 | $ | 1,766 | ||||||
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Ceiling test impairment
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— | 4,787 | — | 4,787 | ||||||||||||
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Loss (gain) on unrealized derivative
contracts
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(5,955 | ) | 7,683 | (7,476 | ) | (10,285 | ) | |||||||||
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Adjusted net income (loss), excluding certain non-cash items
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$ | (11,215 | ) | $ | (1,391 | ) | $ | 6,267 | $ | (3,732 | ) | |||||
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Net income (loss) per share – basic
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(0.06 | ) | (0.18 | ) | 0.15 | 0.02 | ||||||||||
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Adjusted net income (loss), excluding certain non-cash items, per share – basic
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$ | (0.12 | ) | $ | (0.02 | ) | $ | 0.07 | $ | (0.05 | ) | |||||