Attached files
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| 8-K - GASTAR EXPLORATION, INC. | v214357_8k.htm |
Exhibit 99.1
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NEWS RELEASE
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Contacts:
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Gastar Exploration Ltd.
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Michael A. Gerlich, Chief Financial Officer
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713-739-1800 / mgerlich@gastar.com
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Investor Relations Counsel:
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Lisa Elliott / Anne Pearson
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DRG&L: 713-529-6600
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lelliott@drg-l.com / apearson@drg-l.com
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GASTAR EXPLORATION REPORTS
FOURTH QUARTER AND FULL-YEAR 2010 RESULTS
· 23% increase in 4Q oil and gas revenue vs. a year ago
· 12% increase in 4Q oil and gas production vs. a year ago
· Replaced over 100% of production through drilling program
HOUSTON, March 10, 2011 – Gastar Exploration Ltd. (NYSE Amex: GST) today reported financial and operating results for the three and 12 months ended December 31, 2010.
Net loss for the fourth quarter of 2010 was $2.9 million, or $0.06 per share. Excluding the impact of special items, adjusted net income was $325,000, or $0.01 per share. This compares to reported net income of $12.9 million, or $0.26 per diluted share, for the fourth quarter of 2009. Excluding the impact of special items, the largest of which were a $17.8 million gain on the sale of the Company’s Australian assets and a related $4.5 million of income tax expense, adjusted net loss for the fourth quarter of 2009 was $748,000, or $0.02 per share. See the accompanying reconciliation of net income and earnings per share and related financial information to these non-GAAP financial measures in the “Reconciliation of Net Income (Loss) to Net Income (Loss)
Excluding Special Items” table within “Non-GAAP Financial Information and Reconciliation” at the end of this news release.
Our cash used by operations before working capital changes for the fourth quarter of 2010 was $14.6 million and $6.5 million for the 12 months ended December 31, 2010. After adjusting cash flow from operations before working capital changes for the three and 12 months ended December 31, 2010 to eliminate litigation settlement expense and other items, adjusted cash flow from operations was $4.0 million and $10.9 million for these periods, respectively. This compares to the three and 12 months ended December 31, 2009 adjusted cash flow from operations before working capital changes of $2.2 million and $16.2 million, respectively. See the accompanying reconciliation of cash flow from operations and related financial information to these non-GAAP financial measures in the
“Reconciliation of Cash Flow from Operations before Working Capital Changes and Special Items” table within “Non-GAAP Financial Information and Reconciliation” at the end of this news release.
Natural gas and oil revenues increased 23% to $9.4 million in the fourth quarter of 2010, up from $7.7 million for the same period a year ago. The increase in revenues was the result of a 10% increase in realized commodity prices combined with a 12% increase in volumes. Average daily production was 25.8 million cubic feet of natural gas equivalent (“MMcfe”) for the fourth quarter of 2010, compared to 23.0 MMcfe per day for the same period in 2009.
During the fourth quarter of 2010, approximately 74% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $2.1 million in revenues and resulted in an increase in total price received from $3.01 per thousand cubic feet (“Mcf”) to $3.90 per Mcf. The realized hedge impact includes a benefit of $169,000 for the non-cash amortization of prepaid put purchase and call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $1.9 million, which is composed of $2.9 million of NYMEX hedge gains offset by $331,000 of regional basis losses and payment of deferred put premiums of $659,000. We continue to maintain an active hedging program covering a
substantial portion of our future natural gas production.
Lease operating expense (“LOE”) was $1.5 million in the fourth quarter of 2010, which is consistent with LOE a year ago. LOE per thousand cubic feet of natural gas equivalent (“Mcfe”) of production decreased to $0.62 in the fourth quarter of 2010, compared to $0.70 per Mcfe during the fourth quarter of 2009. The decrease per Mcfe was primarily due to higher production volumes.
General and administrative expense was $3.0 million in the fourth quarter of 2010 compared to $4.0 million for the same period in 2009. The $1.0 million decrease was primarily due to lower legal and personnel costs.
Year-End Reserves
Total proved reserves as of December 31, 2010 were 49.9 billion cubic feet (“Bcf”) of natural gas and 61,300 barrels of oil, or 50.3 billion cubic feet of natural gas equivalent (“Bcfe”), of which 83% were proved developed reserves.
The present value of estimated future cash flows, discounted at 10% per year (“PV-10”), was $67.3 million as of December 31, 2010, employing the U.S. Securities and Exchange Commission 12-month un-weighted average of the first-day-of-the-month pricing (“SEC average pricing”) methodology utilizing a Henry Hub price of $4.38 per MMBtu, Katy Hub price of $4.32 per MMBtu, CIG price of $3.95 per MMBtu, Columbia Appalachia Gas Pool price of $4.50 per MMBtu, and an oil price of $75.96 per barrel.
Total proved reserves as of December 31, 2009 were 48.5 Bcf of natural gas and 66,700 barrels of oil, or 48.9 Bcfe, of which 73% were proved developed reserves. The PV-10 was $45.6 million as of December 31, 2009, utilizing the same SEC average pricing methodology of a Henry Hub price of $3.87 per MMBtu, Katy Hub price of $3.68 per MMBtu, CIG price of $3.04 per MMBtu, Columbia Appalachia Gas Pool price of $4.05 per MMBtu and an oil price of $57.65 per barrel.
Operations Review and Update
East Texas
In East Texas, fourth quarter net production from the Hilltop area averaged 23.8 MMcfe per day, up from 20.1 MMcfe per day in the third quarter of 2010. The increase in volumes was primarily due to bringing the Streater #1 well, a middle Bossier well, on production September 30, 2010. During the three months ended December 31, 2010, the Streater #1 well produced at an average gross sales rate of 5.8 MMcf per day. During the fourth quarter of 2010, we began drilling the Belin #2 well, an exploration well testing the deep Bossier in a separate fault block near the Belin #1 well. The well reached total depth of 19,650 feet and encountered approximately 130 net feet of pay in the lower Bossier formation within five separate
sand intervals. We plan to complete the well in two initial zones and, depending upon the availability of frac stimulation services, expect the first of these initial completions to be on production by the end of April 2011.
2
Following the Wildman 6H well that was drilled in the second quarter of 2010, we continued to drill and test oil potential from the Glen Rose formation in East Texas during the fourth quarter. We drilled both the Williams #2, a vertical well, and the Wildman 8H, a multi-stage horizontal well, in the Glen Rose formation. We are continuing to evaluate the completion method that was used in the Wildman 6H well with modest success. The Wildman 6H’s current production is averaging approximately 30 barrels of oil per day. The Wildman 8H and Williams #2 were fracture stimulated and completed in the Glen Rose formation in late February 2011 and have begun initial flow back operations. The initial seven-day
Wildman 8H flowing production averaged over 250 barrels of oil per day and in excess of 1,300 barrels of fracture stimulation fluids per day. The Williams #2 is flowing naturally from the initial stimulation and will be placed on artificial lift in order for us to evaluate the vertical Glen Rose oil potential.
We also began testing the Eagle Ford Shale/Woodbine formation (the “Eaglebine”) with one well, the Wildman 7H, a horizontal well that, as a result of drilling issues, was not able to be drilled in the targeted portion of the Eaglebine formation. We re-targeted the horizontal lateral into the slightly deeper False Buda formation and fracture stimulated the well with a 16-stage frac designed to be directed up into the Eaglebine formation. Micro-seismic data was gathered during the frac job and subsequent processing and interpretation of that data indicates that the stimulation did not grow up into the targeted portion of the Eaglebine formation. The Wildman 7H was placed on artificial lift in mid-February and production is currently averaging 120 barrels of oil per day
and in excess of 1,500 barrels of water per day. We plan on drilling a subsequent Eaglebine well, the Wildman 9H, on the basis of the micro-seismic data and the production results observed to date from the Wildman 7H. The horizontal lateral in the Wildman 9H well will be targeted within the portion of the Eaglebine that was originally the target of the Wildman 7H well and is the target of drilling by other nearby operators. Drilling of the Wildman 9H well is scheduled to commence in mid-March, subject to rig availability.
At December 31, 2010, proved reserves attributable to the Hilltop area were approximately 45.0 Bcfe, representing 90% of our total proved reserves, 83% of which is proved developed. Our East Texas portfolio includes 28 gross (20.4 net) productive wells, and we have identified numerous potential drilling locations on our current acreage of 33,400 gross (19,200 net) acres in the area.
Capital expenditures in East Texas were $13.4 million for the fourth quarter of 2010 and $39.7 million for the year, and we expect to spend approximately $36.2 million in this area for the full year 2011.
Appalachia
In Appalachia, we continued to expand our acreage position and participated in several test and development operations during the fourth quarter of 2010. As previously announced, we completed a Marcellus Shale acquisition for $28.9 million in December 2010. The acquisition consisted of approximately 61,800 net acres of leasehold in the Marcellus Shale concentrated in Preston, Tucker and Pendleton Counties, West Virginia along with a gathering system, a salt water disposal well and five conventional wells producing approximately 500 Mcf per day (gross) of natural gas. We plan to drill one horizontal Marcellus wells on this acreage during 2011 in order to further de-risk the acreage and to provide data that could allow for the
marketing of a second joint venture on this acreage or further development by us without partner participation.
3
In February 2011, we, along with our joint venture partner, Atinum, leased approximately 3,300 gross (1,517 net) additional acres in Marshall County, West Virginia to develop the liquids-rich Marcellus Shale formation. Under the joint venture agreement, we will pay 45% of the lease acquisition cost for a 50% interest, and the initial drilling and completion activities on this acreage will be eligible for the related drilling carry, as previously announced. The acreage is on an industrial site along the Ohio River and provides excellent access to water and natural gas infrastructure. As operator, we expect to begin drilling during the second half of 2011 and to date have identified as many as 30 locations to be drilled over the next several years.
In the fourth quarter of 2010, we reached total depth on our first operated horizontal Marcellus well, the Wengerd 1H, in Marshall County, West Virginia, which is expected to be fracture stimulated during the second quarter of 2011, and if successful, would go on production shortly thereafter. The Wengerd 1H well is within our new joint venture with Atinum, thus we will pay 12.5% of the cost of the well for a 50% interest.
Also, in the fourth quarter of 2010, we and Atinum participated in the drilling of the vertical section of seven horizontal Marcellus wells in Butler County, Pennsylvania with Rex Energy as operator. The operator intends to drill the horizontal portions of the seven wells commencing later this month, to be followed by completion of the wells in succession with expected initial sales in the fourth quarter of 2011. We and Atinum collectively own 38.4% of the seven wells, and Atinum will pay 87.5% of our combined net cost.
At December 31, 2010, proved reserves attributable to the Appalachia area were approximately 2.8 Bcfe, representing 6% of our total proved reserves. For the year ended December 31, 2010, net production from the Appalachian area averaged 0.4 MMcfe per day from 41 gross (29.4 net) shallow Devonian wells, of which 14 gross (11.6 net) wells were acquired in mid-December 2010, as mentioned above. Currently, we hold a total of 81,200 net (91,000 gross) lease acres in the Appalachia region targeting the Marcellus Shale formation.
Capital expenditures for the fourth quarter in Appalachia were $4.0 million and $22.4 million for the full year 2010, and we expect to spend approximately $43.9 million for the full year 2011.
J. Russell Porter, Gastar's President and CEO, stated, “As we enter 2011, we are enthusiastic about our numerous opportunities to increase reserves, production and cash flow, and about the oil and liquids rich gas projects in our portfolio. Although we still have more testing to undertake, we are encouraged by the early indications of oil potential in our East Texas acreage to complement the solid success we have had developing natural gas production from the Bossier formation. Over the years we have been successful in improving drilling, completion and operating techniques to lower costs and increase reserves and production from our Bossier wells. We are now focusing those efforts to determine the best techniques to maximize the
potential of the shallower Glen Rose and Eaglebine formations on our existing East Texas acreage.
“In Appalachia, we have substantially increased and improved our acreage position by accumulating leases in potentially liquids-rich formations of the Marcellus Shale, trading leases to create more efficient blocks in attractive areas and developing a joint venture to help accelerate the pace of development of our assets. In 2011, we expect to drill approximately 28 gross operated horizontal wells and participate in 7 gross non-operated horizontal wells, with about half expected to be on production by year-end. After several years of accumulating a significant and high quality acreage position in the Appalachian area, we are excited about now being able to dramatically increase the level of drilling activity in the Marcellus Shale.
Gastar is uniquely leveraged to the upside that this play offers and we are enthusiastic about our reserve and production growth potential in 2011 from this drilling program,” concluded Porter.
4
Liquidity and Capital Budget
In December 2010, we completed an underwritten public offering of 13.8 million common shares at a public offering price of $4.00 per share. The aggregate net proceeds from the offering totaled approximately $52.5 million after deducting underwriting discounts and offering expenses of approximately $2.7 million. The proceeds from the offering were used to fund the $28.9 million purchase of the Marcellus acreage in December 2010, to fund the initial settlement payment of $18.0 million with respect to the seven In re ClassicStar Mare Lease litigation matters in December 2010 and for general corporate purposes.
At December 31, 2010, the Company had cash and cash equivalents of $7.4 million and a net working capital deficit of approximately $2.8 million, including $3.2 million of the litigation settlement accrual. There were no amounts outstanding under our existing $47.5 million revolving credit facility at December 31, 2010. Currently, we have $17.0 million of debt outstanding under the revolving credit facility prior to receiving reimbursement from Atinum for their 55% share of the recent Marshall County, West Virginia Marcellus Shale acreage acquisition.
Our 2011 planned capital expenditures for properties, excluding acquisitions, are projected to be approximately $83.6 million, consisting of drilling and completion costs of $30.5 million in East Texas and $23.7 million in Appalachia, an additional $22.5 million in lease acquisition costs, $3.5 million for seismic and $3.4 million for capitalized interest and other costs. We plan on funding this capital activity through our existing cash balances, internally generated cash flows from operating activities, availability under our revolving credit facility, possible debt or equity issuance and/or a possible joint venture for the development of our non-joint venture acreage.
Conference Call
Gastar Exploration’s management team will hold a conference call tomorrow, Friday, March 11 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss these results. To participate in the call, dial 480-629-9722 at least 10 minutes early and ask for the Gastar Exploration conference call. A replay will be available approximately two hours after the call ends and will be accessible through March 18, 2011. To access the replay, dial 303-590-3030 and enter the pass code 4406342#.
The call will also be webcast live over the Internet at www.gastar.com. To listen to the live call on the Internet, please visit Gastar’s web site at least 10 minutes early to register and download any necessary audio software. An archive will be available shortly after the call. For more information, please contact Donna Washburn at DRG&L at 713-529-6600 or e-mail dmw@drg-l.com.
5
About Gastar Exploration
Gastar Exploration Ltd. is an independent company engaged in the exploration, development and production of natural gas and oil in the United States. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as shale resource plays. We are pursuing natural gas exploration in the deep Bossier gas play in the Hilltop area in East Texas and the Marcellus Shale in West Virginia and central and southwestern Pennsylvania. We also conduct coal bed methane development activities within the
Powder River Basin of Wyoming and Montana. For more information, visit our web site at www.gastar.com.
Safe Harbor Statement and Disclaimer
This news release includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward looking statements give our current expectations, opinion, belief or forecasts of future events and performance. A statement identified by the use of forward looking words including “may”, “expects”, “projects”, “anticipates”, “plans”, “believes”, “estimate”, “will”, “should”, and certain of the other foregoing statements may be deemed forward-looking statements. Although Gastar believes that the expectations reflected in such forward-looking statements are
reasonable, these statements involve risks and uncertainties that may cause actual future activities and results to be materially different from those suggested or described in this news release. These include risk inherent in natural gas and oil drilling and production activities, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks, which may temporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales or completion of drilling operations; delays in receipt of drilling permits; risks with respect to natural gas and oil prices, a material decline in which could cause Gastar to delay or suspend planned drilling operations or reduce production levels; risks relating to the availability of capital to fund drilling operations that can be
adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices; risks relating to unexpected adverse developments in the status of properties; risks relating to the absence or delay in receipt of government approvals or fourth party consents; and other risks described in Gastar’s Annual Report on Form 10-K and other filings with the SEC, available at the SEC’s website at www.sec.gov. Our actual sales production rates can vary considerably from tested initial production rates depending upon completion and production techniques and our primary areas of operations are subject to natural steep decline rates. By issuing forward looking statements based on current expectations, opinions, views or beliefs, Gastar has no obligation and, except as required by law, is not undertaking any obligation, to update or revise these statements or provide any other information relating to such statements.
- Financial Tables Follow -
6
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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For the Three Months Ended
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For the Year Ended
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December 31,
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December 31,
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2010
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2009
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2010
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2009
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(in thousands, except share and per share data)
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REVENUES:
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Natural gas and oil revenues
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$ | 9,402 | $ | 7,660 | $ | 31,554 | $ | 40,636 | ||||||||
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Unrealized natural gas hedge gain (loss)
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(2,679 | ) | 145 | 11,214 | (7,767 | ) | ||||||||||
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Total revenues
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6,723 | 7,805 | 42,768 | 32,869 | ||||||||||||
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EXPENSES:
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Production taxes
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70 | 114 | 370 | 439 | ||||||||||||
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Lease operating expenses
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1,473 | 1,487 | 6,679 | 6,572 | ||||||||||||
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Transportation, treating and gathering
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1,146 | 557 | 4,654 | 1,547 | ||||||||||||
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Depreciation, depletion and amortization
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3,238 | 2,170 | 9,306 | 16,484 | ||||||||||||
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Impairment of natural gas and oil properties
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- | - | - | 68,729 | ||||||||||||
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Accretion of asset retirement obligation
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104 | 114 | 396 | 379 | ||||||||||||
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General and administrative expense
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3,020 | 4,048 | 14,638 | 15,649 | ||||||||||||
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Litigation settlement expense
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594 | - | 21,744 | - | ||||||||||||
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Total expenses
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9,645 | 8,490 | 57,787 | 109,799 | ||||||||||||
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LOSS FROM OPERATIONS
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(2,922 | ) | (685 | ) | (15,019 | ) | (76,930 | ) | ||||||||
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OTHER INCOME (EXPENSE):
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Interest expense
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(30 | ) | (663 | ) | (150 | ) | (3,993 | ) | ||||||||
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Early extinguishment of debt
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- | - | - | (15,902 | ) | |||||||||||
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Investment income and other
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4 | 745 | 1,347 | 1,267 | ||||||||||||
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Gain on sale of assets
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- | 17,786 | - | 211,162 | ||||||||||||
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Unrealized warrant derivative gain (loss)
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- | 290 | 205 | (205 | ) | |||||||||||
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Foreign transaction gain
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4 | 2 | 353 | 3,764 | ||||||||||||
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INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES
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(2,944 | ) | 17,475 | (13,264 | ) | 119,163 | ||||||||||
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Provision for income tax expense (benefit)
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- | 4,541 | (804 | ) | 70,317 | |||||||||||
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NET INCOME (LOSS)
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$ | (2,944 | ) | $ | 12,934 | $ | (12,460 | ) | $ | 48,846 | ||||||
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NET INCOME (LOSS) PER SHARE:
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Basic
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$ | (0.06 | ) | $ | 0.26 | $ | (0.25 | ) | $ | 1.06 | ||||||
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Diluted
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$ | (0.06 | ) | $ | 0.26 | $ | (0.25 | ) | $ | 1.06 | ||||||
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WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
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Basic
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52,066,371 | 48,994,268 | 49,813,617 | 46,102,662 | ||||||||||||
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Diluted
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52,066,371 | 49,277,432 | 49,813,617 | 46,210,424 | ||||||||||||
7
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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December 31,
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2010
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2009
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(in thousands)
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ASSETS
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CURRENT ASSETS:
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Cash and cash equivalents
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$ | 7,439 | $ | 21,866 | ||||
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Term deposit
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- | 69,662 | ||||||
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Accounts receivable, net of allowance for doubtful accounts of $571 and $609, respectively
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4,034 | 5,336 | ||||||
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Receivable from unproved property sale
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- | 19,412 | ||||||
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Commodity derivative contracts
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10,229 | 4,870 | ||||||
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Prepaid expenses
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1,191 | 669 | ||||||
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Total current assets
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22,893 | 121,815 | ||||||
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PROPERTY, PLANT AND EQUIPMENT:
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Natural gas and oil properties, full cost method of accounting:
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Unproved properties, excluded from amortization
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162,230 | 132,720 | ||||||
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Proved properties
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345,042 | 313,100 | ||||||
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Total natural gas and oil properties
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507,272 | 445,820 | ||||||
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Furniture and equipment
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1,175 | 867 | ||||||
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Total property, plant and equipment
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508,447 | 446,687 | ||||||
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Accumulated depreciation, depletion and amortization
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(293,332 | ) | (284,026 | ) | ||||
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Total property, plant and equipment, net
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215,115 | 162,661 | ||||||
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OTHER ASSETS:
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Restricted cash
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50 | 50 | ||||||
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Commodity derivative contracts
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8,482 | 10,698 | ||||||
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Deferred charges, net
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508 | 764 | ||||||
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Drilling advances and other assets
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304 | 250 | ||||||
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Total other assets
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9,344 | 11,762 | ||||||
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TOTAL ASSETS
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$ | 247,352 | $ | 296,238 | ||||
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LIABILITIES AND SHAREHOLDERS' EQUITY
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CURRENT LIABILITIES:
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Accounts payable
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$ | 9,077 | $ | 8,291 | ||||
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Revenue payable
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4,331 | 4,621 | ||||||
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Accrued interest
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138 | 130 | ||||||
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Accrued drilling and operating costs
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1,490 | 736 | ||||||
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Commodity derivative contracts
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1,991 | 3,678 | ||||||
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Commodity derivative premium payable
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3,451 | 1,190 | ||||||
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Accrued litigation settlement liability
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3,164 | - | ||||||
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Short-term loan
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- | 17,000 | ||||||
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Accrued taxes payable
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- | 75,887 | ||||||
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Other accrued liabilities
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2,024 | 1,438 | ||||||
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Total current liabilities
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25,666 | 112,971 | ||||||
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LONG-TERM LIABILITIES:
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Commodity derivative contracts
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1,521 | 4,047 | ||||||
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Commodity derivative premium payable
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4,725 | 8,176 | ||||||
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Accrued litigation settlement liability
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800 | - | ||||||
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Asset retirement obligation
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7,249 | 5,943 | ||||||
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Warrant derivative
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- | 205 | ||||||
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Total long-term liabilities
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14,295 | 18,371 | ||||||
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Commitments and contingencies (Note 13)
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SHAREHOLDERS' EQUITY:
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Preferred stock, no par value; unlimited shares authorized; no shares issued
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- | - | ||||||
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Common stock, no par value; unlimited shares authorized; 64,179,115 and 50,028,592 shares issued and outstanding at December 31, 2010 and 2009, respectively
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316,346 | 263,809 | ||||||
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Additional paid-in capital
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23,200 | 20,782 | ||||||
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Accumulated deficit
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(132,155 | ) | (119,695 | ) | ||||
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Total shareholders' equity
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207,391 | 164,896 | ||||||
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TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
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$ | 247,352 | $ | 296,238 | ||||
8
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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Years Ended December 31,
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2010
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2009
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(in thousands)
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CASH FLOWS FROM OPERATING ACTIVITIES:
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Net income (loss)
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$ | (12,460 | ) | $ | 48,846 | |||
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Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
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||||||||
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Depreciation, depletion and amortization
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9,306 | 16,484 | ||||||
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Impairment of natural gas and oil properties
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- | 68,729 | ||||||
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Stock-based compensation
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2,765 | 3,547 | ||||||
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Unrealized natural gas hedge (gain) loss
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(11,214 | ) | 7,767 | |||||
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Realized loss (gain) on derivative contracts
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1,437 | (3,053 | ) | |||||
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Amortization of deferred financing costs and debt discount
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283 | 1,964 | ||||||
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Accretion of asset retirement obligation
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396 | 379 | ||||||
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Loss on early extinguishment of debt
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- | 7,027 | ||||||
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Gain on sale of assets
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- | (211,162 | ) | |||||
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Unrealized warrant derivative (gain) loss
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(205 | ) | 205 | |||||
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Litigation settlement payable
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3,150 | - | ||||||
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Changes in operating assets and liabilities:
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||||||||
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Accounts receivable
|
1,565 | 2,278 | ||||||
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Commodity derivative contracts
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1,232 | 2,893 | ||||||
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Prepaid expenses
|
(522 | ) | 151 | |||||
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Accrued taxes payable
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(1,420 | ) | 75,887 | |||||
|
Accounts payable and accrued liabilities
|
(287 | ) | (8,498 | ) | ||||
|
Net cash (used in) provided by operating activities
|
(5,974 | ) | 13,444 | |||||
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||
|
Development and purchase of natural gas and oil properties
|
(58,512 | ) | (49,230 | ) | ||||
|
Drilling advances
|
(300 | ) | (6,044 | ) | ||||
|
Acquisition of natural gas and oil properties
|
(28,887 | ) | - | |||||
|
Proceeds from sale of natural gas and oil properties
|
49,197 | 251,267 | ||||||
|
Purchase of furniture and equipment
|
(308 | ) | (42 | ) | ||||
|
Purchase of term deposit
|
(4,855 | ) | (69,662 | ) | ||||
|
Net cash (used in) provided by investing activities
|
(43,665 | ) | 126,289 | |||||
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
|
Proceeds from issuance of common shares, net of issuance costs
|
52,537 | 13,829 | ||||||
|
Proceeds from short-term loan
|
- | 17,000 | ||||||
|
Proceeds from term loan
|
- | 25,000 | ||||||
|
Repayment of 12 3/4 % senior secured notes
|
- | (100,000 | ) | |||||
|
Repayment of term loan
|
- | (25,000 | ) | |||||
|
Repayment of revolving credit facility
|
- | (18,875 | ) | |||||
|
Repayment of convertible senior unsecured subordinated debentures
|
- | (30,000 | ) | |||||
|
Repayment of subordinated unsecured notes
|
- | (3,250 | ) | |||||
|
Repayment of short-term loan
|
(17,000 | ) | - | |||||
|
Decrease in restricted cash
|
- | 20 | ||||||
|
Deferred financing charges
|
(27 | ) | (2,466 | ) | ||||
|
Other
|
(298 | ) | (278 | ) | ||||
|
Net cash provided by (used in) financing activities
|
35,212 | (124,020 | ) | |||||
|
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
|
(14,427 | ) | 15,713 | |||||
|
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
|
21,866 | 6,153 | ||||||
|
CASH AND CASH EQUIVALENTS, END OF PERIOD
|
$ | 7,439 | $ | 21,866 | ||||
9
PRODUCTION AND PRICES
|
For the Three Months Ended
|
For the Years Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Production:
|
||||||||||||||||
|
Natural gas (MMcf)
|
2,350 | 2,111 | 7,593 | 9,266 | ||||||||||||
|
Oil (MBbl)
|
3 | 1 | 10 | 4 | ||||||||||||
|
Total production (MMcfe)
|
2,369 | 2,116 | 7,654 | 9,291 | ||||||||||||
|
Total (MMcfed)
|
25.8 | 23.0 | 21.0 | 25.5 | ||||||||||||
|
Average sales price per unit:
|
||||||||||||||||
|
Natural gas per Mcf, excluding impact of realized hedging activities
|
$ | 3.01 | $ | 3.50 | $ | 3.51 | $ | 3.06 | ||||||||
|
Natural gas per Mcf, including impact of realized hedging activities
|
$ | 3.90 | $ | 3.60 | $ | 4.06 | $ | 4.36 | ||||||||
|
Oil per Bbl
|
$ | 77.09 | $ | 67.92 | $ | 72.63 | $ | 54.46 | ||||||||
10
NON-GAAP FINANCIAL INFORMATION AND RECONCILIATION
We use both GAAP and certain non-GAAP financial measures to assess performance. Generally, a non-GAAP financial measure is a numerical measure of a company’s performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with GAAP. Our management believes that these non-GAAP measures provide useful supplemental information to investors in order that they may evaluate our financial performance using the same measures as management. These non-GAAP financial measures should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP. In evaluating these
measures, investors should consider that the methodology applied in calculating such measures may differ among companies and analysts. A reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures.
Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items:
|
For the Three Months Ended
|
For the Year Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
(in thousands, except share and per share data)
|
||||||||||||||||
|
NET INCOME (LOSS) AS REPORTED
|
$ | (2,944 | ) | $ | 12,934 | $ | (12,460 | ) | $ | 48,846 | ||||||
|
SPECIAL ITEMS:
|
||||||||||||||||
|
Unrealized natural gas hedge (gain) loss
|
2,679 | (145 | ) | (11,214 | ) | 7,767 | ||||||||||
|
Litigation settlement expense
|
594 | - | 21,744 | - | ||||||||||||
|
Impairment of natural gas and oil properties
|
- | - | - | 68,729 | ||||||||||||
|
Early extinguishment of debt
|
- | - | - | 15,902 | ||||||||||||
|
Gain on sale of assets
|
- | (17,786 | ) | - | (211,162 | ) | ||||||||||
|
Unrealized warrant derivative (gain) loss
|
- | (290 | ) | (205 | ) | 205 | ||||||||||
|
Foreign transaction gain
|
(4 | ) | (2 | ) | (353 | ) | (3,764 | ) | ||||||||
|
Provision for income tax expense (benefit)
|
- | 4,541 | (804 | ) | 70,317 | |||||||||||
|
ADJUSTED NET INCOME (LOSS)
|
$ | 325 | $ | (748 | ) | $ | (3,292 | ) | $ | (3,160 | ) | |||||
|
ADJUSTED NET INCOME (LOSS) PER SHARE:
|
||||||||||||||||
|
Basic
|
$ | 0.01 | $ | (0.02 | ) | $ | (0.07 | ) | $ | (0.07 | ) | |||||
|
Diluted
|
$ | 0.01 | $ | (0.02 | ) | $ | (0.07 | ) | $ | (0.07 | ) | |||||
|
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
|
||||||||||||||||
|
Basic
|
52,066,371 | 48,994,268 | 49,813,617 | 46,102,662 | ||||||||||||
|
Diluted
|
52,066,371 | 49,277,432 | 49,813,617 | 46,210,424 | ||||||||||||
11
Reconciliation of Cash Flow from Operations Before Working Capital Changes and Special Items:
|
For the Three Months Ended
|
For the Year Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||||||
|
Net income (loss)
|
$ | (2,944 | ) | $ | 12,934 | $ | (12,460 | ) | $ | 48,846 | ||||||
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
||||||||||||||||
|
Depreciation, depletion and amortization
|
3,238 | 2,170 | 9,306 | 16,484 | ||||||||||||
|
Impairment of natural gas and oil properties
|
- | - | - | 68,729 | ||||||||||||
|
Stock-based compensation
|
413 | 780 | 2,765 | 3,547 | ||||||||||||
|
Unrealized natural gas hedge (gain) loss
|
2,679 | (145 | ) | (11,214 | ) | 7,767 | ||||||||||
|
Realized loss (gain) on derivative contracts
|
(167 | ) | (448 | ) | 1,437 | (3,053 | ) | |||||||||
|
Amortization of deferred financing costs and debt discount
|
63 | 329 | 283 | 1,964 | ||||||||||||
|
Accretion of asset retirement obligation
|
104 | 114 | 396 | 379 | ||||||||||||
|
Loss on early extinguishment of debt
|
- | - | - | 7,027 | ||||||||||||
|
Gain on sale of assets
|
- | (17,786 | ) | - | (211,162 | ) | ||||||||||
|
Unrealized warrant derivative (gain) loss
|
- | (290 | ) | (205 | ) | 205 | ||||||||||
|
Litigation settlement payable
|
(18,000 | ) | - | 3,150 | - | |||||||||||
|
Cash flow from operations before working capital changes (1)
|
(14,614 | ) | (2,342 | ) | (6,542 | ) | (59,267 | ) | ||||||||
|
Litigation settlement expense adjusted for payable
|
18,594 | - | 18,594 | - | ||||||||||||
|
Early extinguishment of debt
|
- | - | - | 8,875 | ||||||||||||
|
Foreign transaction gain
|
(4 | ) | (2 | ) | (353 | ) | (3,764 | ) | ||||||||
|
Provision for income tax expense (benefit)
|
- | 4,541 | (804 | ) | 70,317 | |||||||||||
|
Adjusted cash flow from operations for special items
|
$ | 3,976 | $ | 2,197 | $ | 10,895 | $ | 16,161 | ||||||||
(1) Cash flow from operations before working capital changes represents cash flows from operating activities before changes in operating assets and liabilities. We have reported cash flow from operations before working capital because we believe it is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance. Cash flow from operations before working capital changes is not a calculation based on U.S. GAAP and should not be considered an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, which are disclosed in our statements of cash flows. Investors
should carefully consider the specific items included in our computation of cash flow from operations before working capital changes. While we have disclosed our cash flow from operations before working capital to permit a more complete comparative analysis of our operating performance relative to other companies, investors should be cautioned that cash flow from operations before working capital changes as reported by us may not be comparable in all instances to cash flow from operations before working capital changes as reported by other companies.
# # #
12