GASTAR EXPLORATION REPORTS
FIRST QUARTER 2011 RESULTS
HOUSTON, May 5, 2011 – Gastar Exploration Ltd. (NYSE Amex: GST) today reported financial and operating results for the three months ended March 31, 2011.
Net loss for the first quarter of 2011 was $1.9 million, or $0.03 per share. Excluding the impact of an unrealized natural gas hedging loss of $1.9 million and other special items, adjusted net loss was $38,000, or $0.00 per share. This compares to net income of $9.4 million, or $0.19 per diluted share, for the first quarter of 2010. Excluding an unrealized natural gas hedging gain of $9.4 million and other special items, adjusted net loss for the first quarter of 2010 was $1.3 million, or $0.03 per share. See the accompanying reconciliation of net income and earnings per share to these non-GAAP financial measures at the end of this news release.
Our cash flow provided by operations before working capital changes and adjusted for special items was $4.5 million for the first quarter of 2011 compared to $2.4 million for the first quarter of 2010. Our cash flow provided by operating activities was $1.6 million for the first quarter of 2011 compared to $7.8 million for the first quarter of 2010. See the accompanying reconciliation of cash flow before working capital changes to these non-GAAP financial measures at the end of this news release.
Natural gas and oil revenues increased 48% to $10.0 million in the first quarter of 2011, up from $6.8 million for the same period a year ago. The increase in revenues was the result of a 29% increase in realized commodity prices combined with a 15% increase in volumes. Average daily production was 22.6 million cubic feet of natural gas equivalent (MMcfe) for the first quarter of 2011, compared to 19.6 MMcfe per day for the same period in 2010.
During the first quarter of 2011, approximately 89% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was an increase of $2.5 million in revenues and resulted in an increase in total price received from $3.35 per thousand cubic feet (Mcf) to $4.62 per Mcf. We continue to maintain an active hedging program covering a substantial portion of our future natural gas production.
Lease operating expense (LOE) was $1.7 million in the first quarter of 2011, which is unchanged from a year ago. LOE per Mcf equivalent (Mcfe) of production decreased to $0.84 in the first quarter of 2011, compared to $0.99 per Mcfe during the first quarter of 2010. The decrease in the rate per Mcfe was primarily due to lower ad valorem taxes of $0.09 per Mcfe, lower workover costs of $0.07 per Mcfe and higher production volumes.
Depreciation, depletion and amortization (DD&A) was $4.1 million in the first quarter of 2011, up from $1.7 million in the first quarter of 2010. The increase in DD&A expense was the result of a 106% increase in the DD&A rate per Mcfe and a 15% increase in production. The DD&A rate for the first quarter of 2011 increased primarily due to higher proved costs associated with recent wells drilled to test oil prospects and limited initial reserve increases related to these activities. The first quarter 2010 DD&A rate partially benefitted from the gathering system sales proceeds credited to proved property costs in the fourth quarter of 2009.
General and administrative expense (G&A) was $2.9 million in the first quarter of 2011 compared to $3.8 million for the same period in 2010, and includes non-cash stock-based compensation expense of $705,000 and $759,000, respectively. The decrease in G&A was primarily due to lower legal fees as a result of the Classic Star litigation settlement in November 2010.
Operations Review and Update
East Texas
In East Texas, first quarter net production from the Hilltop area averaged 20.4 MMcfe per day, down from 23.8 MMcfe per day in the fourth quarter of 2010. The lower volumes were due to natural declines in field production that were not offset by incremental production from newly completed wells during the first quarter.
During 2011, we are continuing to test the potential for oil production from the Eagle Ford Shale/Woodbine (Eaglebine) and Glen Rose formations on our East Texas acreage with a focus on determining the optimum drilling and completion techniques.
In January, we began drilling the Wildman 7H horizontal well to test the Eaglebine, but drilling issues resulted in what we believe to be an incomplete test of the targeted zone. The well is currently producing approximately 40 barrels of oil per day (BOPD) and a substantial amount of water. We have opted to delay additional operations on the well and the drilling of an additional test nearby until we have completed the analysis of a core sample taken from the Eaglebine section of the Belin #3 well, which is a lower Bossier well currently being drilled in a nearby location.
Also during the first quarter, we drilled the Wildman 8H, a horizontal Glen Rose well, and the Williams #2, a vertical well to test both the Eaglebine and Glen Rose formations. Both wells were fracture stimulated in the Glen Rose and completed in late February. Wildman 8H production currently averages approximately 160 BOPD and approximately 200 barrels of fracture stimulation fluids per day on artificial gas lift. We are encouraged by initial results but plan to monitor the well’s performance for a period of time before proceeding with further horizontal development of the Glen Rose formation. The Williams #2, which was initially flowing naturally after stimulation, has been placed on artificial lift and is currently producing approximately 6 BOPD. Later this year, we plan additional Glen Rose perforations and ultimately will commingle the Glen Rose and Eaglebine in the Williams #2 well.
As previously stated, our 2011 drilling activity in East Texas targeting gas producing zones will primarily be focused on meeting lease obligations.
The Belin #2 well, an exploration well testing the deep Bossier in a separate fault block near the Belin #1, was drilled during the first quarter, and the lowest drilled formation zone was fracture stimulated in April. Production from this initial zone was marginal and a bridge plug has been set to enable us to test shallower zones. We plan to fracture stimulate a zone up the hole in the lower Bossier this month. Although production from this zone cannot be assured, well log interpretation and pressure response following perforation in this zone are comparable to other lower Bossier wells completed with initial high production rates.
In late March, we began drilling the Belin #3 well and expect to reach the target depth of 19,600 feet in early July. Assuming the well is successful, we expect to have it fracture stimulated and on production by late summer.
In addition, in mid-April, we recompleted the Streater #1 well in an uphole zone that achieved an initial production rate of 3.5 MMcf per day, and we plan to commingle the new production with production from a lower zone at a later date.
Capital expenditures in East Texas were $15.8 million for the first quarter of 2011, and we expect to spend approximately $36.2 million in this area for the full year 2011.
Appalachia
In Appalachia, we currently have two rigs operating in Marshall County, West Virginia. In late April we began drilling the Corley #1 and the Wengerd 7H, both horizontal Marcellus wells within our Atinum Joint Venture. Fracture stimulations of the previously drilled Wengerd 1H, along with the Wengerd 7H, are expected to commence in June, with first production expected in August.
We plan to immediately drill five additional Corley wells from the Corley #1 location; fracture stimulation operations are scheduled to begin in September, and first production from the Corley wells is expected in late October.
Drilling operations are continuing on seven horizontal Marcellus wells in Butler County, Pennsylvania, that Gastar and Atinum are participating in with Rex Energy as operator. Initial sales are expected in the fourth quarter of this year.
Outside our Atinum Joint Venture, we intend to drill the Hickory Ridge 2H horizontal Marcellus well in Preston County, West Virginia, with drilling operations anticipated to commence in June. This will be our first test of our acreage acquired in December 2010 in an area we are calling “Marcellus East,” with the objective of further de-risking the acreage and providing data to aid further development by us or with a potential partner.
Capital expenditures net to Gastar for the first quarter in Appalachia were $8.1 million, and we expect to spend approximately $43.9 million for the full year 2011, of which $23.7 million will be spent on drilling and completions and the remaining $20.2 million on land and seismic.
J. Russell Porter, Gastar's President and CEO, stated, “Our increasing level of drilling activity in the liquids-rich areas of the Marcellus Shale and our continued analysis and testing of the production potential for oil on our East Texas acreage should position us for much higher liquids production volumes in late 2011 and in 2012. During 2011, we hope to be able to reduce our DD&A rate per Mcf and improve our net financial results as we benefit from the impact of the Atinum Joint Venture under which we pay 12.5% of the cost of the well for a 50% interest. Additionally, we believe that as we proceed with operations in East Texas and accumulate more data, we will be able to prove up more oil reserves on our acreage.
“Throughout 2011, our plan is to continue to de-risk our portfolio and better understand the production potential, along with continuing to improve the drilling and completion techniques needed to optimize our return on investment. We are encouraged by what we have achieved thus far in 2011 in both East Texas and in Appalachia, and we are looking forward to an active second half of 2011 that should result in significantly higher production levels as well as proven reserve increases,” Porter said.
Liquidity and Capital Budget
At March 31, 2011, the Company had cash and cash equivalents of $12.5 million and a net working capital deficit of approximately $3.8 million, including $7.5 million of operated prepayment liability. Currently, $27.5 million is available under the Company’s Revolving Credit Facility.
Planned capital expenditures for the remainder of 2011 are projected to be approximately $59.4 million, consisting of drilling, completion and infrastructure costs of $15.4 million in East Texas and $22.4 million in Appalachia and an additional $15.7 million in lease acquisition costs, $3.1 million for seismic and $2.8 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, funding from Atinum for our joint venture projects, availability under our revolving credit facility, possible debt or equity issuance and/or a possible joint venture for the development of a portion of our acreage.
Conference Call
Gastar Exploration’s management team will hold a conference call Friday, May 6, at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss these results. To participate in the call, dial 480-629-9867 and ask for the Gastar Exploration conference call. A replay will be available and will be accessible through May 13. To access the replay, dial 303-590-3030 and enter the pass code 4435574#.
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.
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 Marcellus Shale in the Appalachian area of West Virginia and central and southwestern Pennsylvania and in the deep Bossier gas play in the Hilltop area of East Texas. We also conduct limited 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 -
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
| | | For the Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (in thousands, except share and per share data) | |
| REVENUES: | | | | | | |
| Natural gas and oil revenues | | $ | 10,028 | | | $ | 6,758 | |
| Unrealized natural gas hedge gain (loss) | | | (1,899 | ) | | | 9,378 | |
| Total revenues | | | 8,129 | | | | 16,136 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Production taxes | | | 109 | | | | 123 | |
| Lease operating expenses | | | 1,707 | | | | 1,743 | |
| Transportation, treating and gathering | | | 1,103 | | | | 1,249 | |
| Depreciation, depletion and amortization | | | 4,112 | | | | 1,731 | |
| Accretion of asset retirement obligation | | | 125 | | | | 95 | |
| General and administrative expense | | | 2,880 | | | | 3,832 | |
| Total expenses | | | 10,036 | | | | 8,773 | |
| | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | | | (1,907 | ) | | | 7,363 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Interest expense | | | (32 | ) | | | (78 | ) |
| Investment income and other | | | 2 | | | | 792 | |
| Unrealized warrant derivative gain | | | - | | | | 148 | |
| Foreign transaction gain | | | 2 | | | | 319 | |
| | | | | | | | | |
| INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES | | | (1,935 | ) | | | 8,544 | |
| | | | | | | | | |
| Provision for income tax expense (benefit) | | | - | | | | (849 | ) |
| | | | | | | | | |
| NET INCOME (LOSS) | | $ | (1,935 | ) | | $ | 9,393 | |
| | | | | | | | | |
| NET INCOME (LOSS) PER SHARE: | | | | | | | | |
| Basic | | $ | (0.03 | ) | | $ | 0.19 | |
| Diluted | | $ | (0.03 | ) | | $ | 0.19 | |
| | | | | | | | | |
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | | |
| Basic | | | 63,024,481 | | | | 48,997,016 | |
| Diluted | | | 63,024,481 | | | | 49,486,656 | |
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
| | | March 31, 2011 | | | December 31, 2010 | |
| | | (Unaudited) | | | | |
| | | (in thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 12,524 | | | $ | 7,439 | |
| Accounts receivable, net of allowance for doubtful accounts of $566 and $571, respectively | | | 5,711 | | | | 4,034 | |
| Commodity derivative contracts | | | 9,060 | | | | 10,229 | |
| Prepaid expenses | | | 861 | | | | 1,191 | |
| Total current assets | | | 28,156 | | | | 22,893 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| Natural gas and oil properties, full cost method of accounting: | | | | | | | | |
| Unproved properties, excluded from amortization | | | 147,186 | | | | 162,230 | |
| Proved properties | | | 384,253 | | | | 345,042 | |
| Total natural gas and oil properties | | | 531,439 | | | | 507,272 | |
| Furniture and equipment | | | 1,305 | | | | 1,175 | |
| Total property, plant and equipment | | | 532,744 | | | | 508,447 | |
| Accumulated depreciation, depletion and amortization | | | (297,444 | ) | | | (293,332 | ) |
| Total property, plant and equipment, net | | | 235,300 | | | | 215,115 | |
| | | | | | | | | |
| OTHER ASSETS: | | | | | | | | |
| Restricted cash | | | 50 | | | | 50 | |
| Commodity derivative contracts | | | 6,334 | | | | 8,482 | |
| Deferred charges, net | | | 444 | | | | 508 | |
| Drilling advances and other assets | | | - | | | | 304 | |
| Total other assets | | | 6,828 | | | | 9,344 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 270,284 | | | $ | 247,352 | |
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Accounts payable | | $ | 7,313 | | | $ | 8,294 | |
| Revenue payable | | | 4,239 | | | | 4,331 | |
| Accrued interest | | | 191 | | | | 138 | |
| Accrued drilling and operating costs | | | 3,183 | | | | 1,490 | |
| Operated prepayment liability | | | 7,529 | | | | 783 | |
| Commodity derivative contracts | | | 1,370 | | | | 1,991 | |
| Commodity derivative premium payable | | | 3,836 | | | | 3,451 | |
| Accrued litigation settlement liability | | | 2,592 | | | | 3,164 | |
| Other accrued liabilities | | | 1,692 | | | | 2,024 | |
| Total current liabilities | | | 31,945 | | | | 25,666 | |
| | | | | | | | | |
| LONG-TERM LIABILITIES: | | | | | | | | |
| Long-term debt | | | 20,000 | | | | - | |
| Commodity derivative contracts | | | 955 | | | | 1,521 | |
| Commodity derivative premium payable | | | 3,612 | | | | 4,725 | |
| Accrued litigation settlement liability | | | 200 | | | | 800 | |
| Asset retirement obligation | | | 7,552 | | | | 7,249 | |
| Total long-term liabilities | | | 32,319 | | | | 14,295 | |
| | | | | | | | | |
| Commitments and contingencies (Note 12) | | | | | | | | |
| | | | | | | | | |
| SHAREHOLDERS' EQUITY: | | | | | | | | |
| Preferred stock, no par value; unlimited shares authorized; no shares issued | | | - | | | | - | |
| Common stock, no par value; unlimited shares authorized; 64,862,341 and 64,179,115 shares issued and outstanding at March 31, 2011 and December 31, 2010, respectively | | | 316,346 | | | | 316,346 | |
| Additional paid-in capital | | | 23,764 | | | | 23,200 | |
| Accumulated deficit | | | (134,090 | ) | | | (132,155 | ) |
Total shareholders' equity | | | 206,020 | | | | 207,391 | |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 270,284 | | | $ | 247,352 | |
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | For the Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (in thousands) | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income (loss) | | $ | (1,935 | ) | | $ | 9,393 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
| Depreciation, depletion and amortization | | | 4,112 | | | | 1,731 | |
| Stock-based compensation | | | 705 | | | | 759 | |
| Unrealized natural gas hedge (gain) loss | | | 1,899 | | | | (9,378 | ) |
| Realized loss (gain) on derivative contracts | | | (442 | ) | | | 1,039 | |
| Amortization of deferred financing costs and debt discount | | | 64 | | | | 96 | |
| Accretion of asset retirement obligation | | | 125 | | | | 95 | |
| Warrant derivative gain | | | - | | | | (148 | ) |
| Changes in operating assets and liabilities: | | | | | | | | |
| Accounts receivable | | | (1,677 | ) | | | 1,451 | |
| Commodity derivative contracts | | | (54 | ) | | | 1,114 | |
| Prepaid expenses | | | 330 | | | | 71 | |
| Accrued taxes payable | | | - | | | | 1,259 | |
| Accounts payable and accrued liabilities | | | (1,524 | ) | | | 310 | |
| Net cash provided by operating activities | | | 1,603 | | | | 7,792 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Development and purchase of natural gas and oil properties | | | (23,196 | ) | | | (10,830 | ) |
| Proceeds from sale of natural gas and oil properties | | | - | | | | 17,350 | |
| Proceeds from (application of) operated property prepayments | | | 6,746 | | | | (422 | ) |
| Purchase of furniture and equipment | | | (130 | ) | | | (66 | ) |
| Purchase of term deposit | | | - | | | | (6,914 | ) |
| Net cash used in investing activities | | | (16,580 | ) | | | (882 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Repayment of short-term loan | | | - | | | | (17,000 | ) |
| Proceeds from revolving credit facility | | | 20,000 | | | | - | |
| Other | | | 62 | | | | (39 | ) |
| Net cash provided by (used in) financing activities | | | 20,062 | | | | (17,039 | ) |
| | | | | | | | | |
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | | | 5,085 | | | | (10,129 | ) |
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | | | 7,439 | | | | 21,866 | |
| CASH AND CASH EQUIVALENTS, END OF PERIOD | | $ | 12,524 | | | $ | 11,737 | |
GASTAR EXPLORATION LTD. AND SUBSIDIARIES
PRODUCTION AND PRICES
| | | For the Three Months Ended | |
| | | March 31, | |
| | | 2011 | | | 2010 | |
| | | | | | | |
| Production: | | | | | | |
| Natural gas (MMcf) | | | 1,966 | | | | 1,753 | |
| Oil (MBbl) | | | 11 | | | | 2 | |
| Total production (MMcfe) | | | 2,031 | | | | 1,764 | |
| | | | | | | | | |
| Total (MMcfed) | | | 22.6 | | | | 19.6 | |
| | | | | | | | | |
| Average sales price per unit: | | | | | | | | |
| Natural gas per Mcf, excluding impact of realized hedging activities | | $ | 3.35 | | | $ | 4.35 | |
| Natural gas per Mcf, including impact of realized hedging activities | | | 4.62 | | | | 3.78 | |
| Oil per Bbl | | | 88.05 | | | | 72.01 | |
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 March 31, | |
| | | 2011 | | | 2010 | |
| | | (in thousands, except share and per share data) | |
| NET INCOME (LOSS) AS REPORTED | | $ | (1,935 | ) | | $ | 9,393 | |
| SPECIAL ITEMS: | | | | | | | | |
| Unrealized natural gas hedge (gain) loss | | | 1,899 | | | | (9,378 | ) |
| Unrealized warrant derivative (gain) loss | | | - | | | | (148 | ) |
| Foreign transaction gain | | | (2 | ) | | | (319 | ) |
| Provision for income tax expense (benefit) | | | - | | | | (849 | ) |
| | | | | | | | | |
| ADJUSTED NET INCOME (LOSS) | | $ | (38 | ) | | $ | (1,301 | ) |
| | | | | | | | | |
| ADJUSTED NET INCOME (LOSS) PER SHARE: | | | | | | | | |
| Basic | | $ | (0.00 | ) | | $ | (0.03 | ) |
| Diluted | | $ | (0.00 | ) | | $ | (0.03 | ) |
| | | | | | | | | |
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | | |
| Basic | | | 63,024,481 | | | | 48,997,016 | |
| Diluted | | | 63,024,481 | | | | 49,486,656 | |
Reconciliation of Cash Flow from Operations Before Working Capital Changes and Special Items:
| | | For the Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income (loss) | | $ | (1,935 | ) | | $ | 9,393 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
| Depreciation, depletion and amortization | | | 4,112 | | | | 1,731 | |
| Impairment of natural gas and oil properties | | | | | | | | |
| Stock-based compensation | | | 705 | | | | 759 | |
| Unrealized natural gas hedge (gain) loss | | | 1,899 | | | | (9,378 | ) |
| Realized loss (gain) on derivative contracts | | | (442 | ) | | | 1,039 | |
| Amortization of deferred financing costs and debt discount | | | 64 | | | | 96 | |
| Accretion of asset retirement obligation | | | 125 | | | | 95 | |
| Unrealized warrant derivative (gain) loss | | | - | | | | (148 | ) |
| Cash flow from operations before working capital changes (1) | | | 4,528 | | | | 3,587 | |
| Foreign transaction gain | | | (2 | ) | | | (319 | ) |
| Provision for income tax expense (benefit) | | | - | | | | (849 | ) |
| Adjusted cash flow from operations for special items | | $ | 4,526 | | | $ | 2,419 | |
_____________________
(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.
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GST-IR
