Exhibit 99.1
808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254
| | | |
| Contact: | | |
| Robert C. Turnham, Jr., President | | Traded: NYSE (GDP) |
| David R. Looney, Chief Financial Officer | | |
FOR IMMEDIATE RELEASE
GOODRICH PETROLEUM ANNOUNCES YEAR END AND FOURTH QUARTER
FINANCIAL RESULTS AND OPERATIONAL UPDATE
| | • | | Production volumes for the year set record and grow 44% over 2006. Production volumes for the quarter increase by 41% versus the prior year period, and increase by 9% sequentially over 3Q07. Guidance of 9-13% sequential growth in 1Q08 |
| |
| | • | | Proved reserves grow by 105% to record level of 358 Bcfe |
| |
| | • | | Drilled 104 Gross (85 Net) Wells in 2007 with a 99% Success Rate |
| |
| | • | | Net Acreage in the Cotton Valley Trend increased by 13% over previous year to approximately 181,000 Gross (115,000 Net) Acres at year end |
Houston, Texas — March 12, 2008. Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the year and fourth quarter ended December 31, 2007.
PRODUCTION
Net production volumes from continuing operations in the quarter increased by approximately 41% to 4.6 billion cubic feet equivalent (“Bcfe”), or approximately 50,500 Mcfe per day, versus 3.3 Bcfe, or approximately 35,900 Mcfe per day, in the prior year period. For the year, net production volumes increased by 44% to 16.0 Bcfe versus 11.1 Bcfe in 2006. Net production volumes for the fourth quarter increased sequentially by approximately 9% versus the third quarter of 2007. Virtually all of net production volumes for the quarter came from Cotton Valley trend wells in East Texas and North Louisiana.
The Company currently expects net daily production volumes will average between 55,000 and 57,000 Mcfe per day for the first quarter of 2008, a 9-13% sequential increase over the fourth quarter of 2007.
YEAR END RESERVES
Pursuant to a fully engineered reserve report from Netherland, Sewell & Associates, Inc., year end proved reserves reached a record 358 Bcfe using the SEC-mandated unescalated pricing on December 31, 2007 of approximately $6.80/MMbtu of natural gas and $92.50/barrel of crude oil, subject to further reductions for quality and basis differentials. At year end 2007, the Company’s reserve to production ratio was approximately 22 years, based on 2007 production. Proved reserves were approximately 97% natural gas and 31% developed, with approximately 99% located in the Cotton Valley trend.
Future net revenue before income tax expense from proved reserves at year end pricing is estimated to be $895 million, with pre-tax present worth discounted at 10% of $313 million. The standardized measure of discounted net cash flows from proved reserves (after income tax expense) was $284 million. At $8.00/MMbtu of natural gas and $65.00/barrel of crude oil and after applying historic differentials, the year end reserves would have been 364 Bcfe, with future net revenue of $1.22 billion and pre-tax present worth discounted at 10% of $472 million.
At $8.00/MMbtu of natural gas and $65.00/barrel of crude oil and after applying historic differentials, the year end reserves would have been 364 Bcfe, with future net revenue of $1.22 billion and pre-tax present worth discounted at 10% of $472 million.
Proved reserves grew by approximately 105% versus the year end 2006 proved reserves of 175 Bcfe attributable to the Company’s continuing operations (the Company sold the majority of its South Louisiana properties in March of 2007, which had proved reserves of 32 Bcfe in the year end 2006 report). Reserve growth in 2007 was achieved exclusively through organic growth with the drill bit in the Cotton Valley trend. When including all revisions in the calculation, the Company replaced approximately 1150% of its 2007 net production volumes of approximately 16.0 Bcfe.
Year end 2007 all-in finding and development cost (“F&D”), being defined as 2007 drilling, completion and acquisition capital expenditures of $274.2 million, which excludes capital costs associated with undeveloped leasehold acquisition and facility costs of approximately $26 million, divided by proved reserve additions, including revisions, was $1.38 per Mcfe. When factoring in estimated future drilling and completion expenditures of $414.0 million associated with proved undeveloped reserves added in 2007, total finding cost for all proved reserve additions for 2007 was $3.46 per Mcfe.
NET INCOME
Net income applicable to common stock for the fourth quarter of 2007 was a loss of $22.1 million ($(0.83) per share) which compares to a fourth quarter 2006 loss of $23.9 million ($(0.96) per share). Results for the fourth quarter of 2007 included a $3.0 million non-cash loss on derivatives not qualifying for hedge accounting (comprised of a $1.1 million realized gain and a $4.1 million unrealized loss) and a $7.8 million non-cash impairment charge to oil and gas properties at year end 2007 as a result of impairments at the Company’s Alabama Bend and Gilmer fields, two non-core step out areas, as well as at a South Louisiana property currently in discontinued operations. For the full year 2007, GDP reported a loss applicable to common stock of $51.1 million, which included a $6.4 million non-cash loss on derivatives not qualifying for hedge accounting, versus a loss applicable to common stock of $5.9 million for 2006.
CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration (“EBITDAX”), increased 73% to approximately $19.7 million for the fourth quarter, compared to $11.4 million in the prior year period. EBITDAX for the year increased 81% to $74.6 million, compared to $41.6 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities).
Discretionary cash flow, defined as net cash provided by operating activities before changes in working capital, increased to $15.7 million in the quarter, compared to $14.2 million in the prior year period. Discretionary cash flow increased to $68.1 million for the year, compared to $60.2 million in the prior year period (note that DCF, is not adjusted for discontinued operations). Net cash provided by operating activities was $85.9 million for the year, compared to $65.1 million for the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).
REVENUES
Total revenues for the quarter increased by 61% to $32.5 million, versus $20.2 million for the prior year period. Revenues for the quarter increased by 19% sequentially over the third quarter of 2007. Average net oil and gas prices received in the quarter were $6.60 per Mcf of gas and $89.60 per barrel of oil. Total revenues and average prices received in the fourth quarter do not include realized gains of $1.1 million received on the Company’s settled oil and gas derivatives, all of which were ineffective during the quarter.
Total revenues for the year increased by 49% to $111.3 million versus $74.8 million for the prior year period. Average net oil and gas prices received for the year were $6.69 per Mcf of natural gas and $71.83 per barrel of oil, versus $6.42 per Mcf of natural gas and $62.03 per barrel of oil from the previous period. Total revenues and average prices received during the year do not include realized gains of $9.5 million received on the Company’s settled oil and gas derivatives, all of which were ineffective for the entirety of the year.
OPERATING INCOME
Operating income, defined as revenues minus operating expenses, totaled a loss of $13.6 million for the quarter versus an operating loss of $13.4 million for the prior year period, primarily due to the relatively high DD&A rate incurred by the Company during the period. Operating income for the year was a loss of $35.2 million versus an operating loss of $15.3 million in the prior year.
OPERATING EXPENSES
Operating expenses were $46.1 million during the quarter, including the previously mentioned impairment charges. Lease operating expenses (LOE) totaled $7.0 million in the quarter, or $1.50 per Mcfe, versus $4.4 million, or $1.44 per Mcfe during the fourth quarter of 2006. The LOE exit rate for December 2007 was $1.03 per Mcfe for core LOE and $0.20 per Mcfe for workovers, for a total of $1.23 per Mcfe. The increase in LOE for the quarter was primarily related to increased salt water disposal costs as a result of drilling success and higher production volumes coming from fields in which the Company does not currently have low pressure gathering and salt water disposal systems. For the year, LOE totaled $22.5 million in 2007, or $1.40 per Mcfe, versus $12.7 million, or $1.14 per Mcfe in 2006, with the increase due primarily to the same reasons as those impacting the fourth quarter differences. First quarter 2008 guidance for LOE is between $1.10 and $1.30 per Mcfe for core LOE and $0.15 per Mcfe for workovers, for a total of $1.25-$1.45 per Mcfe. The Company expects to have salt water disposal facilities in place in the North Minden field and Cotton South area of the Angelina River trend by the third quarter of 2008, which will reduce per unit LOE going forward.
General and Administrative (G&A) expenses were $5.0 million during the quarter, or $1.08 per Mcfe, versus $5.0 million, or $1.63 per Mcfe during the similar quarter in 2006. G&A expenses were down on a per unit basis over the prior year period as the Company grew production volumes while holding absolute
G&A expenses relatively flat. For the year, G&A expenses totaled $20.9 million, or $1.31 per Mcfe, versus $17.2 million, or $1.55 per Mcfe for the full year 2006, with the absolute increase in the year over year period due primarily to higher staffing levels associated with the Company’s increased levels of activity and a $1 million Louisiana franchise tax payment made under protest in April of 2007. For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers, employees and directors of $1.0 million. For the full year, the Company recorded non-cash G&A expense related to stock based compensation of approximately $5.3 million, or approximately 25% of total G&A for the year.
CAPITAL EXPENDITURES
The Company conducted drilling or completion operations on 104 gross (85 net) wells in 2007 with a 99% success rate. The Company had to permanently abandon one well during the year for mechanical reasons, otherwise the results would have been 100% successful.
Capital expenditures for the quarter and year totaled $84.4 million and $300.2 million respectively, compared to $70.7 million and $269.5 million in the prior year’s quarter and year respectively. Approximately 97%, or $82.2 million of the capital expenditures in the quarter and approximately 91%, or $274.2 million of the capital expenditures for the year were associated with drilling and completion costs, with $18.9 million incurred on 164 wells either drilled in previous years or in the process of drilling for which no proved reserves were booked at December 31, 2007. Of the drilling and completion capital expenditures, virtually all were associated with wells drilled and completed in the Cotton Valley trend.
For the year 2008, the Company has preliminarily budgeted total capital expenditures of approximately $275.0 million, of which approximately 89%, or $245.0 million, is expected to be focused on the drilling program in the Cotton Valley trend of East Texas and North Louisiana, where the Company plans to average nine rigs working throughout 2008. The remainder of the $30.0 million budgeted amount is earmarked for lease acquisitions, gathering and facilities, and other capital expenditures.
LIQUIDITY
The Company expects to finance its 2008 capital expenditures through a combination of cash flow from operations, borrowings under its existing bank credit facility and the proceeds from recent debt and equity offerings of $200.0 million. Upon closing on the second lien term loan in January and paying down revolver debt with the proceeds, the Company had no outstanding borrowings under its revolving credit facility. In conjunction with the second lien term loan, the terms of the credit facility required the borrowing base to be reduced to $142.5 million until the re-determination associated with the receipt of the Company’s year end 2007 reserve report. Given the growth in the Company’s proved reserves, including proved developed reserves, the Company expects the borrowing base to be returned to at least the levels previously intact before entering into the second lien term loan. This increase, along with future borrowing base increases resulting from the Company’s ongoing drilling program, are expected to provide sufficient funding, when combined with the Company’s cash flow from operations, such that the Company will not have to access additional capital markets until well into 2009, assuming continued commodity price levels and budgeted capital expenditures. In addition, the Company continues to evaluate the potential sale of certain assets as an additional source of liquidity.
OPERATIONAL UPDATE
DRILLING
The Company completed and added to production 36 Cotton Valley trend wells during the quarter, four of which produced for the entire quarter. Through year end the Company had drilled and logged a total of 257 wells, with a success rate in excess of 99%. The Company has had 9 drilling rigs under contract since early 2007.
During 2007, the Company drilled seven 20-acre spaced wells located in the Beckville and North Minden fields, with average estimated ultimate recoverable proved reserves of approximately 1.1 Bcfe per well. With these results, the Company intends to continue development on 20-acre spacing and further refine its inventory of drilling locations and probable and possible reserve exposure to reflect 20-acre spacing potential for Beckville and the Southeastern portion of North Minden.
ACREAGE
At year end, the Company had 181,600 gross (114,800) net acres in the Cotton Valley trend in eight counties in Texas and three parishes in Louisiana, which currently yields approximately 2,000 possible drilling locations. The Company continues to seek additional opportunities to expand its inventory in resource plays similar to the Cotton Valley trend.
OPERATING EXPENSES
The Company is planning for separate low pressure gathering systems with salt water disposal capabilities in additional fields, including the southeastern portion of North Minden, where the Company is drilling in-field development wells, and Cotton South in the Angelina River trend, where the Company expects 2 to 3 rigs running in 2008. Since salt water disposal is the highest component of LOE, and a substantially higher percentage of the Company’s production volumes are coming from these areas, the Company expects a meaningful reduction in per unit LOE coming from these areas with the installation of the gathering and disposal systems.
CORE PROPERTIES
Bethany-Longstreet Field, Caddo and DeSoto Parishes, Louisiana. The Company is currently drilling its Champe Graham 5H well, the second horizontal Cotton Valley well in the field, which is an offset to the previous horizontal Cotton Valley well drilled, the Champe Graham 3H. Results are expected in approximately 60 days.
In addition, the Company has taken one of its vertical wells, the James Cook 1, to the Haynesville formation to evaluate the Bossier Shale, an emerging play in Northwest Louisiana. Electric and mud log results are encouraging with good gas shows and correlation with recent wells adjacent to the Company’s acreage. The Company is currently monitoring offset activity and evaluating its acreage, with the potential to test the Bossier Shale at a future date.
Longwood Field, Caddo Parish, Louisiana.The Company has drilled and completed its initial well on its Longwood acreage, the A.C. Mitchell 1H, a horizontal Cotton Valley well targeting the Sexton formation of the Cotton Valley sands. The well, which has been online for approximately 40 days, had an initial daily production rate during flowback of approximately 2,000 Mcf per day, an average of approximately 1,900 Mcf per day for the first 30 days and a current rate of approximately 1,900 Mcf per day.
The Company expects to drill a second well on its Longwood acreage in the second quarter, with additional plans to evaluate the Bossier Shale.
Angelina River Trend, Nacogdoches and Angelina Counties, Texas.The Company has drilled and completed its LB Mast 1H, its third James Lime horizontal well on its Cotton Prospect in the Angelina River trend. The well was drilled with a 4,880 foot lateral and successfully fracture stimulated eight stages, with a 24 hour initial production rate of 8,000 Mcf per day. The Company has a 57% working interest in the well, and plans to drill approximately 10 wells on its Cotton Prospect acreage during 2008.
The Company has also drilled and completed its Bethune A-1H, its initial James Lime horizontal well on its Bethune Prospect. The well was drilled with a 4,400 foot lateral and is currently in flowback stage, but early flowback results to date indicate inferior results compared to the Cotton Prospect wells drilled to date.
The Company has permitted and intends to drill its initial James Lime horizontal well on its Cotton South Prospect acreage during the second quarter.
MANAGEMENT COMMENTS
Commenting on the results, the Company’s Vice-Chairman and CEO Walter G. “Gil” Goodrich, Vice Chairman and CEO stated, “During 2007, we made tremendous progress through the execution of our strategy to aggressively exploit our asset base and rapidly grow production volumes and reserves. We succeeded in converting a meaningful amount of previously non-proven 2P and 3P reserves into the proven category, while also stepping out and proving up newer areas of our acreage position. We drilled and completed a record 104 wells during the year, all in the Cotton Valley trend, which allowed us to grow production volumes by 44% compared to 2006 and to report a 107% increase in year end proved reserves of 358 Bcfe. In addition, we sold substantially all of our interests in South Louisiana, which allowed us to focus entirely on the Cotton Valley trend. We further tested the economic viability of horizontal drilling and downspacing in our core areas, with some encouraging results in both cases. During the year we also initiated development of the James Lime horizontal play in the Angelina River trend, which adds significant upside potential to our core Cotton Valley/Travis Peak (Hosston) program, thereby enhancing shareholder value in the process. In 2008, we will continue with the aggressive development of our core Cotton Valley acreage, where approximately 75% of our capital is planned to be allocated, test newly acquired acreage, further test the viability of horizontal drilling and continue to prove up economic reserves from 20-acre spaced vertical wells. We are committed to our strategy of expanding our position and developing our significant asset base in the trend, as evidenced by our continued nine-rig drilling program and $275 million budget for the year. In addition, the financings we have completed over the past few months have us well positioned to continue with our aggressive drilling plans which will further mature and enhance the value of our existing acreage.”
OTHER INFORMATION
In this press release, the Company refers to two non-GAAP financial measures, EBITDAX and discretionary cash flow. Management believes that each of these measures is a good financial indicator of the Company’s ability to internally generate operating funds. Management also believes that these non-GAAP financial measures of cash flow provide useful information to investors because they are widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry. Neither discretionary cash flow nor EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by GAAP.
The Company has provided the alternative proved reserve estimates in this release assuming natural gas prices other than those in effect on December 31, 2007 solely for illustrative purposes to demonstrate hypothetically the effect that year end economic conditions have on the Company’s proved reserve estimates. The natural gas price used in one of these alternative presentations was selected by management based upon a review of longer term forward trading prices on the NYMEX. The United States Securities and Exchange Commission (SEC) has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under economic and operating conditions existing at the date of the report. Accordingly, the SEC guidelines may prohibit us from including these alternatively priced proved reserve estimates in filings with the SEC.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
Certain statements in this news release regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of the Securities Litigation Reform Act. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company’s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.
Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange. The majority of its properties are in Louisiana and Texas.
GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Year Ended | |
| | | December 31, | | | December 31, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 32,477 | | | $ | 20,224 | | | $ | 111,305 | | | $ | 74,771 | |
| | | | | | | | | | | | | | | | | |
| Operating Expenses | | | | | | | | | | | | | | | | |
| Lease operating expense | | | 6,965 | | | $ | 4,414 | | | | 22,465 | | | | 12,688 | |
| Production and other taxes | | | 1,276 | | | | 322 | | | | 2,272 | | | | 3,345 | |
| Transportation | | | 1,734 | | | | 1,074 | | | | 5,964 | | | | 3,791 | |
| Depreciation, depletion and amortization | | | 22,163 | | | | 11,538 | | | | 79,766 | | | | 37,225 | |
| Exploration | | | 1,499 | | | | 1,453 | | | | 7,346 | | | | 5,888 | |
| Impairment of oil and gas properties | | | 7,414 | | | | 9,886 | | | | 7,696 | | | | 9,886 | |
| General and administrative | | | 4,996 | | | | 4,975 | | | | 20,888 | | | | 17,223 | |
| Other | | | 67 | | | | (23 | ) | | | 67 | | | | (23 | ) |
| | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (13,637 | ) | | | (13,415 | ) | �� | | (35,159 | ) | | | (15,252 | ) |
| | | | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | | | |
| Interest expense | | | (3,938 | ) | | | (3,139 | ) | | | (11,870 | ) | | | (7,845 | ) |
| Gain (loss) on derivatives not qualifying for hedge accounting | | | (2,964 | ) | | | 3,517 | | | | (6,439 | ) | | | 38,128 | |
| Loss on early extinguishment of debt | | | — | | | | (612 | ) | | | — | | | | (612 | ) |
| | | | | | | | | | | | | | | | | |
| | | | (6,902 | ) | | | (234 | ) | | | (18,309 | ) | | | 29,671 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations before income taxes | | | (20,539 | ) | | | (13,649 | ) | | | (53,468 | ) | | | 14,419 | |
| Income tax (expense) benefit | | | 345 | | | | 4,659 | | | | (3,034 | ) | | | (5,120 | ) |
| Income (loss) from continuing operations | | | (20,194 | ) | | | (8,990 | ) | | | (56,502 | ) | | | 9,299 | |
| | | | | | | | | | | | | | | | | |
| Discontinued operations: | | | | | | | | | | | | | | | | |
| Gain (loss) on disposal, net of tax | | | (161 | ) | | | — | | | | 9,662 | | | | — | |
| Income (loss) from discontinued operations, net of tax | | | (271 | ) | | | (13,442 | ) | | | 1,807 | | | | (7,660 | ) |
| | | | (432 | ) | | | (13,442 | ) | | | 11,469 | | | | (7,660 | ) |
| | | | | | | | | | | | | | | | | |
| Net income (loss) | | | (20,626 | ) | | | (22,432 | ) | | | (45,033 | ) | | | 1,639 | |
| Preferred stock dividends | | | 1,512 | | | | 1,512 | | | | 6,047 | | | | 6,016 | |
| Preferred stock redemption premium | | | — | | | | — | | | | — | | | | 1,545 | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) applicable to common stock | | $ | (22,138 | ) | | $ | (23,944 | ) | | $ | (51,080 | ) | | $ | (5,922 | ) |
| | | | | | | | | | | | | | | | | |
| Income (loss) per common share from continuing operations | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.75 | ) | | $ | (0.36 | ) | | $ | (2.21 | ) | | $ | 0.37 | |
| Diluted | | $ | (0.75 | ) | | $ | (0.36 | ) | | $ | (2.21 | ) | | $ | 0.37 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) per common share from discontinued operations | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.02 | ) | | $ | (0.54 | ) | | $ | 0.45 | | | $ | (0.30 | ) |
| Diluted | | $ | (0.02 | ) | | $ | (0.54 | ) | | $ | 0.45 | | | $ | (0.31 | ) |
| | | | | | | | | | | | | | | | | |
| Net income (loss) per common share applicable to common stock | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.83 | ) | | $ | (0.96 | ) | | $ | (2.00 | ) | | $ | (0.24 | ) |
| Diluted | | $ | (0.83 | ) | | $ | (0.96 | ) | | $ | (2.00 | ) | | $ | (0.24 | ) |
| | | | | | | | | | | | | | | | | |
| Weighted average common shares outstanding: | | | | | | | | | | | | | | | | |
| Basic | | | 26,771 | | | | 25,016 | | | | 25,578 | | | | 24,948 | |
| Diluted | | | 26,771 | | | | 25,016 | | | | 25,578 | | | | 25,412 | |
| | | | | | | | | | | | | | | | | |
GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Year Ended | |
| | | December 31, | | | December 31, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | |
| Calculation of EBITDAX: | | | | | | | | | | | | | | | | |
| Revenue | | | 32,477 | | | | 20,224 | | | | 111,305 | | | | 74,771 | |
| Lease operating expense | | | (6,965 | ) | | | (4,414 | ) | | | (22,465 | ) | | | (12,688 | ) |
| Production and other taxes | | | (1,276 | ) | | | (322 | ) | | | (2,272 | ) | | | (3,345 | ) |
| Transportation | | | (1,734 | ) | | | (1,074 | ) | | | (5,964 | ) | | | (3,791 | ) |
| G&A — cash portion only | | | (3,964 | ) | | | (2,707 | ) | | | (15,606 | ) | | | (11,261 | ) |
| Realized gain (loss) on derivatives not qualifying for hedge accounting | | | 1,141 | | | | (298 | ) | | | 9,640 | | | | (2,057 | ) |
| | | | | | | | | | | | | | | | | |
| EBITDAX | | | 19,679 | | | | 11,409 | | | | 74,638 | | | | 41,629 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of EBITDAX to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| EBITDAX | | | 19,679 | | | | 11,409 | | | | 74,638 | | | | 41,629 | |
| EBITDAX — Discontinued Operations | | | 32 | | | | 6,475 | | | | 5,779 | | | | 27,615 | |
| Exploration | | | (1,499 | ) | | | (1,453 | ) | | | (7,346 | ) | | | (5,888 | ) |
| Prospect amortization | | | 1,116 | | | | 1,579 | | | | 6,211 | | | | 5,488 | |
| Interest expense | | | (3,938 | ) | | | (3,139 | ) | | | (11,870 | ) | | | (7,845 | ) |
| Other non-cash items | | | 259 | | | | (691 | ) | | | 658 | | | | (768 | ) |
| Net changes in working capital | | | 8,688 | | | | 1,310 | | | | 17,855 | | | | 4,902 | |
| | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities (GAAP) | | | 24,337 | | | | 15,490 | | | | 85,925 | | | | 65,133 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| Discretionary cash flow | | | 15,649 | | | | 14,180 | | | | 68,070 | | | | 60,231 | |
| Net changes in working capital | | | 8,688 | | | | 1,310 | | | | 17,855 | | | | 4,902 | |
| Net cash provided by operating activities (GAAP) | | | 24,337 | | | | 15,490 | | | | 85,925 | | | | 65,133 | |
| | | | | | | | | | | | | | | | | |
| Selected Operating Data: | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Year Ended | |
| | | December 31, | | | December 31, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | |
| Production — Continuing Operations: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 4,435 | | | | 2,910 | | | | 15,281 | | | | 10,500 | |
| Oil and condensate (MBbls) | | | 34 | | | | 25 | | | | 118 | | | | 106 | |
| Total (Mmcfe) | | | 4,642 | | | | 3,059 | | | | 15,991 | | | | 11,135 | |
| | | | | | | | | | | | | | | | | |
| Average sales price per unit: | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 6.60 | | | $ | 6.44 | | | $ | 6.69 | | | $ | 6.42 | |
| Oil (per Bbl) | | | 89.60 | | | | 53.14 | | | | 71.83 | | | | 62.03 | |
| Natural gas and oil (Mcfe) | | | 6.97 | | | | 6.56 | | | | 6.92 | | | | 6.64 | |
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| Expenses per Mcfe: | | | | | | | | | | | | | | | | |
| Lease operating expense | | $ | 1.50 | | | $ | 1.44 | | | $ | 1.40 | | | $ | 1.14 | |
| DD&A | | | 4.77 | | | | 3.77 | | | | 4.99 | | | | 3.34 | |
| Exploration | | | 0.32 | | | | 0.47 | | | | 0.46 | | | | 0.53 | |
| General and administrative expense | | | 1.08 | | | | 1.63 | | | | 1.31 | | | | 1.55 | |
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