Goodrich Petroleum Announces Second Quarter 2012 Financial And Operational Results

HOUSTON, Aug. 6, 2012 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the quarter ended June 30, 2012.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") increased 12% sequentially and 3% over the prior year period to $45.2 million in the quarter, compared to $40.4 million in the first quarter of 2012 and $43.7 million in the prior year period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, increased 16% sequentially and 4% over the prior year period to $34.8 million in the quarter, compared to $29.9 million in the first quarter of 2012 and $33.3 million in the prior year period.

Net cash provided by operating activities increased 56% sequentially and 47% over the prior year period to $47.4 million in the quarter, compared to $30.5 million in the first quarter of 2012 and $32.3 million in the prior year period. 

(See accompanying tables at the end of this press release that reconcile adjusted EBITDAX and discretionary cash flow, which are non-GAAP measures to their most directly comparable GAAP financial measure.)

NET INCOME

The Company announced a net loss applicable to common stock of $4.7 million for the quarter, or ($0.13) per basic share, versus a net loss applicable to common stock of $1.4 million, or ($0.04) per basic share in the prior year period.  Adjusted net loss applicable to common stock was $7.5 million, or ($0.21) per basic share.

(See accompanying tables at the end of this press release that reconcile adjusted net loss applicable to common stock, a non-GAAP measure, to its most directly comparable GAAP financial measure.) 

PRODUCTION

Net production volumes for the quarter were 8.3 billion cubic feet equivalent ("Bcfe"), or an average of 91,006 thousand cubic feet equivalent ("Mcfe") per day, versus 10.3 Bcfe, or an average of 113,268 Mcfe per day in the prior year period.  Despite a 17% sequential increase in oil production volumes in the quarter, total average net daily production volumes for the quarter decreased 6% sequentially, due to declining natural gas production volumes due to substantially all of the Company's drilling and completion capital expenditures being allocated to oil-directed activity.  Oil production volumes averaged approximately 2,800 barrels of oil per day for the quarter. Since the end of the quarter, the Company's net oil volumes have averaged approximately 3,500 barrels per day.  Natural gas liquids volumes averaged 1,300 barrels per day for the quarter.  Production for the third quarter of 2012 is expected to average 85,000 – 89,000 Mcfe per day, with oil production expected to average 3,200 – 3,600 barrels of oil per day, or 23% of total production, with an additional 5 gross (3 net) wells completed from two separate pads in September of 2012.

REVENUES

Revenues for the quarter were $41.3 million versus $52.9 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $21.3 million for the quarter, would have been $62.7 million.  Average realized price per unit for the quarter was $2.41 per Mcf of natural gas and $98.96 per barrel of oil, or $5.00 per Mcfe, versus $5.09 per Mcfe in the prior year period.  Including the realized gain on derivatives of $21.3 million for the quarter, the average realized price per unit was $5.26 per Mcf of natural gas and $107.15 per barrel of oil, or $7.58 per Mcfe, versus $5.67 per Mcfe in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") increased to $6.7 million in the quarter, or $0.81 per Mcfe, versus $5.2 million, or $0.51 per Mcfe in the prior year period.  The increase in LOE expense versus the prior year period was primarily due to increased oil-focused drilling activity in the Eagle Ford Shale Trend and additional workover expenditures.  LOE, excluding workovers, was $6.0 million, or $0.73 per Mcfe, for the quarter.

Production and other taxes was $2.1 million in the quarter, or $0.25 per Mcfe, versus $1.6 million, or $0.16 per Mcfe, in the prior year period.  The increase in production and other taxes was driven by higher oil production volumes from the Eagle Ford Shale Trend, which carries a higher production tax rate.

Transportation and processing expense was $3.5 million in the quarter, or $0.43 per Mcfe, versus $2.3 million, or $0.22 per Mcfe in the prior year period.  Transportation and processing expense was impacted by increased processing costs under the previously disclosed East Texas processing agreement for the Minden, Beckville and South Henderson fields.

Depreciation, depletion and amortization ("DD&A") expense was $34.6 million in the quarter, or $4.17 per Mcfe, versus $30.9 million, or $3.00 per Mcfe in the prior year period.Increased DD&A expense was due to higher oil production levels coming from the Company's Eagle Ford Shale Trend, which carries a higher DD&A rate on a volume equivalent basis.  The Company will readjust its DD&A rate for the second half of the year based upon its mid-year reserve report.

Exploration expense was $2.0 million in the quarter, or $0.24 per Mcfe, versus $2.3 million, or $0.23 per Mcfe in the prior year period.  Approximately $1.3 million ($0.15 per Mcfe), or 63% of exploration expense for the quarter was non-cash associated with amortization of the Company's undeveloped leasehold.

General and Administrative ("G&A") expense was $6.7 million in the quarter, or $0.81 per Mcfe, versus $7.3 million, or $0.71 per Mcfe in the prior year period.  For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers and employees of $1.5 million, or $0.18 per Mcfe, versus $1.3 million, or $0.13 per Mcfe in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, was a loss of $14.2 million in the quarter, versus an operating gain of $2.1 million in the prior year period.  When adding in realized gains on derivatives not designated as hedges of $21.3 million, adjusted operating income increased by 324% sequentially to $7.2 million for the quarter, versus $1.7 million in the first quarter of 2012.

(See accompanying tables at the end of this press release that reconcile adjusted operating income, a non-GAAP measure, to its most directly comparable GAAP financial measure.)

INTEREST EXPENSE

Interest expense for the quarter was $13.1 million, or $1.58 per Mcfe, versus $13.0 million, or $1.26 per Mcfe in the prior year period.  Non-cash interest expense associated with the Company's long term debt comprised 24% of the total, or $3.1 million ($0.38 per Mcfe).

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company incurred a realized gain of $21.3 million on its derivatives not designated as hedges and an unrealized gain of $2.7 million, for a net gain of $24.0 million for the quarter.

After the end of the quarter, the Company hedged an additional 500 barrels of oil per day for the remainder of 2012 and 2013 at $92.50 per barrel, bringing the total hedged oil volumes for the second half of 2012 to 3,500 barrels of oil per day at a blended average price of $100.14 per barrel.  For 2013, the Company has 1,000 barrels of oil per day hedged with straight swaps at a blended average price of $97.83 per barrel and 2,500 barrels of oil per day committed under a swaption, to be exercised at the counterparty's option, at $100.82 per barrel.

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $74.3 million, of which $59.0 million was spent on drilling and completion costs, $13.6 million on acreage acquisitions, $1.5 million on facility costs and $0.2 million on other expenditures.  Capital expenditures for the first six months of the year were $135.7 million, of which $115.1 million was spent on drilling and completion costs, $18.0 million on acreage acquisitions, $2.4 million on facility costs and $0.2 million on other expenditures.  With its leasehold acquisition costs largely completed and rig count reduced in the Eagle Ford from three rigs to two rigs, the Company expects to spend approximately $115.0 million in the second half of the year, bringing the yearly capital expenditure estimate to approximately $250.0 million.

For the quarter, the Company spent approximately $54.3 million, or 73% of its capital, in the Eagle Ford Shale Trend where we had 2 – 3 rigs running during the quarter, and $17.5 million, or 24%, in the Tuscaloosa Marine Shale Trend, for a total of $71.9 million, or 97%, of its total capital on oil-directed activity.  Of the $17.5 million spent in the Tuscaloosa Marine Shale Trend, approximately $12.8 million was spent on leasehold, which was included in the Company's previously disclosed $27.5 million leasehold and infrastructure budget. 

For the quarter, the Company conducted drilling operations on 15 gross (10 net) wells, added 10 gross (5 net) wells to production and had 18 gross (9 net) wells waiting on completion at the end of the quarter. The Company added 7 gross (4.5 net) wells to production from the Eagle Ford Shale Trend, with 4 gross (3 net) wells waiting on completion.

The Company expects its 2012 capital expenditures to be approximately $250.0 million, which includes an increase in the number of wells drilled and completed and capital allocated to the Tuscaloosa Marine Shale by approximately $20.0 million, offset by a reduction in capital expenditures of approximately $25.0 million previously allocated to the Angelina River Trend and Eagle Ford Shale Trend, with 5 gross (3 net) fewer Eagle Ford Shale Trend wells completed than previously estimated.

LIQUIDITY

The Company exited the quarter with $2.0 million in cash and $158.0 million drawn on its senior bank revolving credit facility, under which the Company currently has a borrowing base of $265.0 million.  The Company expects to finance its 2012 capital expenditure budget with cash flow from operations and borrowings under its senior bank revolving credit facility. In addition, the Company intends to boost liquidity for 2013 through the asset divestiture of the South Henderson field.

OPERATIONAL UPDATE

South Henderson Divestiture

The Company has entered into a letter of intent to sell its South Henderson field in Rusk County, Texas for $95 million, with an effective date of July 1, 2012 and an estimated closing date of October 1, 2012.  The purchase and sale of the field is contingent upon negotiation of definitive agreements, containing customary terms and conditions. 

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale Trend, the Company conducted drilling operations on 13 gross (9 net) wells and added 7 gross (4.5 net) wells to production for the quarter.  Since the end of the second quarter, the Company has averaged approximately 3,500 barrels of oil per day.  Due to timing of completions, the Company expects to average 3,200 – 3,600 barrels of oil per day for the quarter, with 4 gross (3 net) wells added during July and 5 gross (3 net) wells added in September.  The Company is currently running two operated rigs in the Eagle Ford Shale Trend.

Pearsall Shale Trend

The Company owns deep rights to approximately 10,000 net acres prospective for the Pearsall Shale on its Eagle Ford Shale Trend acreage, and it continues to monitor offset operator activity for potential future development.

Tuscaloosa Marine Shale Trend

The Company is currently drilling its first operated well, the Denkmann 33 H-1(75% WI), with completion scheduled within 30 days, to be followed by the Crosby 12H-1 (75% WI).  The Company has participated in a non-operated well, the Joe Jackson 4H-2 (25% WI), which is scheduled to be fracked in August, and will be participating in two additional non-operated wells, the Ash 31 H-1 (20% WI) and Ash 31 H-2 (20% WI) during the second half of the year.  With the success we have experienced to date, the Company anticipates moving a second rig into the TMS from the Eagle Ford Shale in the second half of the year, with the possibility of running 2 – 3 operated rigs in the TMS in 2013.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, including Adjusted EBITDAX, discretionary cash flow, drilling and completion capital expenditures, adjusted revenues, adjusted operating income, adjusted net loss applicable to common stock and cash operating margin.  Management believes adjusted EBITDAX, discretionary cash flow, adjusted revenues, adjusted operating income, adjusted net loss applicable to common stock and cash margin are good financial indicators of the Company's ability to internally generate operating funds, while drilling and completion capital expenditures are a useful measure of the Company's annual drilling expenditures.  Neither discretionary cash flow, nor adjusted EBITDAX, should be considered an alternative to net cash provided by operating activities, as defined by GAAP.  Adjusted revenues should not be considered an alternative to total revenues, as defined by GAAP.  Adjusted operating income should not be considered an alternative to operating income (loss), as defined by GAAP.  Adjusted net loss applicable to common stock should not be considered an alternative to net loss applicable to common stock, as defined by GAAP.  Nor should drilling and completion capital expenditures be considered an alternative to costs incurred in oil and gas property acquisition, exploration, and development activities, as defined by GAAP.  Management believes that all of these non-GAAP financial measures provide useful information to investors because they are monitored and used by Company management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry. 

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.  In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

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, changes in commodities prices and costs of drilling and completion, 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.

SOURCE Goodrich Petroleum Corporation

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