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

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") increased 6% sequentially and decreased 2% over the prior year period to $48.0 million in the quarter, compared to $45.2 million in the second quarter of 2012 and $49.1 million in the prior year period. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, increased by 6% sequentially and decreased 5% over the prior year period to $36.9 million in the quarter, compared to $34.8 million in the second quarter of 2012 and $39.0 million in the prior year period.   

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

NET INCOME

The Company announced net income applicable to common stock of $10.9 million for the quarter, or $0.30 per basic share, versus net income applicable to common stock of $12.1 million, or $0.34 per basic share in the prior year period.  The Company had an adjusted net loss applicable to common stock of $8.3 million, or an adjusted net loss of $0.23 per basic share, when adjusted for the gain on sale of assets of $44.2 million and unrealized loss on derivatives of $24.9 million for the quarter.

(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 7.8 billion cubic feet equivalent ("Bcfe"), or an average of 84,400 thousand cubic feet equivalent ("Mcfe") per day, versus 10.7 Bcfe, or an average of 116,200 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 on a Mcfe basis for the quarter decreased 7% sequentially, as a result of a 11% decline in natural gas production volumes due to the Company's drilling and completion capital expenditures being allocated exclusively to oil directed activity.  Oil production volumes averaged approximately 3,200 barrels of oil per day for the quarter and natural gas liquids averaged 1,400 per day for the quarter.  Production for the fourth quarter of 2012 is expected to average between 71,600 – 80,200 Mcfe per day, with oil production expected to average between 3,600 – 4,200 barrels of oil per day, or 27 – 35% of total production, with an additional 8 gross (5 net) wells expected to be completed and added to production in the fourth quarter of 2012.  The oil production exit rate is now expected to be approximately 4,500 barrels of oil per day, down from the previously announced guidance of 5,000 barrels per day, due to the sale of the South Henderson field and expected production delays from two Tuscaloosa Marine Shale wells.

REVENUES

Revenues for the quarter were $46.0 million versus $55.5 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $18.8 million for the quarter, would have been $64.8 million.  Average realized price per unit for the quarter was $2.87 per Mcf and $97.43 per barrel of oil, or $5.92 per Mcfe, versus $5.20 per Mcfe in the prior year period.  Including the realized gain on derivatives of $18.8 million for the quarter, the average realized price per unit was $5.60 per Mcf and $105.63 per barrel of oil, or $8.34 per Mcfe, versus $5.97 per Mcfe in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") decreased sequentially to $6.2 million in the quarter, or $0.80 per Mcfe, versus $6.7 million, or $0.81 per Mcfe in the prior quarter. LOE in the prior year period was $5.4 million, or $0.51 per Mcfe.  The increase in LOE expense versus the prior year period was primarily due to increased oil-focused drilling and production activity in the Eagle Ford Shale Trend, which has higher LOE than most of the Company's dry gas assets.  LOE, excluding workovers, was $5.8 million, or $0.75 per Mcfe, for the quarter.

Production and other taxes decreased sequentially to $1.7 million in the quarter, or $0.22 per Mcfe, versus $2.1 million, or $0.25 per Mcfe in the prior quarter. Production and other taxes in the prior year period was $1.6 million, or $0.15 per Mcfe.  The increase in production and other taxes from the prior year period was driven by higher oil production volumes, which carry higher production tax rates. 

Transportation and processing expense decreased sequentially to $3.4 million in the quarter, or $0.44 per Mcfe, versus $3.5 million, or $0.43 per Mcfe in the prior quarter. Transportation and processing expense in the prior year period was $2.8 million, or $0.26 per Mcfe.  Transportation and processing expense for the quarter as compared to the prior year period 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 $37.3 million in the quarter, or $4.80 per Mcfe, versus $37.3 million, or $3.49 per Mcfe in the prior year period.  Increased DD&A expense per unit of production was primarily 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, and lower production levels coming from the Haynesville Shale Trend, which carries a lower DD&A rate on a volume equivalent basis. The Company adjusted its DD&A rate for the second half of the year upon receipt of its mid-year reserve report.

Exploration expense was $2.5 million in the quarter, or $0.32 per Mcfe, versus $2.0 million, or $0.24 per Mcfe in the prior quarter and $1.6 million, or $0.15 per Mcfe in the prior year period.  The increase in exploration expense compared to the prior quarter was due to seismic expenditures of $0.6 million, or $0.08 per Mcfe.  Approximately $1.3 million ($0.17 per Mcfe), or 52% of exploration expense for the quarter, was a non-cash expense associated with the amortization of the Company's undeveloped leasehold.   

General and Administrative ("G&A") expense was $7.1 million in the quarter, or $0.92 per Mcfe, versus $6.7 million, or $0.81 per Mcfe in the prior quarter and $6.3 million, or $0.58 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 $1.7 million, or $0.22 per Mcfe, versus $1.3 million, or $0.13 per Mcfe in the prior year period. 

OPERATING INCOME

Operating income, defined as revenues less operating expenses, was $31.9 million in the quarter, versus operating income of $0.2 million in the prior year period.  When adding in realized gain on derivatives not designated as hedges of $18.8 million, adjusted operating income increased by 604% sequentially to $50.7 million for the quarter, versus $7.2 million in the second quarter of 2012. When adjusting for the gain on sale of asset for the quarter of $44.2 million, adjusted operating income was $6.5 million for the quarter.

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

INTEREST EXPENSE

Interest expense for the quarter was $13.3 million, or $1.71 per Mcfe, versus $13.0 million, or $1.22 per Mcfe in the prior year period.  Non-cash interest expense associated with the amortization of debt issuance cost and discount on the Company's long term debt comprised 24% of the total, or $3.1 million ($0.40 per Mcfe).

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $18.8 million on its derivatives not designated as hedges and an unrealized loss of $24.9 million, for a net loss on derivatives of $6.1 million for the quarter.

During 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 fourth quarter of 2012 to 3,500 barrels of oil per day at a blended average price of $100.14 per barrel.  The Company hedged an additional 500 barrels of oil per day for 2013 at $95.85 per barrel, bringing the total hedged oil volumes for 2013 to 1,500 barrels of oil per day with straight swaps at a blended average price of approximately $97.17 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 down 22% sequentially to $57.8 million, of which $51.3 million was spent on drilling and completion costs, $3.3 million on acreage acquisitions, $1.8 million on facility costs and $1.4 million on other expenditures.  Capital expenditures for the first nine months of the year were $193.5 million, of which $164.7 million was spent on drilling and completion costs, $21.3 million on acreage acquisitions, $4.2 million on facility costs and $3.3 million on other expenditures.  

For the quarter, the Company spent approximately $44.3 million, or 77% of its capital, in the Eagle Ford Shale Trend where the Company had two rigs running during the quarter, and $10.9 million, or 19%, in the Tuscaloosa Marine Shale Trend, for a total of $55.2 million, or 96%, of its total capital on oil-directed activity.  Of the $10.9 million spent in the Tuscaloosa Marine Shale Trend, approximately $1.4 million was spent on leasehold, which was accounted for in our previously disclosed $27.5 million leasehold and infrastructure budget.    

For the quarter, the Company conducted drilling operations on 13 gross (8 net) wells, added 6 gross (4 net) wells to production and had 18 gross (9 net) wells waiting on completion at the end of the quarter. The Company added 6 gross (4 net) wells to production from the Eagle Ford Shale Trend, with 5 gross (3 net) wells waiting on completion.

LIQUIDITY

The Company exited the quarter with $1.6 million in cash and $99.0 million drawn on its senior bank revolving credit facility, under which the Company currently has a borrowing base of $210 million, yielding approximately $113 million of liquidity. 

OPERATIONAL UPDATE

Tuscaloosa Marine Shale Trend ("TMS")

The Company has fraced its initial operated well, the Denkmann 33 H-1, with 12 successful frac stages, but flowback has been delayed due to the need to repair a casing connection.  Flowback will commence upon completion of the repair and installation of tubing.

The Company has drilled, cored and logged the vertical portion of its Crosby 12H-1 (50% WI) in Wilkinson County, MS, with plans for a 7,000 foot lateral.  In addition, the Company has participated in two additional non-operated wells, the Joe Jackson 4H-2 (25% WI) in Wilkinson County, MS, which is currently flowing back, and the Ash 31 H-1 (19% WI) in Amite County, MS, which is in completion phase.  The Ash 31 H-1 is the first well in which the lateral was landed just above the zone that has caused wellbore instability, with a very favorable outcome, which if repeatable should materially reduce drilling costs going forward.

The Company anticipates running one rig in the TMS into the first quarter of 2013, and potentially adding or reallocating a second rig to the play in 2013 pending continued success.   

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale Trend, the Company conducted drilling operations on 10 gross (7 net) wells in the quarter, and expects to conduct drilling operations on approximately 12 gross (8 net) wells in the fourth quarter of 2012, which would bring the total to 32 gross (21 net) wells drilled for the year.  The Company has reduced its drill time on recent wells by approximately 40% to 11 days for an average 6,400 foot lateral, which has increased the well count for the year.  The Company added 6 gross (4 net) wells to production for the quarter, and expects to add 8 gross (5 net) wells to production in the fourth quarter of 2012, which would bring the yearly total to 26 gross (17 net) wells added to production.  The Company expects to have approximately 7 gross (5 net) wells waiting on completion at year end due primarily to timing issues related to its pad drilling.  The Company is currently running two operated rigs in the Eagle Ford Shale Trend.

Pearsall Shale

The Company owns deep rights to approximately 10,000 net acres prospective for the Pearsall Shale on its Eagle Ford Shale Trend acreage.  The Company is in the preliminary planning stage for an early first quarter of 2013 Pearsall well on its acreage in Frio County near a recently reported well that tested at approximately 1,800 BOE per day (75% liquids).  

Haynesville Shale Trend

The Company now expects to complete 13 gross (6 net) previously drilled Haynesville Shale wells in the first half of 2013, comprised of 12 gross (5 net) non-operated wells in North Louisiana and 1 gross (1 net) operated well in the Angelina River Trend.  Total capital expenditures are expected to be approximately $22 million to complete these wells.  Assuming timely completion, the Company expects to grow gas volumes during 2013 from these completions by approximately 10%.  The Company expects to give additional guidance in connection with the disclosures of its intended 2013 capital expenditure budget in December.

South Henderson Divestiture

On September 28, 2012, the Company sold its interest in non-core properties in the South Henderson field in Rusk County, Texas for $95 million, with an effective date of July 1, 2012.  During the quarter, production from the South Henderson field averaged approximately 9,600 Mcf/d of natural gas and 200 Bbls/d of oil net to the Company.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, including Adjusted EBITDAX, DCF, 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.

Unless otherwise stated, oil production volumes include condensate.

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 for the year ended December 31, 2011 and other subsequent 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