Goodrich Petroleum Announces Third Quarter Financial and Operational Results

HOUSTON, Nov. 3, 2011 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial and operating results for the quarter ended September 30, 2011.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX"), increased by 75% to $49.1 million for the quarter, compared to $28.1 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).  EBITDAX was 12% higher sequentially.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $39.0 million for the quarter, compared to $27.4 million in 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).  DCF increased by 17% sequentially.  

NET INCOME

The Company announced net income applicable to common stock of $12.1 million for the quarter, or $0.34 per basic share, versus a net loss applicable to common stock of $226.6 million, or $6.31 per basic share in the prior year period.  The prior year period was negatively affected by non-cash impairment expense of $234.9 million.

PRODUCTION

Net production volumes in the quarter increased by 27% to 10.7 billion cubic feet equivalent ("Bcfe"), or an average of 116,200 Mcfe per day, versus 8.4 Bcfe, or an average of approximately 91,700 Mcfe per day in the prior year period.  Average net daily production volumes for the quarter were up 3% sequentially from the second quarter of 2011.  Oil production increased by 518% over the prior year period and 50% sequentially to an average of 2,215 barrels of oil per day for the quarter.

Production is expected to average 108,000 – 112,000 Mcfe per day in the fourth quarter of 2011, due to an approximate 40% reduction in capital expenditures for the quarter, along with pipeline curtailment issues in the Eagle Ford Shale, which is expected to reduce volumes by approximately 5,000 Mcfe per day for the quarter.  The curtailment is expected to be rectified in January of 2012.  Oil production is expected to grow sequentially by 15 – 25% in the fourth quarter, or an average of 2,500 – 2,800 barrels of oil per day which would comprise approximately 13.5 – 15.5% of total volumes for the quarter.  

Full year 2011 production guidance is confirmed at an average of 108,000 – 112,000 Mcfe per day, a 15 – 25% increase over 2010.

REVENUES

Revenues for the quarter were $55.5 million versus $37.4 million in the prior year period.  Adjusted revenues, including realized gain on derivatives not designated as hedges of $8.3 million for the quarter, was $63.8 million (see accompanying table for a reconciliation of adjusted revenues, a non-GAAP measure, to revenues).  Average realized price per unit for the quarter, prior to factoring in the Company's realized hedging gains, was $5.20 per Mcfe, versus $4.44 per Mcfe in the prior year period.  When factoring in the Company's realized gains, average realized price per unit was $5.97 per Mcfe, versus $5.19 in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") per unit of production decreased by 31% to $5.4 million in the quarter, or $0.51 per Mcfe, versus $6.3 million, or $0.74 per Mcfe in the prior year period.  Per unit LOE for the quarter was flat sequentially.  Lower per unit LOE continued to be driven by the Company's Haynesville Shale wells, which comprised 64% of Company volumes and averaged $0.17 per Mcfe for the quarter.  The Company expects LOE per unit to average $0.55 – $0.65 per Mcfe in the fourth quarter.    

Production and other taxes for the quarter increased on a unit basis by 88% to $1.6 million, or $0.15 per Mcfe, versus $0.7 million, or $0.08 per Mcfe in the prior year period, with the increase driven by higher oil production and lower high cost credits for the quarter. Production and other taxes decreased by 6% sequentially on a unit basis.

Transportation expense on a unit basis decreased by 26% to $2.8 million, or $0.26 per Mcfe in the quarter, versus $3.0 million, or $0.35 per Mcfe in the prior year period. Transportation expense on a unit basis increased by 18% sequentially.

Depreciation, depletion and amortization ("DD&A") expense on a unit basis increased by 13% to $37.3 million, or $3.49 per Mcfe in the quarter, versus $26.0 million, or $3.09 per Mcfe in the prior year period.  DD&A expense for the quarter on a unit basis increased by 16% sequentially due to higher production volumes coming from its Eagle Ford Shale trend, which provides higher cash margins from the associated oil production but carries a higher DD&A rate on a Mcfe basis.  

Exploration expense on a unit basis decreased by 38% to $1.6 million, or $0.15 per Mcfe for the quarter, versus $2.0 million, or $0.24 per Mcfe in the prior year period.  Exploration expense for the quarter on a unit basis decreased by 35% sequentially.  Approximately $1.2 million ($0.11 per Mcfe), or 75% of exploration expense for the quarter, was non-cash expense associated with amortization of the Company's undeveloped leasehold.

General and Administrative ("G&A") expense on a unit basis decreased by 33% to $6.3 million, or $0.58 per Mcfe in the quarter, versus $7.3 million, or $0.86 Mcfe in the prior year period.  Per unit G&A expense decreased by 18% sequentially.  Of the total G&A expense for the quarter, $1.3 million ($0.13 per Mcfe), or 22% of the total, was non-cash expense associated with stock based compensation.  

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled $0.2 million for the quarter versus an operating loss of $238.5 million for the prior year period.  When adding in realized gain on derivatives not designated as hedges of $8.3 million, adjusted operating income for the quarter is $8.5 million (see accompanying table for a reconciliation of adjusted operating income, a non-GAAP measure, to operating income).  Operating income from the prior year period was negatively affected by non-cash impairment.  

OTHER INCOME (EXPENSE)

Interest expense for the quarter was $13.0 million, or $1.22 per Mcfe, versus $9.2 million, or $1.09 per Mcfe in the prior year period.  Non-cash interest expense primarily associated with the Company's convertible notes comprised 27% of the total, or $3.5 million ($0.33 per Mcfe).

Gain (loss) on derivatives not designated as hedges for the quarter was $26.5 million, or $2.47 per Mcfe, versus a gain of $22.5 million, or $2.67 per Mcfe in the prior year period.  The derivative gain for the quarter is comprised of a realized gain of $8.3 million and an unrealized gain of $18.2 million.  The Company currently has a net derivative asset of $41.8 million.

LIQUIDITY

The Company ended the quarter with approximately $32.7 million in cash and cash equivalents and restricted cash, with $79.5 million drawn on its senior credit facility, under which the Company currently has a borrowing base of $275 million, providing $228 million of liquidity.

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $79.9 million, of which $71.9 million was spent on drilling and completion costs, $1.0 million on acreage acquisitions, $5.8 million on facility costs and $1.2 million on other expenditures.  For the quarter, the Company conducted drilling operations on 10 gross (8 net) wells, added 9 gross (5 net) wells to production and had 9 gross (5 net) wells waiting on completion at the end of the quarter.  The Company added 9 gross (5 net) wells from the Eagle Ford Shale trend, with 4 gross (2.5 net) wells waiting on completion.  The Company expects capital expenditures of approximately $50 million in the fourth quarter.

HEDGING

The Company has entered into new derivative contracts for 2,000 barrels of oil per day at an average swap price of $100.20 per barrel and 20,000 MMBtu per day of natural gas at $5.35 per Mcf for calendar year 2012.  The Company now has 1,500 barrels of oil per day (68% of third quarter oil volumes) hedged for the fourth quarter of 2011 at a blended average price of $102.10, and 2,000 barrels of oil per day (90% of third quarter oil volumes) hedged for 2012 at a blended average price of $100.20.  On natural gas, the Company has 40,000 MMBtu per day (39% of third quarter natural gas volumes) hedged for the fourth quarter of 2011 at a blended average floor price of $6.00 per Mcf, and 60,000 MMBtu per day (58% of third quarter natural gas volumes) hedged for 2012 at a blended average floor price of $5.78 per Mcf.  

OPERATIONAL UPDATE

Texas

Eagle Ford Shale, LaSalle and Frio Counties, Texas

The Company completed the following five Eagle Ford Shale wells during the quarter, with an average 24-hour peak production rate of 907 BOE per day:

• Burns Ranch 20H (67% WI), a 5,960 foot lateral with 21 frac stages, at a 24-hour peak production rate of 1,080 barrels oil equivalent ("BOE") per day;    
• Burns Ranch 2H (67% WI), an 8,320 foot lateral with 29 frac stages, at a 24-hour peak production rate of 1,004 BOE per day;
• Burns Ranch 3H (67% WI), a 5,160 foot lateral with 19 frac stages, at a 24-hour peak production rate of 953 BOE per day;
• Burns Ranch 18H (67% WI), a 5,060 foot lateral with 19 frac stages, at a 24-hour peak production rate of 883 BOE per day;
• Burns Ranch 19H (67% WI), a 5,940 foot lateral with 21 frac stages, at a 24-hour peak production rate of 613 BOE per day.

The Company completed two additional Buda Lime wells in the quarter:

• Carnes 7H (65% WI), an un-stimulated 4,215 foot lateral, at a 24-hour peak production rate of 1,167 BOE per day and a 30-day average of 871 BOE per day (762 BO and 655 Mcf per day);
• Burns Ranch 30H (67% WI), a 5,060 foot lateral with 19 frac stages, at a 24-hour peak production rate of 500 BOE per day.

The Company is in completion phase on the following wells:

• Burns Ranch 35H (67% WI), an 8,880 foot lateral with 32 planned frac stages;
• Burns Ranch 16H (67% WI), a 5,710 foot lateral with 20 planned frac stages;
• Burns Ranch 22H (67% WI), a 5,520 foot lateral with 20 planned frac stages;
• Shiner G-1 (67% WI), a 4,190 foot lateral in the Buda Lime;
• Shiner G-4 (67% WI), a 4,130 foot lateral in the Buda Lime;

Angelina River Trend, Nacogdoches and Angelina Counties, Texas  

The Company is scheduled to spud its next well in the field, the ACLCO 1H (100% WI), late November, with an expected completion date in January.

Cotton Valley Taylor Sand, South Henderson Field, Rusk County, Texas

Since the end of the third quarter, the Company completed the following two Cotton Valley Taylor Sand wells at an average 7,854 Mcfe per day (15% oil/condensate):

Rayford – Siler No. 1H (100% WI), a 4,331 foot lateral with 13 frac stages, at a 24-hour peak production rate of 7,997 Mcfe per day, comprised of 6,943 Mcf and 176 barrels of oil per day;

Crow – Holland 1H (100% WI), a 5,011 foot lateral with 15 frac stages, at a 24-hour  peak production rate of 7,712 Mcfe per day, comprised of 6,398 Mcf and 219 barrels of oil per day.  

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, Adjusted EBITDAX, discretionary cash flow, cash operating margin, Adjusted Revenue and Adjusted Operating Income.  We define Adjusted Revenues as revenues plus realized gain (or loss) on derivatives not designated as hedges.  We define cash operating margin as Adjusted EBITDAX divided by Adjusted Revenues.  A full reconciliation of Adjusted EBITDAX and discretionary cash flow to comparable GAAP measure is included with this release.  .

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 the two non-GAAP financial measures of cash flow, Adjusted EBITDAX and discretionary 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 natural gas exploration and production industry. Non-GAAP financial measures should be reviewed in addition to, and not as an alternative for the Company's reported results prepared in accordance to GAAP.

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 and uncertainties, such as availability of drilling rigs and completion crews and equipment, 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. References to prior year periods in this release refer to the comparable quarterly period of the prior calendar year.

Initial production rates stated in this release are expected to differ substantially from longer term average production rates.  “24-hour peak rate” mentioned in this press release is the highest 24-hour production rate for the referenced well.  Forward looking estimates of production growth assume drilling results comparable to recent prior periods, which may not be realized. The Company is commencing its initial operations in the Eagle Ford Shale and the success of its drilling and completion strategy is subject to more uncertainty relative to areas where the Company has already established drilling and production history.

Goodrich Petroleum Corporation is an independent oil and gas exploration and production company listed on the New York Stock Exchange. Substantially all of its properties are located in Louisiana and Texas.

SOURCE Goodrich Petroleum Corporation