HOUSTON, Feb. 19, 2014 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial and operating results for the year and fourth quarter ended December 31, 2013.

• Proved Reserves grow by 36% to 452.2 Bcfe, with undiscounted future cash flow of $1.1 billion and PV-10 of $472.3 million. Finding and development cost, as adjusted for 2013 drilling and completion capital expenditures, was $21.07 per barrel of oil equivalent ("BOE") and proved developed finding and development cost, as adjusted for 2013 drilling and completion capital expenditures, was $32.89 per BOE.
• Adjusted EBITDAX was $32.3 million for the quarter and $125.5 million for the year. Discretionary cash flow was $22.0 million for the quarter and $84.1 million for the year.
• Production averaged 80,800 Mcfe per day for the quarter, with 29.4% of volumes coming from oil, which generated 67.4% of revenue.
• Tuscaloosa Marine Shale ("TMS"):
  • The Company's Huff 18-7H-1 well in Amite County, Mississippi reached peak rate from a shortened lateral of 530 BOE per day, comprised of 501 barrels of oil and 174 Mcf of gas on a 13/64 inch choke.
  • Results from the Company's Weyerhaeuser 51H-1 well are delayed due to drilling out the frac plugs (see below).

(PV-10, Adjusted EBITDAX and Discretionary Cash Flow are non-GAAP financial measures; please refer to the "Other Information" section and the accompanying tables at the end of this press release that reconcile PV-10, Adjusted EBITDAX and Discretionary Cash Flow to their most directly comparable GAAP financial measure.)

FINANCIAL RESULTS

REVENUES

Revenues totaled $50.6 million in the quarter versus $48.2 million in the prior year period. Average realized price per unit was $6.81 per Mcfe in the quarter versus $7.24 per Mcfe in the prior year period. When factoring in the realized gain or loss on derivatives not designated as hedges, Adjusted Revenues totaled $50.2 million in the quarter versus $65.4 million in the prior year period, and average realized price per unit was $6.76 per Mcfe versus $9.83 per Mcfe in the prior year period.

(See accompanying tables at the end of this press release that reconciles Adjusted Revenues, a non-GAAP measure, to its most directly comparable GAAP financial measure.)

PRODUCTION

Production totaled 7.4 billion cubic feet equivalent ("Bcfe") in the quarter, or an average of 80,800 Mcfe per day, versus 6.6 Bcfe, or an average of 71,800 Mcfe per day in the prior year period. Oil production totaled 364,000 barrels of oil in the quarter, or an average of approximately 3,950 barrels per day, versus 329,000 barrels of oil, or an average of approximately 3,580 barrels per day, in the prior year period. Production for the quarter was negatively affected by delays in the TMS trend. Production for the year was 27.8 Bcfe, or an average of 76,100 Mcfe per day, versus 31.4 Bcfe, or an average of 85,800 Mcfe per day in the prior year period. Crude oil production for the year totaled 1.3 million barrels of oil, a 22% increase over 2012, and 19.8 Bcf of natural gas, or an average of 54,100 Mcf per day.

The Company anticipates producing between 3,800 – 4,200 Bbls/d of oil and 48,000 – 50,000 Mcf/d of natural gas during the first quarter of 2014. The Company anticipates capital expenditures between $45 – $60 million in the first quarter with approximately 75% allocated towards drilling and completing wells in the TMS.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $32.3 million in the quarter, compared to $50.5 million in the prior year period. Adjusted EBITDAX for the year was $125.5 million versus $184.0 million in the prior year period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $22.0 million in the quarter, compared to $39.9 million in the prior year period. DCF was $84.1 million for the year, versus $141.5 million in the prior year period. Net cash provided by operating activities for the year was $71.4 million, compared to $173.8 million for the prior year period.

Adjusted EBITDAX and DCF were both impacted by a $0.4 million realized loss on derivatives not designated as hedges during the quarter compared to a $17.1 million realized gain on derivatives not designated as hedges during the prior year period. For the year, Adjusted EBITDAX and DCF were both impacted by a $3.8 million realized loss on derivatives not designated as hedges compared to a $73.2 million realized gain on derivatives not designated as hedges 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 a net loss applicable to common stock of $30.9 million in the quarter, or ($0.73) per basic share, versus a net loss applicable to common stock of $77.2 million, or ($2.12) per basic share in the prior year period. Adjusted net loss applicable to common stock was $23.9 million for the quarter, or ($0.57) per basic share, which excludes the impact of unrealized losses on derivatives not designated as hedges of $0.7 million, loss on extinguishment of debt of $2.3 million and dry hole costs on the Company's initial TMS well drilled in 2012 due to casing failure of $4.1 million. The Company announced a net loss applicable to common stock of $113.8 million for the year, or ($2.99) per basic share, versus a net loss applicable to common stock of $90.2 million, or ($2.48) per basic share in the prior year period. Adjusted net loss applicable to common stock was $105.6 million for the year, or ($2.77) per basic share, which excludes the impact of unrealized gains on derivatives not designated as hedges of $3.1 million, loss on extinguishment of debt of $7.1 million and dry hole costs of $4.4 million.

(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.)

OPERATING EXPENSES

Lease operating expense ("LOE") was $7.1 million in the quarter, or $0.96 per Mcfe, versus $4.7 million, or $0.71 per Mcfe, in the prior year period, which included $1.6 million, or $0.22 per Mcfe, for workovers performed in the quarter, versus $0.9 million, or $0.13 per Mcfe, in the prior year period. For the year, LOE totaled $27.3 million, or $0.98 per Mcfe, versus $25.9 million, or $0.83 per Mcfe in the prior year period, which included $6.0 million, or $0.22 per Mcfe, for workovers, versus $4.3 million, or $0.13 per Mcfe, in the prior year period. The majority of the Company's workover expense pertained to wells in the Eagle Ford Shale trend.

Production and other taxes were $1.8 million in the quarter, or $0.25 per Mcfe, versus $2.4 million, or $0.36 per Mcfe, in the prior year period. For the year, production and other taxes totaled $9.8 million, or $0.35 per Mcfe, versus $8.1 million, or $0.26 per Mcfe, in the prior year period, which was primarily driven by increasing oil volumes in the Eagle Ford Shale trend and the absence of production tax credits on natural gas wells in Louisiana and Texas.

Transportation and processing expense was $2.7 million in the quarter, or $0.36 per Mcfe, versus $2.8 million, or $0.43 per Mcfe, in the prior year period. For the year, transportation and processing expense totaled $10.5 million, or $0.38 per Mcfe, versus $13.9 million, or $0.44 per Mcfe, in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense was $32.6 million in the quarter, or $4.38 per Mcfe, versus $37.1 million, or $5.62 per Mcfe, in the prior year period. The decline in quarterly DD&A expense per unit of production was driven by higher mid-year 2013 reserves and lower capital expenditures per well in the Eagle Ford Shale trend. For the year, DD&A expense totaled $135.4 million, or $4.87 per Mcfe, versus $141.2 million, or $4.50 per Mcfe, for the prior year period, which was driven by more production coming from the oil-focused Eagle Ford Shale trend compared to 2012.

Exploration expense was $5.8 million in the quarter, or $0.78 per Mcfe, versus $16.4 million, or $2.48 per Mcfe, in the prior year period. For the year, exploration expense totaled $22.8 million, or $0.82 per Mcfe, versus $23.1 million, or $0.74 per Mcfe, in the prior year period. Approximately $4.1 million, or 71% of the exploration expense for the quarter, was associated with the remaining dry hole expense related to the mechanical failure of the Company's initial well drilled in 2012, the Denkmann 33-28 H-1, in the TMS trend.

General and Administrative ("G&A") expense was $8.7 million in the quarter, or $1.18 per Mcfe, versus $7.2 million, or $1.09 per Mcfe, in the prior year period. During the quarter, the Company incurred $0.6 million of non-recurring G&A expense in connection with the closing of its Shreveport, Louisiana land office and the associated employee severance and relocation expenses. G&A expense related to non-cash, stock based compensation for its employees totaled $2.5 million in the quarter, or $0.33 per Mcfe, versus $2.2 million, or $0.33 per Mcfe, in the prior year period. For the year, G&A expense totaled $34.1 million, or $1.23 per Mcfe, versus $28.9 million, or $0.92 per Mcfe, in the prior year period. For the year, G&A expense related to non-cash, stock based compensation totaled $7.7 million, or $0.28 per Mcfe, versus $6.9 million, or $0.22 per Mcfe, in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $8.1 million in the quarter, versus an operating loss of $67.1 million in the prior year period, which was negatively impacted by $45.2 million of non-recurring, non-cash impairment expenses in the prior year period. For the year, operating income totaled a loss of $36.3 million, versus an operating loss of $63.7 million in the prior year period.

(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 totaled $12.1 million in the quarter, or $1.63 per Mcfe, versus $13.1 million, or $1.98 per Mcfe, in the prior year period. Non-cash interest expense, associated with the Company's debt, totaled $2.7 million (representing 23% of total interest expense) in the quarter, or $0.37 per Mcfe, versus $3.4 million, or $0.52 per Mcfe, in the prior year period. For the year, interest expense totaled $51.2 million, or $1.84 per Mcfe, versus $52.4 million, or $1.67 per Mcfe, in the prior year period. For the year, non-cash interest expense, representing 25% of total interest expense, totaled $12.7 million, or $0.46 per Mcfe, versus $12.8 million, or $0.41 per Mcfe, in the prior year period.

CAPITAL EXPENDITURES

Capital expenditures totaled $50.8 million in the quarter, of which $38.3 million was spent on drilling and completion costs, $9.0 million on leasehold acquisition and $3.5 million on facilities, capital workovers and other expenditures. For the year, capital expenditures totaled $255.0 million, of which $212.4 million was spent on drilling and completion costs, $38.4 million on leasehold and property acquisitions and $4.2 on facilities, capital workovers and other expenditures. Drilling and completion expenditures of $212.4 million were comprised of $112.7 million, or 53%, for wells that had new reserve additions in 2013, $45.6 million, or 21%, for the conversion of 10 proved undeveloped reserve locations to proved developed reserves and $54.1 million, or 26%, for wells in progress at year-end and carry-over drilling and completion costs from wells drilled in prior years.

YEAR-END RESERVES

The Company's proved oil and natural gas reserves as of December 31, 2013 increased by 36% to 452.2 Bcfe, versus 333.1 Bcfe in the prior year period. The Company incurred positive reserve revisions of 90.9 Bcfe on mostly natural gas reserves in Northwest Louisiana and East Texas areas, that became economic under 2013 SEC pricing. The Company spent $192.4 million of adjusted net drilling and completion capital, adding 54.8 Bcfe of proved reserves, resulting in an adjusted organic finding and development cost of $3.51 per Mcfe ($21.07 per BOE). Year-end proved reserves were 73% natural gas, 27% oil and liquids and 39% developed. The future net cash flows of the reserves was $1.1 billion and the PV-10 was $472.3 million, using SEC pricing of $3.67 per MMBtu for natural gas, $96.94 per barrel of oil and $31.44 per barrel of natural gas liquids.

(Year-end PV-10 of proved reserves is a non-GAAP financial measure; please refer to the "Other Information" section for additional disclosure and information.)

The following table reflects the changes in the proved reserve estimates since year-end 2012:

The reserve report was prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company had a net loss of $1.1 million on its derivatives not designated as hedges in the quarter, versus a net gain of $4.6 million during the prior year period. For the year, the Company had a net loss of $0.7 million on its derivatives not designated as hedges, versus a net gain of $31.9 million during the prior year period.

At year-end 2013, the Company had 1,500 Bbls/d committed under an extendable contract for 2014 at $99.77 per Bbl that was not exercised at the counterparty's election. For calendar year 2014, the Company has a total of 3,800 Bbls/d firmly swapped at a blended price of $93.65 per Bbl, which includes 2,500 Bbls/d swapped at a NYMEX crude oil price of $93.18 per Bbl and 1,300 Bbls/d swapped at a LLS crude oil price of $94.55 per Bbl.

With regard to natural gas, at year-end 2013 the Company had 20,000 MMBtu/d committed under an extendable contract for 2014 at $5.35 per MMBtu that was not extended at the counterparty's election. For 2014, the Company has 30,000 MMBtu/d firmly swapped at a NYMEX natural gas price of $4.76 per MMBtu.

LIQUIDITY

The Company exited the year with $49.2 million in cash, $51.8 million of restricted cash and no outstanding borrowings under its senior credit facility, providing approximately $320 million of available liquidity as the Company entered 2014. The Company's borrowing base is currently $270 million, with a new borrowing base redetermination expected in the second quarter of 2014. The Company expects to finance its 2014 capital expenditure budget with cash on hand, cash flow from operations and available capacity on its senior credit facility.

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 4 gross (3 net) wells, of which 1 gross (0.67 net) were in the Eagle Ford and 3 gross (2.6 net) were in the TMS trend. A total of 7 gross (4.7 net) wells were added to production during the quarter, of which 4 gross (2.7 net) were in the Eagle Ford Shale trend, 1 gross (0.9 net) was in the TMS trend, and 2 gross (1 net) were previously cased wells in our non-operated joint-venture in the Haynesville Shale trend. For the year, the Company conducted drilling operations on 25 gross (16 net) wells and added 43 gross (24 net) wells to production. The wells added to production during the year consisted of 23 gross (15 net) in the Eagle Ford Shale trend, 7 gross (3 net) in the TMS trend, 1 gross (1 net) previously cased well in the ART/Shelby Trough and 12 gross (5 net) previously cased wells in our non-operated joint-venture in the Haynesville Shale trend.

The Company has set a $375 million capital expenditure budget for 2014. In the TMS, the Company has preliminary plans, subject to continued success, to spend $300 million to drill 32 gross (23 net) wells, which is predicated on an increasing rig count throughout 2014, resulting in five operated rigs running by the second half of 2014. In the Eagle Ford Shale trend, the Company plans to spend $45 million to drill 9 gross (6 net) wells, and in the Haynesville Shale, plans to drill one gross and net well on its ART / Shelby Trough acreage by mid-2014. The Company plans to spend approximately $15 million on leasehold, acquisitions and infrastructure in 2014.

Tuscaloosa Marine Shale:

The Company has completed its Huff 18-7H-1 (97% WI) well in Amite County, Mississippi. Previously announced workover operations to clean out an obstruction at approximately 500 feet in the lateral were unsuccessful. However, the well is currently producing and had a peak 24-hour production rate of 530 BOE per day, comprised of 501 barrels of oil and 174 Mcf of gas on a 13/64 choke. The Huff well landed in the Company's upper target in the TMS.

The Company drilled its Weyerhaeuser 51H-1 (66.7% WI) well approximately three miles south of previously drilled Weyerhaeuser wells in St. Helena Parish, Louisiana. The well was successfully drilled in the Company's lower target with a lateral length of approximately 6,200 feet and was fracture stimulated with 23 stages. The well initially flowed back through permanent frac plugs at high frac fluid rates on similar choke sizes to other wells in the field, but over time showed signs of plugging off on a portion of the lateral. As a result, the Company is currently drilling out the frac plugs prior to returning the well to production.

The Company is currently fracking its CMR 8-5 H-1 (100% WI) in Amite County, Mississippi, which is a 5,300 foot lateral with 20 planned frac stages. The CMR 8-5 H-1 well landed in the Company's lower target in the TMS.

The Company is currently drilling its Blades 33H-1 (66.7% WI) well in Tangipahoa Parish, Louisiana and its CH Lewis 30-19H-1 (81.4% WI) well in Amite County, Mississippi. A third operated rig is expected in the field in early March.

The Company currently has in excess of 300,000 net acres in the TMS.

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, Cash operating margin and year-end pretax present worth of proved reserves discounted at 10%, or "PV-10". Management believes Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income, Adjusted net loss applicable to common stock and Cash operating 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 DCF, 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 also believes that year-end PV-10 of proved reserves discounted at 10% is a helpful comparative indicator of proved reserves from company to company without regard to an individual company's tax position, as is taken into account in reducing PV-10 by the discounted amount of estimated future income tax expense, resulting in the GAAP-required standardized measure of discounted future net cash flows ("SMOG"). The Company's discounted future income taxes are estimated to be $4.1 million at December 31, 2013 to arrive at a SMOG of $468.1 million. 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 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.

CONTACT: Robert C. Turnham, Jr., President, or Jan L. Schott, Chief Financial Officer, or Daniel E. Jenkins, Director of Investor Relations, +1-713-780-9494