Goodrich Petroleum Announces Third Quarter 2014 Financial Results, Non-Core Asset Sale And Operational Update

HOUSTON, Nov. 4, 2014 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial results, the sale of a non-core asset and an operational update for the third quarter ended September 30, 2014. 

FINANCIAL RESULTS:

• Adjusted Revenues totaled $55.1 million in the quarter versus $53.5 million in the prior year period, and average realized price per unit was $9.00 per Mcfe versus $6.91 per Mcfe in the prior year period.
• Earnings before interest, taxes, DD&A, non-cash general and administrative expenses, exploration, and impairment ("Adjusted EBITDAX") totaled $37.1 million for the quarter compared to $34.7 million in the prior year period.
• Oil production averaged approximately 4,800 Bbls/day, a 17% increase over the prior year period.  Oil production grew 15% sequentially over the prior quarter.  Since the end of the third quarter, oil production has averaged approximately 6,000 Bbls/day, which is mid-point of fourth quarter guidance.

NON-CORE ASSET SALE:

• Subsequent to the end of the third quarter, the Company has entered into a definitive agreement to sell its Beckville/Minden assets in Panola and Rusk Counties, Texas for $61.0 million. The agreement is subject to customary terms and conditions with an estimated closing date of December 22, 2014.

TUSCALOOSA MARINE SHALE ("TMS"):

• The Company's Spears 31-6H-1 (77% WI) well in Amite County, Mississippi, has achieved a peak 24-hour production rate to date of approximately 1,360 Boe/day, comprised of 1,290 Bbls of oil (95%) and 420 Mcf of natural gas on a 15/64 inch choke from an approximate 6,210 foot completed lateral with 23 frac stages. 
• The Company's CMR/Foster Creek 24-13H-1 (97% WI) well in Wilkinson County, Mississippi, has achieved a peak 24-hour production rate to date of approximately 1,215 Boe/day, comprised of 1,140 Bbls of oil (94%) and 450 Mcf of natural gas on a 16/64 inch choke from an approximate 6,480 foot completed lateral with 24 frac stages. 

(THE COMPANY HAS POSTED A NEW TMS SLIDE DECK ON THE COMPANY'S WEBSITE AT WWW.GOODRICHPETROLEUM.COM WHICH WILL BE REVIEWED ON THE EARNINGS CALL)

FINANCIAL RESULTS

REVENUES

Revenues totaled $54.9 million in the quarter versus $57.2 million in the prior year period.  Average realized price per unit was $8.96 per Mcfe in the quarter versus $7.38 per Mcfe in the prior year period.  When factoring in the realized gain or loss on derivatives not designated as hedges, Adjusted Revenues totaled $55.1 million in the quarter versus $53.5 million in the prior year period, and average realized price per unit was $9.00 per Mcfe versus $6.91 per Mcfe in the prior year period.

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

PRODUCTION

Production totaled 6.1 billion cubic feet equivalent ("Bcfe") in the quarter, or an average of 66,600 Mcfe/day, versus 7.7 Bcfe, or an average of 83,700 Mcfe/day in the prior year period.  Oil production totaled 439,000 barrels of oil in the quarter and 43% of total production, or an average of approximately 4,800 Bbls/day, versus 374,000 barrels of oil and 29% of total production, or an average of approximately 4,100 Bbls/day, in the prior year period.  Oil production grew 15% sequentially over the prior quarter.  Since the end of the third quarter, oil production has averaged approximately 6,000 Bbls/day and based on timing of pad drilled wells and the Company's frac schedule, the Company expects fourth quarter oil production to average 5,700 – 6,300 Bbls/day.  Natural gas production totaled 3.5 Bcf in the quarter, or an average of approximately 38,000 Mcf/day, versus 5.5 Bcf, or an average of 60,000 Mcf/day, in the prior year period.  The Company anticipates producing 32,000 – 35,000 Mcf/day of natural gas during the fourth quarter of 2014.

CAPITAL EXPENDITURES

Capital expenditures totaled $97.2 million in the quarter for drilling and completion costs, leasehold acquisition, and infrastructure capital.  Approximately 78% of the quarter's total capital expenditures were spent in the TMS drilling and completing wells and extending existing leasehold for future drilling operations.  Capital expenditures for the first nine months of the year totaled $259.5 million.  Capital expenditures for the fourth quarter are expected to be $60 – $75 million, which would have yearly expenditures at the low end of the previously issued guidance range of $325 – $375 million.      

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses, exploration, and impairment ("Adjusted EBITDAX") was $37.1 million in the quarter, compared to $34.7 million in the prior year period. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $26.8 million in the quarter, compared to $24.8 million in the prior year period.  Net cash provided by operating activities was $25.3 million in the quarter, compared to $5.0 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-US GAAP financial measures, to their most directly comparable US GAAP financial measure.)

NET INCOME

The Company announced a net loss applicable to common stock of $87.1 million in the quarter, or ($1.96) per basic share, versus a net loss applicable to common stock of $32.8 million, or ($0.89) per basic share in the prior year period.  Net loss applicable to common stock for the quarter was negatively affected by a non-cash impairment charge of $85.3 million on fields in East Texas that the Company is selling.  Adjusted net loss applicable to common stock was $21.8 million for the quarter, or ($0.49) per basic share, which excludes the impact of unrealized gains on derivatives not designated as hedges of $20.1 million, the impairment charge referenced above and non-cash leasehold expiration of $0.1 million.

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

OPERATING EXPENSES

Lease operating expense ("LOE") was $6.7 million in the quarter, or $1.10 per Mcfe, versus $7.1 million, or $0.92 per Mcfe, in the prior year period.  LOE for the quarter included $0.6 million, or $0.10 per Mcfe, for workovers performed in the quarter, versus $1.6 million, or $0.21 per Mcfe, in the prior year period.  The majority of the Company's workover expense pertained to cleanout operations on wells in the Haynesville Shale trend.     

Production and other taxes were $2.9 million in the quarter, or $0.47 per Mcfe, versus $2.5 million, or $0.32 per Mcfe, in the prior year period. The increase in production and other taxes was due to additional ad valorem taxes associated with new TMS and Eagle Ford Shale trend wells added to production.  Production taxes should decline as we complete more wells in the TMS, where new wells are subject to no or very low production taxes until payout of the well is achieved.    

Transportation and processing expense was $2.1 million in the quarter, or $0.35 per Mcfe, versus $2.8 million, or $0.36 per Mcfe, in the prior year period.    

Depreciation, depletion and amortization ("DD&A") expense was $36.0 million in the quarter, or $5.88 per Mcfe, versus $33.3 million, or $4.33 per Mcfe, in the prior year period.  The increase in DD&A expense was due to increased production volumes and DD&A rates associated with continued production growth from the TMS. 

Exploration expense was $0.9 million in the quarter, or $0.15 per Mcfe, versus $4.1 million, or $0.53 per Mcfe, in the prior year period.  The decrease in exploration expense pertains to less leasehold expiration expense primarily in the Eagle Ford Shale trend.

General and Administrative ("G&A") expense was $8.3 million in the quarter, or $1.36 per Mcfe, versus $8.3 million, or $1.08 per Mcfe, in the prior year period.  G&A expense related to non-cash, stock based compensation totaled $2.0 million in the quarter, or $0.33 per Mcfe, versus $1.7 million, or $0.23 per Mcfe, in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $87.4 million in the quarter, versus an operating loss of $0.9 million in the prior year period.  Adjusted operating loss, when adjusted for realized gain on derivatives not designated as hedges and impairment cost of $85.3 million was $1.9 million for the quarter.   

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

INTEREST EXPENSE

Interest expense totaled $12.6 million in the quarter, or $2.06 per Mcfe, versus $12.7 million, or $1.65 per Mcfe, in the prior year period.  Non-cash interest expense associated with the Company's debt totaled $2.7 million (representing 21% of total interest expense) in the quarter, or $0.44 per Mcfe, versus $3.2 million, or $0.42 per Mcfe, in the prior year period.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $0.2 million and an unrealized gain of $20.1 million, which resulted in a net gain of $20.3 million on its derivatives not designated as hedges in the quarter, versus a net loss of $8.8 million during the prior year period.

For the remainder of 2014, the Company has a total of 3,800 Bbls/day swapped at a blended price of $93.65 per Bbl, which includes 2,500 Bbls/day swapped at a NYMEX crude oil price of $93.18 per Bbl and 1,300 Bbls/day swapped at a LLS crude oil price of $94.55 per Bbl.  For 2015, the Company has a total of 3,500 Bbls/day swapped at an average LLS price of $96.11 per Bbl.      

With regard to natural gas, the Company has 30,000 MMBtu/day swapped at an average NYMEX natural gas price of $4.76 per MMBtu for the remainder of 2014.       

LIQUIDITY

The Company exited the quarter with $2.2 million in cash, $51.8 million of restricted cash and $118 million drawn on its senior credit facility.  In conjunction with the Company's semi-annual redetermination, the borrowing base remained unchanged at $250 million and the Company was in compliance with all financial covenants as of September 30, 2014.  Upon closing the sale of the Company's East Texas assets scheduled for December 22, 2014, the borrowing base will be reduced to $230 million.  The Company expects to finance the remainder of its 2014 capital expenditure budget with cash flow from operations and available capacity on its senior credit facility. 

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 12.0 gross (7.2 net) wells, of which 11.0 gross (6.6 net) were in the TMS and 1.0 gross (0.7 net) were in the Eagle Ford Shale trend.  A total of 9.0 gross (5.5 net) wells were added to production during the quarter, which included 6.0 gross (3.5 net) wells in the TMS and 3.0 gross (2.0 net) wells in the Eagle Ford Shale trend.  As of September 30, 2014, the Company had 3.0 gross (1.8 net) TMS wells drilled and waiting on completion.

Tuscaloosa Marine Shale:

The Company's Spears 31-6H-1 (77% WI) well in Amite County, Mississippi, has achieved a peak 24-hour production rate to date of approximately 1,360 Boe/day, comprised of 1,290 Bbls of oil (95%) and 420 Mcf of natural gas on a 15/64 inch choke from an approximate 6,210 foot completed lateral with 23 frac stages. 

The Company's CMR/Foster Creek 24-13H-1 (97% WI) well in Wilkinson County, Mississippi, has achieved a peak 24-hour production rate to date of approximately 1,215 Boe/day, comprised of 1,140 Bbls of oil (94%) and 450 Mcf of natural gas on a 16/64 inch choke from an approximate 6,480 foot completed lateral with 24 frac stages. 

The Company has commenced completion operations on its Verberne 5H-1 (67% WI) and Williams 46H-1 (61% WI) wells in Tangipahoa Parish, Louisiana, with estimated frac dates occurring in the middle to end of November. The Company anticipates completing and adding to production approximately five gross operated TMS wells throughout the fourth quarter, with the frac dates being back-end loaded.     

The Company currently has three rigs running in the play and is conducting drilling operations on its CMR/Foster Creek 8H-1 and 8H-2 (79% WI) wells in Wilkinson County, Mississippi, Kent 41H-1 (67% WI) well in Tangipahoa Parish, Louisiana and its T. Lewis 7-38H-1 (estimated 90.5% WI) well in Amite County, Mississippi.

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-US GAAP financial measures, including Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income (loss), Adjusted net loss applicable to common stock and Cash operating margin.  Management believes Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income (loss), 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.  None of DCF, Adjusted EBITDAX or Cash operating margin, should be considered an alternative to net cash provided by operating activities, as defined by US GAAP.  Adjusted revenues should not be considered an alternative to total revenues, as defined by US GAAP.  Adjusted operating income (loss) should not be considered an alternative to operating income (loss), as defined by US GAAP.  Adjusted net loss applicable to common stock should not be considered an alternative to net loss applicable to common stock, as defined by US GAAP.  Management believes that all of these non-US 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, 2013 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

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