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Goodrich Petroleum Announces Year-End 2016 Financial Results And Operational Update

THE COMPANY HAS POSTED A NEW PRESENTATION ON THE COMPANY'S WEBSITE WHICH WILL BE REVIEWED ON THE EARNINGS CONFERENCE CALL. INVESTORS CAN ACCESS THE SLIDES AT: http://goodrichpetroleum.investorroom.com/events-and-presentations

Mar 1, 2017

HOUSTON, March 1, 2017 /PRNewswire/ -- Goodrich Petroleum Corporation (OTCQX: GDPP) (the "Company") today announced year-end 2016 financial results and an operational update.

RESERVES

Proved reserves at year-end under SEC pricing grew to 302.9 Bcfe (94% natural gas and 85% undeveloped) from 54.9 Bcfe (58% natural gas and 100% developed) at year-end 2015, driven by proved undeveloped reserve ("PUD") additions in the Haynesville Shale.

Year-end proved reserves at different pricing scenarios are as follows:

PRICING SCENARIOS

RESERVES

PV10




SEC ($2.48/Mmbtu & $42.75/Bbl)

302.9 Bcfe

$57.1 Million

$3.00/Mmbtu & $55.00/Bbl

339.8 Bcfe

$180.0 Million

$3.50/Mmbtu & $55.00/Bbl

347.5 Bcfe

$261.2 Million

 

The Company expects to develop its proved undeveloped reserves over five years under its existing capital structure, subject to market conditions.

CAPITALIZATION

The Company exited the year with $37 million of cash and $58 million in principal debt, or $21 million of net debt.

OPERATIONAL UPDATE (HAYNESVILLE)

The Company has previously announced a combined initial production rate of 72,000 Mcf per day on two 10,000 foot lateral Haynesville wells in Caddo Parish, Louisiana. The ROTC 1H well was completed with 5,200 lbs of proppant per foot with an initial production rate of 40,000 Mcf per day. To date, the wells have produced approximately 4.0 Bcf in a little over two months, or approximately 61,000 Mcf/day, and are currently producing at a combined rate of approximately 61,400 Mcf per day. The wells, in which the Company owns a 17.4% working interest, are producing above the Company's internal high case curve of 2.5 Bcf per 1,000 feet of lateral.

The Company is running one operated rig that is currently drilling its Wurtsbaugh 26H-1 (74% WI) well in DeSoto Parish, Louisiana, a 4,600 foot lateral with a planned completion design of 4-5,000 lbs of proppant per foot. Once finished, the Company is moving the rig to drill its Wurtsbaugh 25-24H-2 (estimated WI of 75-80%) well in DeSoto Parish, with a planned 10,000 foot lateral. 

THE FOLLOWING FINANCIAL INFORMATION IS BEING RELEASED PURSUANT TO FRESH START ACCOUNTING AND THE COMPANY'S TRANSITION TO FULL COST METHOD OF ACCOUNTING, WHICH INCLUDES THE PREDECESSOR COMPANY FROM JANUARY 1, 2016OCTOBER 12, 2016 ("Predecessor Company period") AND THE SUCCESSOR COMPANY FROM OCTOBER 13, 2016 - DECEMBER 31, 2016 ("Successor Company period").

CAPITAL EXPENDITURES

Capital expenditures for the Successor Company period were $4.3 million, with $4.2 million spent on drilling and completion costs and $0.1 million on leasehold and other expenditures. For the Predecessor Company period, capital expenditures totaled $2.0 million, with $1.5 million spent on drilling and completion costs, $0.5 million on leasehold and $0.1 million on facilities, capital workovers and other expenditures.    

The Company is updating its preliminary 2017 capital expenditure budget to $40-50 million to account for more operated activity with higher anticipated working interests. Current plans have the Company drilling 9-13 gross (3-5 net) wells in 2017.

PRODUCTION

Production totaled approximately 1.72 Bcfe (70% natural gas) for the Successor Company period, or an average of 21,538 Mcfe per day. Current production is approximately 39% higher at 30,000 Mcfe (80% natural gas) per day, with the increase primarily driven by recent Haynesville completions. Production for the Predecessor Company period was 6.69 Bcfe (65% natural gas).  

Subject to market conditions, natural gas production for the year is expected to grow by more than 100% over the prior year period, with most of the Company's capital expenditure budget dedicated to drilling long lateral, high proppant Haynesville wells.

REVENUES

Revenues for the Successor Company period totaled $6.6 million, from an average realized price of $3.79 per Mcfe ($1.94/Mcf and $47.84/Bbl). Revenues for the Predecessor Company period were $20.7 million from an average realized price of $3.14/Mcfe ($1.34/Mcf and $39.20/Bbl).

OPERATING EXPENSES

Lease operating expense ("LOE") was $2.1 million ($1.22/Mcfe) for the Successor Company period.  LOE for the Successor Company period included $0.4 million ($0.23/Mcfe) of workover expenses.  Net of workovers, LOE for the Successor Company period equated to $0.99/Mcfe and the Company expects per unit LOE to trend down as new Haynesville wells are added at significantly lower per unit costs. LOE for the Predecessor Company period was $6.5 million ($0.97/Mcfe), which included $0.8 million ($0.12/Mcfe) for workover expenses.

Production and other taxes were $0.6 million ($0.36/Mcfe) in the Successor Company period.   For the Predecessor Company period, Production and other taxes totaled $1.9 million ($0.29/Mcfe). Per unit Production and other taxes is expected to decrease over time as the Company executes on its Haynesville-directed capital expenditure budget, which wells carry severance tax abatement until the earlier of payout or two years.  

Transportation and processing expense was $0.2 million ($0.13/Mcfe) in the Successor Company period. Transportation and processing expense for the Predecessor Company period totaled $1.3 million ($0.19/Mcfe).

Depreciation, depletion and amortization ("DD&A") expense was $1.6 million ($0.90/Mcfe) in the Successor Company period.  DD&A expense for the Predecessor Company period was $8.3 million ($1.24/Mcfe).

Impairment expense was $2.5 million ($1.44/Mcfe) for the Successor Company period. Impairment expense for the Predecessor Company period was $1.6 million ($0.24/Mcfe).

Exploration expense was capitalized in the Successor Company period due to full cost accounting. Exploration expense for the Predecessor Company period was $0.6 million ($0.09/Mcfe).

General and Administrative ("G&A") expense was $2.2 million ($1.28/Mcfe) in the Successor Company period.  Cash G&A expense for the Successor Company period was $2.0 million ($1.14/Mcfe) after deducting non-cash, stock based compensation of $0.2 million ($0.14/Mcfe). G&A expense for the Predecessor Company period was $14.5 million ($2.16/Mcfe). Cash G&A for the Predecessor Company period was $11.2 million ($1.67/Mcfe) after deducting $3.3 million ($0.49/Mcfe) of non-cash, stock based compensation. Per unit G&A expense will continue to decline as production volumes grow over the year.

Gain on Sale of assets was $2,000 for the Successor Company period. Gain on sale of assets was $0.8 million for the Predecessor Company period.  

OPERATING INCOME (LOSS)

Operating income, defined as revenues minus operating expenses, totaled a loss of $2.6 million in the Successor Company period, which was negatively impacted by impairment expense of $2.5 million. Operating income for the Predecessor Company period was a loss of $13.1 million, which was negatively impacted by impairment expense of $1.6 million.

INTEREST EXPENSE

Interest expense totaled $1.8 million in the Successor Company period.  Of this interest expense, $1.5 million was non-cash associated with the Company's election to pay in kind (additional notes) for its second lien notes. Interest expense for the Predecessor Company period totaled $11.4 million.

NET INCOME

The Company announced net loss applicable to common stock of $4.3 million in the Successor Company period.  Net income applicable to common stock for the Predecessor Company period was $358.7 million, primarily due to a net gain of $399.4 million associated with the Company's reorganization. 

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company did not have any of its natural gas and oil production hedged in the Successor Company period, but has since added a costless collar for calendar year 2017 for 12,000 Mcf per day at $3.00 - $3.60 per Mcf.

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 performance and ability to internally generate operating funds.  Neither DCF nor 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 and Adjusted EBITDAX 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, 2016 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 natural gas exploration and production company listed on the OTCQX under the symbol GDPP.

 

SOURCE Goodrich Petroleum Corporation

For further information: Robert Turnham, President, Robert Barker, Chief Financial Officer, (713) 780-9494


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