Goodrich Petroleum Announces Second Quarter 2017 Financial Results and Operational Update

Adjusted EBITDA increased significantly to $5.1 million in the quarter versus $0.7 million in the prior quarter.  Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $4.8 million in the quarter.

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

Operating Expenses

Lease operating expense ("LOE") was $3.0 million in the quarter, or $0.89 per Mcfe.  LOE for the quarter included $0.7 million, or $0.22 per Mcfe, for workovers.  Lease operating expense excluding workovers was $2.2 million, or $0.67 per Mcfe, versus $0.94 per Mcfe in the first quarter. Per unit LOE will continue to fall as new Haynesville wells are added, as these wells carry very low operating costs per unit of production.

Production and other taxes were $0.4 million in the quarter, or $0.13 per Mcfe versus $0.28 per Mcfe in the first quarter.  Haynesville wells drilled in North Louisiana have severance tax abatement until the earlier of payout or two years, and therefore the Company's production and other taxes per unit of production is expected to continue to fall in the near term as new Haynesville wells are added.

Transportation and processing expense was $1.9 million in the quarter, or $0.57 per Mcfe versus $0.51 per Mcfe in the first quarter. Transportation and processing expense for the quarter includes transportation fees incurred on non-operated natural gas volumes that we take in-kind and approximately $0.1 million of a gathering line amortization fee associated with the Company's Wurtsbaugh 25&24 No. 1 well, which is expected to be fully amortized by the end of August 2017.  We expect per unit transportation and processing expense to fall this year as we add operated Haynesville production which carries a lower per unit cost.

Depreciation, depletion and amortization ("DD&A") expense was $3.1 million in the quarter, or $0.93 per Mcfe versus $0.99 per Mcfe in the first quarter.  The Company's DD&A rate is expected to decrease over time as the Company adds new Haynesville wells to the full cost pool and reserves, as finding costs for these new wells are expected to be lower than the current DD&A rate. 

General and Administrative expense was $3.8 million in the quarter, which includes $1.0 million of stock based compensation, $0.7 million for potential performance bonuses to be compensated in common stock and $0.1 million in non-cash amortization of office rent. G&A payable in cash for the quarter was $2.0 million, or $0.59 per Mcfe. Per unit G&A payable in cash will continue to fall in 2017 as costs are expected to remain relatively flat and production volumes are expected to grow materially.

Operating Income

Operating income, defined as revenues minus operating expenses, totaled $0.4 million in the quarter versus an operating loss of $3.5 million in the prior quarter.    

Interest Expense

Interest expense totaled $2.4 million in the quarter, which includes cash interest of $0.3 million incurred on the Company's first lien term loan and non-cash interest of $2.1 million incurred on the Company's second lien notes, which includes $1.4 million paid in-kind interest and $0.7 million amortization of debt discount.

Net Income (Loss)

The Company announced a net loss of $1.2 million in the quarter, or ($0.13) per basic share versus a net loss of $5.7 million in the prior quarter, or ($0.63) per basic share. 

Capital Expenditures

Capital expenditures totaled $14.1 million in the quarter, with the majority of the expenditures being spent on drilling and completion costs for the Company's recent Haynesville operated wells. The Company's capital expenditure budget for 2017 is being reduced to $35–45 million from $40-50 million due to savings and efficiencies gained from drilling two 7,500 foot laterals from a two well pad versus two individual 10,000 foot laterals originally planned.

Balance Sheet

The Company exited the quarter with $35 million of cash (including $0.6 million in restricted cash) and $61 million of funded debt.

Crude Oil and Natural Gas Derivatives

The Company had a gain of $0.8 million on its derivatives not designated as hedges in the quarter, representing the change in fair value of our natural gas derivative contracts and a small realized gain on derivative settlements.

The Company currently has 2017 natural gas swaps on a total of 6,000 MMBtu/day at a fixed price of $3.20 and natural gas costless collars on 12,000 MMBtu/day at a price range of $3.00-$3.60, as well as 2018 natural gas swaps on a total of 20,000 MMBtu/day at an average fixed price of $3.00. As volumes grow, the Company anticipates adding hedges for additional downside protection. 

OPERATIONAL UPDATE

Haynesville Shale

The Company is currently drilling its Franks 25&24 No. 1 well (69% WI, 50% NRI), which is planned as a 10,000 foot lateral with a completion design utilizing 5,000 lbs of proppant per foot.  Following the Franks well, the Company's full year budget includes drilling and completing the Wurtsbaugh 25&24 Nos. 2 & 3 (67%WI, 49% NRI) wells from the same pad. The Wurtsbaugh 25&24 Nos. 2 & 3 wells are expected to be 7,500 foot laterals to optimize the geographic configuration and provide maximum reserve recovery for the Company's operated acreage.  Due to the change in drilling schedule in order to take advantage of the two well pad and competitive service cost bids, the Company is now guiding to  a year-end production exit  rate of 55,000 – 60,000 Mcfe per day.

Well results continue to perform at or above the Company's type curves.  The ROTC 1&2 wells, the Company's initial two 10,000 foot laterals in which it participated, have now produced approximately 11 Bcf in seven months under a choke management program designed to minimize drawdown.  The Company has instituted a similar program for its two recent operated wells, the Wurtsbaugh 26 No. 1 and Wurtsbaugh 25&24 No. 1.

The Company's Haynesville acreage comprises approximately 50,000 gross (26,000 net) acres in Caddo and DeSoto Parishes, Louisiana and Angelina and Nacogdoches Counties, Texas. We estimate approximately 250 gross (100 net) locations prospective for the Haynesville on our core North Louisiana acreage, where the Company is allocating the vast majority of its capital expenditures in 2017. 

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 

OTHER INFORMATION

In this press release, the Company refers to several non-US GAAP financial measures, including Adjusted EBITDA, DCF, Adjusted revenues, Adjusted operating income (loss), Adjusted net loss and Cash operating margin.  Management believes Adjusted EBITDA, DCF, Adjusted Revenues, Adjusted operating income (loss), Adjusted net loss 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 and Adjusted EBITDA should not be considered an alternative to net loss, 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 NYSE American under the symbol "GDP".

GOODRICH PETROLEUM CORPORATION
SELECTED INCOME AND PRODUCTION DATA
(In thousands, except per share amounts)
			Three Months Ended		Six Months Ended
			June 30, 2017		June 30, 2017
Volumes
	Natural gas (MMcf)		2,795		4,628
	Oil and condensate (MBbls)		84		166
	Mmcfe - Total		3,299		5,623
	Mcfe per day		36,253		31,066
Oil and natural gas revenues			$                    12,115		$                21,526
Other			350		352
			$                    12,465		$                21,878
Operating Expenses
	Lease operating expense (LOE excluding workovers - $2,221 and $4,384, respectively)		2,950		7,261
	Production and other taxes		424		1,083
	Transportation and processing		1,868		3,044
	Depreciation, depletion and amortization		3,083		5,377
	General and administrative (payable in cash - $1,950 and $4,559, respectively)		3,772		8,235
Operating income (loss)			368		(3,122)
Other income (expense)
	Interest expense (payable in cash - $279 and $531, respectively)		(2,360)		(4,539)
	Interest income and other		12		21
	Gain on derivatives not designated as hedges		766		506
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