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Goodrich Petroleum Announces Financing, Amendment To Credit Facility And Year-End And Fourth Quarter Financial And Operational Results

HOUSTON, Feb. 27, 2015 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial and operating results for the year and fourth quarter ended December 31, 2014. 

  • The Company has entered into a definitive purchase agreement for the issuance and sale of $100 million aggregate principal amount of 8% senior secured notes due 2018 (the "Second Lien Notes"), together with warrants to purchase up to 4.88 million shares of the Company's common stock at an exercise price of $4.66 per share, a 10% premium to yesterday's closing stock price. The Company has increased its liquidity and has the ability to issue an additional $75 million aggregate principal amount of the Second Lien Notes in the future.
  • The Company's first lien credit facility maturity has been extended to February 2017, the covenants amended to provide additional flexibility and borrowing base redetermined to $200 million, reduced to $150 million upon closing of the sale of the Second Lien Notes.
  • Adjusted EBITDAX totaled $41.7 million for the quarter increasing approximately 29% over the prior year period. Discretionary cash flow totaled $31.6 million for the quarter increasing approximately 43% over the prior year period.
  • Oil production averaged 5,770 Bbls per day for the quarter, an approximate 46% increase over the prior year period. For the quarter, approximately 51% of volumes were comprised of oil, which generated 79% of the quarterly revenue.
  • Significant cost reductions seen in the Tuscaloosa Marine Shale ("TMS") from an approximate 35% reduction in drilling days and reduced service costs resulting in a combined reduction in estimated well costs of approximately 23%.

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

(PV-10, Adjusted EBITDAX and Discretionary Cash Flow are non-US 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 US GAAP financial measure.)

FINANCIAL RESULTS

REVENUES

Revenues totaled $48.6 million in the quarter versus $50.6 million in the prior year period.  Average realized price per unit was $7.73 per Mcfe in the quarter versus $6.81 per Mcfe in the prior year period.  When factoring in net cash received/paid to settle oil and natural gas derivatives, Adjusted Revenues totaled $57.6 million in the quarter versus $50.2 million in the prior year period, and average realized price per unit, inclusive of derivative settlements, was $9.16 per Mcfe versus $6.76 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 6.3 billion cubic feet equivalent ("Bcfe") in the quarter, or an average of 68,300 Mcfe (51% oil) per day, versus 7.4 Bcfe, or an average of 80,800 Mcfe (29% oil) per day in the prior year period.  Oil production totaled 531,000 barrels of oil in the quarter, or an average of approximately 5,770 barrels per day, versus 364,000 barrels of oil, or an average of approximately 3,950 barrels per day, in the prior year period.  Production for the year was 25.1 Bcfe, or an average of 68,900 Mcfe per day, versus 27.8 Bcfe, or an average of 76,100 Mcfe per day in the prior year period.  Crude oil production for the year totaled 1.7 million barrels of oil, a 26% increase over 2013, and 15.0 Bcf of natural gas, or an average of 41,000 Mcf per day. 

As previously announced, the Company anticipates producing between 4,800 – 5,200 Bbls per day of oil in 2015, which includes completion deferrals into the second half of 2015, and 23,000 – 26,000 Mcf per day of natural gas in 2015.        

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $41.7 million in the quarter, compared to $32.3 million in the prior year period.   Adjusted EBITDAX for the year was $139.3 million versus $125.5 million in the prior year period. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $31.6 million in the quarter, compared to $22.0 million in the prior year period.  Net cash provided by operating activities for the quarter was $26.6 million, compared to $30.6 million for the prior year period.  DCF was $96.2 million for the year, versus $84.1 million in the prior year period.  Net cash provided by operating activities for the year was $121.7 million, compared to $71.4 million for the prior year period.

Adjusted EBITDAX and DCF were both impacted by $9.0 million of net cash received for the settlement of derivative instruments during the quarter compared to $0.4 million of net cash paid for the settlement of derivative instruments during the prior year period.  For the year, Adjusted EBITDAX and DCF were both impacted by $3.4 million of net cash received for the settlement of derivative instruments compared to $3.8 million of net cash paid for the settlement of derivative instruments during 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 $233.3 million in the quarter, or ($5.23) per basic share, versus a net loss applicable to common stock of $30.9 million, or ($0.73) per basic share in the prior year period.  Net loss applicable to common stock for the quarter included a $246.6 million non-cash impairment charge.   Adjusted net loss applicable to common stock was $21.1 million for the quarter, or ($0.47) per basic share, which excludes the impact of gains on derivatives not designated as hedges of $47.4 million, net cash received for settlement of derivatives instruments of $9.0 million, loss on the sale of assets of $3.5 million, non-cash impairment of assets of $246.6 million and other expenses totaling $0.5 million.  The Company announced a net loss applicable to common stock of $382.9 million for the year, or ($8.62) per basic share, versus a net loss applicable to common stock of $113.8 million, or ($2.99) per basic share in the prior year period.  Adjusted net loss applicable to common stock was $87.8 million for the year, or ($1.98) per basic share, versus a net loss applicable to common stock of $105.6 million, or ($2.77) per basic share in the prior year period.

(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 $6.9 million in the quarter, or $1.09 per Mcfe, versus $7.1 million, or $0.96 per Mcfe, in the prior year period, which included $0.4 million, or $0.06 per Mcfe, for workovers performed in the quarter, versus $1.6 million, or $0.22 per Mcfe, in the prior year period.  For the year, LOE totaled $29.5 million, or $1.17 per Mcfe, versus $27.3 million, or $0.98 per Mcfe in the prior year period, which included $4.3 million, or $0.17 per Mcfe, for workovers, versus $6.0 million, or $0.22 per Mcfe, in the prior year period.  The majority of the Company's workover expense pertained to wells in the Eagle Ford Shale and Haynesville Shale trends.       

Production and other taxes were $2.6 million in the quarter, or $0.42 per Mcfe, versus $1.8 million, or $0.25 per Mcfe, in the prior year period.  For the year, production and other taxes totaled $9.9 million, or $0.39 per Mcfe, versus $9.8 million, or $0.35 per Mcfe, in the prior year period.     

Transportation and processing expense was $2.2 million in the quarter, or $0.36 per Mcfe, versus $2.7 million, or $0.36 per Mcfe, in the prior year period.  The decrease in transportation and processing expense was mostly due to lower natural gas production.  For the year, transportation and processing expense totaled $9.1 million, or $0.36 per Mcfe, versus $10.5 million, or $0.38 per Mcfe, in the prior year period. Following the completion of the Company's non-core asset sale in December 2014 and the continued focus on the TMS, transportation and processing expense is expected to decrease in 2015.   

Depreciation, depletion and amortization ("DD&A") expense was $40.4 million in the quarter, or $6.43 per Mcfe, versus $32.6 million, or $4.38 per Mcfe, in the prior year period, which was driven by increasing production from the oil-focused TMS compared to 2013.  For the year, DD&A expense totaled $135.7 million, or $5.40 per Mcfe, versus $135.4 million, or $4.87 per Mcfe, for the prior year period.

Exploration expense was $0.6 million in the quarter, or $0.10 per Mcfe, versus $5.8 million, or $0.78 per Mcfe, in the prior year period.  For the year, exploration expense totaled $6.2 million, or $0.25 per Mcfe, versus $22.8 million, or $0.82 per Mcfe, in the prior year period.  The decrease in exploration expense was due to lower lease amortization costs associated with expiring leases in the Eagle Ford Shale trend and no dry hole costs. 

General and Administrative ("G&A") expense was $7.0 million in the quarter, or $1.12 per Mcfe, versus $8.7 million, or $1.18 per Mcfe, in the prior year period.  The decrease in G&A expense was mostly due to lower compensation expense.  G&A expense related to non-cash, stock based compensation for its employees totaled $2.9 million in the quarter, or $0.46 per Mcfe, versus $2.5 million, or $0.33 per Mcfe, in the prior year period.  For the year, G&A expense totaled $33.7 million, or $1.34 per Mcfe, versus $34.1 million, or $1.23 per Mcfe, in the prior year period.  For the year, G&A expense related to non-cash, stock based compensation totaled $9.6 million, or $0.38 per Mcfe, versus $7.7 million, or $0.28 per Mcfe, in the prior year period.    

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $261.7 million in the quarter, versus an operating loss of $8.1 million in the prior year period, which was negatively impacted by $246.6 million of non-recurring, non-cash impairment expenses.  For the year, operating income totaled a loss of $354.8 million, versus an operating loss of $36.3 million in the prior year period, which was negatively impacted by $331.9 million of non-recurring, non-cash impairment expenses.

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

INTEREST EXPENSE

Interest expense totaled $11.6 million in the quarter, or $1.84 per Mcfe, versus $12.1 million, or $1.63 per Mcfe, in the prior year period.  Non-cash interest expense, associated with the Company's debt, totaled $2.0 million (representing 17% of total interest expense) in the quarter, or $0.32 per Mcfe, versus $2.7 million, or $0.37 per Mcfe, in the prior year period.  For the year, interest expense totaled $47.8 million, or $1.90 per Mcfe, versus $51.2 million, or $1.84 per Mcfe, in the prior year period.  For the year, non-cash interest expense, representing 21% of total interest expense, totaled $10.0 million, or $0.40 per Mcfe, versus $12.7 million, or $0.46 per Mcfe, in the prior year period.

CAPITAL EXPENDITURES

Capital expenditures totaled $73.4 million in the quarter, of which $68.8 million was spent on drilling and completion costs, $0.8 million on leasehold acquisition and $3.8 million on facilities, capital workovers and other expenditures.  For the year, capital expenditures totaled $332.9 million, of which $295.1 million was spent on drilling and completion costs, $23.2 million on leasehold and property acquisitions and $14.6 million on facilities, capital workovers and other expenditures.

As previously announced, the Company revised its preliminary capital expenditure budget for 2015 to $90 – 110 million, comprised of $80 – 100 million of drilling and completion capital expenditures and approximately $10 million of leasehold and infrastructure expenditures.  The Company will monitor capital expenditures on a quarterly basis and maintain flexibility to accelerate capital expenditures with improvement in oil prices and the monetization of certain assets.  Oil-directed capital is estimated to be approximately 91 – 93% of the total drilling and completion budget, with the entire oil-directed allocation to the Tuscaloosa Marine Shale, where the Company is seeing significant reductions in well costs, as authority for expenditures ("AFEs" ) have decreased from approximately $13 million per well in 2014 for single well pads to approximately $10 million per well for single well pads and $9.4 million per well for two well pads.  The reduction in well costs is being driven by a reduction in drilling days from approximately 40 days to an average of 26 days (21 – 29 days per well) over the last four wells, and approximately 15 – 20% reduction in service costs.  More detail is given in the presentation for the earnings release.

YEAR-END RESERVES

The Company's proved oil and natural gas reserves as of December 31, 2014 totaled 273.7 Bcfe, versus 452.2 Bcfe in the prior year period.   Year-end reserves were comprised of 59.3% oil, 38.3% natural gas and 2.4% natural gas liquids, which does not include approximately 103.1 Bcfe of proved undeveloped natural gas reserves due to the Securities and Exchange Commission's ("SEC") five year rule and 140.3 Bcfe of reserves (as of December 31, 2013) that were sold in December of 2014.  The Company spent $272.8 million of adjusted net drilling and completion capital, adding 100.4 Bcfe of proved reserves, resulting in an adjusted organic finding and development cost of $2.72 per Mcfe ($16.30 per BOE).  SEC pricing for the year-end report was $94.99 per barrel of oil, $4.35 per MMBtu for natural gas and $44.84 per barrel of natural gas liquids.  Proved reserves from the Tuscaloosa Marine Shale grew by 14.9 million barrels of oil equivalent (89.7 Bcfe) and $311 million of PV-10 compared to December 31, 2013, and now comprises 42.1% of the Company's reserves and 60.4% of the Company's PV-10. 

(Year-end PV-10 of proved reserves is a non-US 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 2013:


Proved


Reserves


(Bcfe)



Reserves at December 31, 2013 

452.2

      Production 

(26.8)

      Divestitures 

(135.8)

      Acquisitions 

-

      Reserve Additions 

100.4

      Revisions – Price and Technical 

(116.3)



Reserves at December 31, 2014 

273.7



2014 Reserve Replacement Ratio (%)(2) 

375%



2014 Net Cash Drilling and Completion Capital Expenditures (non-US GAAP)(3) 

$272.8 MM



2014 Finding and Development Costs ($/Mcfe)(4) 

$2.72 ($16.30/BOE)

 


(1)

Reserve Replacement Ratio is calculated by dividing Reserve Additions (before price and technical revisions) by Production.


(2)

See Net Cash Drilling and Completion Capital Expenditures (non-US GAAP) in "Other Information" section for additional disclosure and information.


(3)

Finding and Development Costs per Mcfe is calculated by dividing Net Cash Drilling and Completion Capital Expenditures (non-US GAAP) for wells drilled in 2014 by total proved reserve additions (before price and technical revisions).

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

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company had a gain of $47.4 million on its derivatives not designated as hedges in the quarter, versus a loss of $1.1 million during the prior year period.  For the year, the Company had a gain of $49.4 million on its derivatives not designated as hedges, versus a loss of $0.7 million during the prior year period.

For 2015, the Company has a total of 3,500 Bbls/day swapped at an average LLS price of $96.11 per Bbl.     

SENIOR SECURED NOTES OFFERING

The Company has entered into a definitive agreement for the issuance and sale of $100 million second lien senior secured notes to repay borrowings under the first lien credit facility and to pay transaction expenses and third party fees.  The debt financing, which is for a term of three years, carries an 8% coupon which is payable semi-annually.  Additionally, the purchaser of the notes will receive 4.88 million warrants exercisable at a 10% premium to the stock price on the execution date of the agreements.  The Company has the ability to place an additional $75 million of second lien senior secured notes in the future. 

LIQUIDITY

Following the sale of the Company's East Texas assets on December 22, 2014, the borrowing base of the Company's first lien credit facility was reduced to $230 million.  The Company had $121 million drawn on its first lien credit facility at the end of 2014 resulting in approximately $109 million of available liquidity as the Company entered 2015.

The Company has entered into an amendment to its first lien credit facility which extends the term until February 2017, amends the debt to EBITDAX covenant to 2.5 times secured debt to EBITDAX and sets the borrowing base at $200 million, which reduces to $150 million upon closing of the notes offering.  The Company expects to finance the remainder of its 2015 capital expenditure budget with cash flow from operations and available capacity on its first lien credit facility. 

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 9 gross (7 net) wells, of which 8 gross (6 net) were in the TMS and 1 gross (1 net) in the ART/Shelby Trough area of the Haynesville Shale.  A total of 4 gross (3 net) TMS wells were added to production during the quarter, with 5 gross (4 net) wells waiting on completion at year-end and 8 gross (6 net) wells waiting on completion currently.  For the year, the Company conducted drilling operations on 29 gross (21 net) wells and added 23 gross (16 net) wells to production.  The wells added to production during the year consisted of 6 gross (4 net) in the Eagle Ford Shale trend and 17 gross (12 net) in the TMS.

Tuscaloosa Marine Shale:

During the fourth quarter of 2014, the Company had approximately three rigs running in the TMS, and reached total depth on three wells, its two-well CMR/Foster Creek 8H-1 (78.8% WI) and 8H-2 (81.8% WI) pad in Wilkinson County, Mississippi, and its T. Lewis 7-38H-1 (90.5% WI) well in Amite County, Mississippi.  During the quarter, the Company continued with drilling operations on its two-well B-Nez 43H-1 (69.5% WI) and 43H-2 (70% WI) pad, its Kinchen 58H-1 (78.3% WI) well, all located in Tangipahoa Parish, Louisiana, and its Painter 5H-1 (73% WI) well located in Washington Parish, Louisiana. 

The Company has completed its Kent 41H-1 (99.8% WI) well in Tangipahoa Parish, Louisiana but has yet to drill out the frac plugs, which is currently planned for early March 2015.  In addition, the Company currently has seven TMS wells drilled and waiting on completion, with plans to begin completion operations on these wells beginning late 1Q'15 through early 2016, pending better market conditions.  Since the end of the fourth quarter, the Company has released two rigs, with one active in the TMS.

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, 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 US GAAP.  Adjusted revenues should not be considered an alternative to total revenues, as defined by US GAAP.  Adjusted operating income 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.  Nor should drilling and completion capital expenditures be considered an alternative to costs incurred in oil and natural gas property acquisition, exploration, and development activities, as defined by US 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 US GAAP-required standardized measure of discounted future net cash flows ("SMOG").  The Company's discounted future income taxes are estimated to be $5.8 million at December 31, 2014 to arrive at a SMOG of $644.7 million.  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 natural 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 natural gas exploration and production company listed on the New York Stock Exchange.

Quantitative Reconciliation of Net Cash Drilling and Completion Capital Expenditures (non-US GAAP) as used in the calculation of Organic Finding and Development Costs and Organic Proved Developed Finding and Development Costs to Net Cash Used in Investing Activities (US GAAP):

Net Cash Used In Investing Activities (US GAAP)

$268,420

Less: Cash Spent in 2014 for Expenditures Booked in 2013 

(22,322)

Add: Proceeds from Sale of Assets 

53,932



Net Capital Expenditures Booked in 2014 (non-US GAAP) 

$300,030

Less:   Leasehold Acquisitions 

(23,202)

           Facilities & Infrastructure 

(3,341)

           Furniture, Fixtures & Equipment 

(684)



Net Cash Drilling and Completions Capital Expenditures (non-US GAAP) 

$272,803

 

 

GOODRICH PETROLEUM CORPORATION

SELECTED INCOME AND PRODUCTION DATA

(In Thousands, Except Per Share Amounts)














Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013

Volumes










Natural gas (MMcf)


3,101


5,254


14,980


19,760


Oil and condensate (MBbls)


531


364


1,692


1,338


MMcfe - Total


6,286


7,437


25,131


27,785












Mcfe per day


68,322


80,832


68,853


76,124











Total Revenues


$     48,557


$   50,565


$  208,553


$  203,295











Operating Expenses










Lease operating expense


6,851


7,124


29,525


27,293


Production and other taxes


2,612


1,848


9,905


9,812


Transportation and processing


2,238


2,657


9,070


10,498


Depreciation, depletion and amortization


40,391


32,550


135,716


135,357


Exploration


642


5,813


6,206


22,774


Impairment 


246,592


-


331,931


-


General and administrative


7,021


8,743


33,728


34,069


(Gain) loss on sale of assets


3,499


(48)


3,499


(107)


Other


436


-


3,793


(91)

Operating  loss


$ (261,725)


$   (8,122)


$ (354,820)


$   (36,310)











Other income (expense)










Interest expense


$   (11,555)


$ (12,108)


$   (47,829)


$   (51,187)


Interest income and other


64


83


90


101


Loss on early extinguishment of debt


-


(2,296)


-


(7,088)


Gain (loss) on derivatives not designated as hedges


47,389


(1,052)


49,423


(702)




$     35,898


$ (15,373)


$       1,684


$   (58,876)











Loss before income taxes


$ (225,827)


$ (23,495)


$ (353,136)


$   (95,186)

Income tax benefit 


-


-


-


-

Net loss  


(225,827)


(23,495)


(353,136)


(95,186)

Preferred stock dividends


7,430


7,431


29,722


18,604











Net loss applicable to common stock


$ (233,257)


$ (30,926)


$ (382,858)


$ (113,790)












(Gain) loss on derivatives not designated as hedges


(47,389)


1,052


(49,423)


702


Net cash received (paid) in settlement of derivative instruments


9,001


(374)


3,417


(3,786)


Lease expirations


29


-


1,769


-


Dry hole cost


-


4,069


44


4,390


Loss on early extinguishment of debt


-


2,296


-


7,088


(Gain) loss on sale of assets


3,499


(48)


3,499


(107)


Other


436


-


3,793


(91)


Impairment 


246,592


-


331,931


-











Adjusted net loss applicable to common stock (1)


$   (21,089)


$ (23,931)


$   (87,828)


$ (105,594)












Discretionary cash flow (see non-US GAAP reconciliation) (2)


$     31,611


$   22,049


$     96,235


$     84,122












Adjusted EBITDAX (see calculation and non-US GAAP reconciliation) (3)


$     41,717


$   32,288


$  139,297


$  125,517











Weighted average common shares outstanding - basic


44,592


42,229


44,402


38,098

Weighted average common shares outstanding - diluted (4)


44,592


42,229


44,402


38,098











Earnings per share










Net loss applicable to common stock - basic


$        (5.23)


$      (0.73)


$        (8.62)


$        (2.99)


Net loss applicable to common stock - diluted


$        (5.23)


$      (0.73)


$        (8.62)


$        (2.99)











Adjusted earnings per share










Adjusted net loss applicable to common stock - basic (1)


$        (0.47)


$      (0.57)


$        (1.98)


$        (2.77)


Adjusted net loss applicable to common stock - fully diluted (1)


$        (0.47)


$      (0.57)


$        (1.98)


$        (2.77)

 




(1) Adjusted net income (loss) applicable to common stock is defined as net income (loss) applicable to common stock adjusted to exclude certain charges or amounts in order to provide users of this financial information with additional meaningful comparisons between current results and the results of prior periods. Management presents this measure because (i) it is consistent with the manner in which the company's performance is measured relative to the performance of its peers, (ii) this measure is more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under  accounting principles generally accepted in the United States of America ("US GAAP"). 











(2) Discretionary cash flow is defined as net cash provided by operating activities before changes in operating assets and liabilities. Management believes that the non-US GAAP measure of operating cash flow is useful as an indicator of an oil and natural gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with US GAAP. 











(3) Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, In calculating adjusted EBITDAX, gain/losses on derivatives, less net cash received or paid in settlement of commodity derivatives are excluded from Adjusted EBITDAX. Other excluded items include Interest income and other, (Gain) loss on sale of assets, Loss on early extinguishment of debt, Stock compensation expense and Other expense.











(4) Fully diluted shares excludes approximately 9.1 million  and 9.2 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the three months and year ended December 31, 2014, respectively.  We report our financial results in accordance with US GAAP. However, management believes certain non-US GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.

 

GOODRICH PETROLEUM CORPORATION

Per Unit Sales Prices and Costs














Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013











Average sales price per unit:










Oil (per Bbl)










     Including net cash received/paid to settle oil derivatives 


$ 85.09


$ 91.17


$ 89.61


$   98.70


     Excluding net cash received/paid to settle oil derivatives


$ 72.28


$ 93.66


$ 90.08


$ 101.96


Natural gas (per Mcf)










     Including net cash received/paid to settle natural gas derivatives


$   4.01


$   3.25


$   4.03


$      3.38


     Excluding net cash received/paid to settle natural gas derivatives


$   3.30


$   3.15


$   3.75


$      3.35


Oil and natural gas (per Mcfe)










     Including net cash received/paid to settle oil and natural gas derivatives


$   9.16


$   6.76


$   8.44


$      7.15


     Excluding net cash received/paid to settle oil and natural gas derivatives


$   7.73


$   6.81


$   8.30


$      7.29





















Costs Per Mcfe










Lease operating expense


$   1.09


$   0.96


$   1.17


$      0.98


Production and other taxes


0.42


0.25


0.39


0.35


Transportation and processing


0.36


0.36


0.36


0.38


Depreciation, depletion and amortization


6.43


4.38


5.40


4.87


Exploration


0.10


0.78


0.25


0.82


Impairment 


39.23


-


13.21


-


General and administrative


1.12


1.18


1.34


1.23


(Gain) loss on sale of assets


0.56


(0.01)


0.14


-


Other


0.07


-


0.15


-




$ 49.36


$   7.89


$ 22.42


$      8.62











Note: Amounts on a per Mcfe basis may not total due to rounding.

 


GOODRICH PETROLEUM CORPORATION



Selected Cash Flow Data (In Thousands):

























Reconciliation of Discretionary Cash Flow and Net Cash Provided by Operating Activities (unaudited)















Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013













Net cash provided by operating activities (US GAAP)

$     26,563


$           30,564


$      121,731


$        71,405



Net changes in working capital

5,048


(8,515)


(25,496)


12,717



Discretionary cash flow

$     31,611


$           22,049


$        96,235


$        84,122














Weighted average common shares outstanding - basic

44,592


42,229


44,402


38,098



Weighted average common shares outstanding - diluted (4)

44,592


42,229


44,402


38,098














Supplemental Balance Sheet Data








As of









December 31,


December 31,









2014


2013



















Cash and cash equivalents

$                8


$           49,220



















Long-term debt

568,625


435,866

















Reconciliation of Net loss to Adjusted EBITDAX








Three Months Ended


Year Ended





December 31,


December 31,





2014


2013


2014


2013















Net loss (US GAAP)

$ (225,827)


$         (23,495)


$    (353,136)


$      (95,186)




Exploration expense

642


5,813


6,206


22,774




Depreciation, depletion and amortization

40,391


32,550


135,716


135,357




Impairment

246,592


-


331,931


-




Stock compensation expense

2,881


2,469


9,555


7,680




Interest expense 

11,555


12,108


47,829


51,187




Loss on early extinguishment of debt

-


2,296


-


7,088




(Gain) loss on derivatives not designated as hedges

(47,389)


1,052


(49,423)


702




Net cash received (paid) in settlement of derivative instruments

9,001


(374)


3,417


(3,786)




Other excluded items *

3,871


(131)


7,202


(299)




      Adjusted EBITDAX

$     41,717


$           32,288


$      139,297


$      125,517















*  Other excluded items include Interest income and other, (Gain) loss on sale of assets and Other expense.














Other Information








Three Months Ended


Year Ended





December 31,


December 31,





2014


2013


2014


2013















Interest expense - cash

$        9,571


$             9,367


$        37,850


$        38,441




Interest expense - noncash

1,984


2,741


9,979


12,746




Total Interest

$     11,555


$           12,108


$        47,829


$        51,187















Change in fair value of derivatives not designated as hedges prior to cash settlement

$    (38,388)


$                678


$      (46,006)


$         (3,084)




Net cash (received) paid in settlement of derivative instruments

(9,001)


374


(3,417)


3,786




Total (gain) loss on derivatives not designated as hedges

$    (47,389)


$             1,052


$      (49,423)


$              702















General and Administrative expense - cash

$        4,140


$             6,274


$        24,173


$        26,389




General and Administrative expense - noncash

2,881


2,469


9,555


7,680




Total General and Administrative expense

$        7,021


$             8,743


$        33,728


$        34,069


 


GOODRICH PETROLEUM CORPORATION



Selected Cash Flow Data continued (In Thousands):

























Reconciliation of Adjusted Revenues and Total Revenues (unaudited)















Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013













Total Revenues (US GAAP)

$     48,557


$        50,565


$       208,553


$       203,295



Net cash received (paid) in settlement of derivative instruments

9,001


(374)


3,417


(3,786)



Adjusted Revenues

$     57,558


$           50,191


$       211,970


$       199,509

























Reconciliation of Adjusted Operating Income and Operating Income (unaudited)















Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013













Operating loss (US GAAP)

$ (261,725)


$        (8,122)


$     (354,820)


$       (36,310)



Net cash received (paid) in settlement of derivative instruments

9,001


(374)


3,417


(3,786)



Impairment

246,592


-


331,931


-



Adjusted Operating  loss

$      (6,132)


$           (8,496)


$       (19,472)


$       (40,096)

























Calculation of Cash operating margin (unaudited)















Three Months Ended


Year Ended




December 31,


December 31,




2014


2013


2014


2013













Adjusted EBITDAX (see calculation and non-US GAAP reconciliation) (3)

$     41,717


$        32,288


$       139,297


$       125,517



Adjusted Revenues (see non-US GAAP reconciliation)

$     57,558


$           50,191


$       211,970


$       199,509



Cash operating margin

72%


64%


66%


63%













                                        

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SOURCE Goodrich Petroleum Corporation

For further information: Robert C. Turnham, Jr., President, or Jan L. Schott, Chief Financial Officer, or Daniel E. Jenkins, Director of Investor Relations, (713) 780-9494