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News Releases
Goodrich Petroleum Announces Financial Results And Operational Update
PR Newswire
HOUSTON

HOUSTON, Aug. 6, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the quarter ended June 30, 2013 and provided an operational update.

  • Tuscaloosa Marine Shale ("TMS"):
    • The Encana operated Anderson 17H-2 (7% WI) well is online and producing with a peak 24-hour average rate of 1,540 BOE (95% oil) on a 17/64 inch choke.  The Anderson 17H-3 (7% WI) well is in early stage of flowback with approximately 2% of frac fluid recovered, with results to be announced upon achievement of peak rate;
    • The Smith 5-29H-1 (89% WI) well has averaged approximately 1,000 BOE (96% oil) per day on a 12/64 inch choke over the last eight days;
    • The Crosby 12H-1 (50% WI) well reached cumulative production of in excess of 100,000 BOE in five months, with current production rate of approximately 375 BOE per day;
    • Company on target to close by August 22nd on its recently announced acquisition of a 66.7% working interest in 750 gross barrels of oil per day (March 2013) and 277,000 gross acres for $26.7 million, effective March 1, 2013. Upon closing, the Company will own approximately 320,000 net acres in the TMS;
    • The Company has reallocated approximately $15 million of estimated capital expenditures from its Eagle Ford Shale 2013 capital expenditure budget to accelerate development of its new TMS acreage block in the fourth quarter with further acceleration anticipated in 2014.  
  • Production for the quarter was 6.7 billion cubic feet equivalent ("Bcfe"), or an average of 73,200 Mcfe per day, versus 8.3 Bcfe or an average of 91,000 Mcfe per day in the prior year period. Average daily production for the quarter grew 10% sequentially.  Oil production for the quarter totaled 292,000 barrels of oil or an average of 3,209 barrels per day, versus 254,000 barrels of oil or 2,791 barrels per day, in the prior year period.  Natural gas production for the quarter totaled 4.9 Bcf or an average of 54,000 Mcf per day.  Oil production in the Eagle Ford Shale trend continued to be impacted by frac interference as the Company has been concentrating its development activities on a portion of its acreage with pad drilled wells and zipper fracs.  Frac interference is subsiding as the Company has moved its rig to an area where it expects less interference, with current oil production for the Company in the 4,300 to 4,500 barrels per day range.
  • Oil volumes comprised 26% of total production and 62% of revenues for the quarter as average daily natural gas volumes increased 18% sequentially, with average realized oil price of $101.62 per barrel due to premium pricing agreements. Average realized price per Mcfe of production was $7.23 per Mcfe, including realized gain on derivatives.

FINANCIAL RESULTS

Cash Flow

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $31.5 million in the quarter compared to $45.2 million in the prior year period and $27.1 million in the prior quarter.   

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital was $20.9 million in the quarter compared to $34.8 million in the prior year period and $16.3 million in the prior quarter.  Net cash provided by operating activities was $29.6 million compared to $47.4 million for the prior year period.

For the prior year period, both Adjusted EBITDAX and DCF were positively impacted by a $21.3 million gain on realized derivative settlements compared to a $0.1 million gain in the current quarter.

(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 $20.1 million for the quarter or ($0.55) per basic share, versus a net loss applicable to common stock of $4.7 million or ($0.13) per basic share in the prior year period.  Adjusted net loss applicable to common stock was $23.0 million, which excludes the impact of the unrealized gain on derivatives not designated as hedges of $11.0 million, non-recurring exploration expense of $0.6 million and lease expirations of $7.5 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.) 

REVENUES

Revenues for the quarter were $48.5 million versus $41.3 million in the prior year period.  Average realized price per unit for the quarter was $7.22 per Mcfe versus $5.00 per Mcfe in the prior year period.  When factoring in the realized gain on derivatives not designated as hedges, average realized price per unit was $7.23 per Mcfe versus $7.58 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.) 

OPERATING EXPENSES

Lease operating expense ("LOE") was $5.9 million in the quarter or $0.88 per Mcfe versus $6.7 million or $0.81 per Mcfe in the prior year period.  LOE included $1.1 million or $0.17 per Mcfe for workovers performed in the quarter primarily in the Eagle Ford Shale trend.

Production and other taxes for the quarter were $2.7 million or $0.41 per Mcfe versus $2.1 million or $0.25 per Mcfe in the prior year period driven by higher oil volumes as a percentage of total volumes which carries a higher severance tax rate.     

Transportation and processing expense was $2.5 million, or $0.37 per Mcfe in the quarter versus $3.5 million or $0.43 per Mcfe in the prior year period. 

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $34.5 million or $5.18 per Mcfe versus $34.6 million or $4.17 per Mcfe in the prior year period. DD&A rate for the quarter was higher than the prior year due to a higher percentage of production volumes coming from oil which properties carry a higher DD&A rate.  DD&A expense per unit was $5.84 per Mcfe for the prior quarter.

Exploration expense was $9.5 million, or $1.43 per Mcfe for the quarter versus $2.0 million or $0.24 per Mcfe in the prior year period.  Approximately $7.5 million or 78% of exploration expense for the quarter was a non-cash expense for the expiration of undeveloped leasehold.  As part of its ongoing review of capital allocation, the Company elected not to renew expiring leases in its non-core Eagle Ford Shale trend acreage.  Exploration expense for the quarter also includes $0.6 million in seismic expense.

General and Administrative ("G&A") expense was $7.6 million, or $1.15 per Mcfe in the quarter versus $6.7 million or $0.81 per Mcfe in the prior year period. G&A expense related to stock based compensation for its employees was $1.7 million or $0.26 per Mcfe versus $1.5 million or $0.18 per Mcfe in the prior year period. 

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $14.2 million for the quarter in line with the prior year period.  Adjusted operating loss which includes the realized gain on derivatives not designated as hedges was a loss of $14.1 million.

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

INTEREST EXPENSE

Interest expense for the quarter was $13.0 million or $1.96 per Mcfe versus $13.1 million or $1.58 per Mcfe in the prior year period.  Non-cash interest expense associated with the Company's long term debt comprised 26% of the total or $3.4 million ($0.51 per Mcfe). 

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $64.5 million, of which $62.4 million was spent on drilling and completion costs and $2.1 million on leasehold acquisition, facilities and other expenditures.  Approximately 60% of the capital was spent in the Eagle Ford Shale trend, 17% in the Tuscaloosa Marine Shale trend and 23% on the completion of previously drilled Haynesville Shale wells that were brought online in the second quarter.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $0.1 million on its derivatives not designated as hedges and an unrealized gain of $11.0 million, for a gain on derivatives not designated as hedges of $11.1 million for the quarter.

LIQUIDITY

The Company exited the quarter with $2.7 million in cash and $75.0 million drawn on its senior bank revolving credit facility, with a borrowing base of $225 million, providing $152.7 million of available liquidity. Upon closing of the TMS acquisition the Company's borrowing base will increase by $18 million to $243 million.

PRODUCTION GUIDANCE

The Company is revising its full year 2013 production guidance to incorporate the experienced frac interference in its Eagle Ford Shale trend development drilling and delays due to a reallocation of capital from the Eagle Ford Shale to the TMS. The Company currently estimates oil volumes will grow by 30-40% in 2013 versus 2012 and overall volumes on a Mcfe basis will decrease by 5-10% year over year. Oil volumes are estimated to comprise approximately 30% of total production and 65-70% of revenues for the year.

OPERATIONAL UPDATE

Tuscaloosa Marine Shale ("TMS"):

The Company drilled and/or completed 4.0 gross (1.2 net) wells in the TMS in the quarter and expects to drill and complete 9.0 gross (4.6 net) wells in the trend for the year.  The Company had 3.0 gross (1.1 net) wells waiting on completion at quarter-end.

The Company is currently drilling its CMR/Foster Creek 20-7H-1 (99% WI) well in Wilkinson County, Mississippi and currently plans to spud three additional operated wells by the end of the year. The Company has reallocated approximately $15 million of its 2013 capital expenditure budget from the Eagle Ford Shale to accelerate development of its new TMS acreage block.  

Eagle Ford Shale:

The Company conducted drilling operations on 7.0 gross (4.7 net) wells in the quarter and expects to drill 22.0 gross (14.7 net) wells for the year.  In the quarter 9.0 gross (6.0 net) wells were completed and added to production, with 12.0 gross (8.0 net) wells completed and added to production year to date. For the year the Company expects to complete 22.0 gross (14.7 net) wells, down 3.0 gross (2.0 net) due to the reallocation of capital from the Eagle Ford Shale to the TMS. At quarter-end, 5.0 gross (3.3 net) wells were drilled but waiting on completion.

The Company has reduced its average drill time from inception by 13 days targeting 6,000 foot laterals which has led to a sharp reduction in costs over time, however, oil production for the quarter continued to be affected by frac interference due to pad drilling on a portion of the Company's Eagle Ford Shale acreage.

Haynesville Shale

The Company completed 6.0 gross (2.7 net) previously drilled Haynesville Shale wells in the quarter with 10.0 gross (4.2 net) wells completed and added to production year to date. The Company had 3.0 gross (1.5 net) wells drilled but waiting on completion at quarter-end. For the year, the Company expects to complete 13.0 gross (5.7 net) wells, with the remainder expected to be completed by the end of the third quarter. 

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, including Adjusted EBITDAX, Discretionary cash flow, Adjusted revenues, Adjusted operating income, Adjusted net loss applicable to common stock and Cash operating margin.  Management believes Adjusted EBITDAX, Discretionary cash flow, Adjusted revenues, Adjusted operating income, Adjusted net loss applicable to common stock and Cash margin are good financial indicators of the Company's ability to internally generate operating funds.  None of Discretionary cash flow, Adjusted EBITDAX or Cash operating margin, 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.  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 Annual Report on Form 10-K for the year ended December 31, 2012 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.



GOODRICH PETROLEUM CORPORATION

SELECTED INCOME AND PRODUCTION DATA

(In Thousands, Except Per Share Amounts)














Three Months Ended


Six Months Ended




June 30,


June 30,




2013


2012


2013


2012

Volumes










Natural gas (MMcf)


4,906


6,758


9,050


14,224


Oil and condensate (MBbls)


292


254


600


471


MMcfe - Total


6,658


8,282


12,651


17,047












Mcfe per day


73,167


91,006


69,893


93,665











Total Revenues


$  48,485


$ 41,346


$  95,569


$  86,654











Operating Expenses










Lease operating expense


5,881


6,695


13,097


15,049


Production and other taxes


2,742


2,087


5,502


4,080


Transportation and processing


2,476


3,522


5,073


7,650


Depreciation, depletion and amortization


34,513


34,562


69,487


66,840


Exploration


9,511


2,019


12,846


4,232


Impairment 


-


-


-


2,662


General and administrative


7,645


6,690


17,032


14,611


Gain on sale of assets


-


(72)


(43)


(72)


Other


(91)


-


(91)


-

Operating  loss


(14,192)


(14,157)


(27,334)


(28,398)











Other income (expense)










Interest expense


(13,027)


(13,089)


(26,400)


(26,002)


Interest income and other


15


1


19


1


Gain on derivatives not designated as hedges


11,061


24,043


9,109


33,468




(1,951)


10,955


(17,272)


7,467











Loss before income taxes


(16,143)


(3,202)


(44,606)


(20,931)

Income tax benefit 


-


-


-


-

Net loss  


(16,143)


(3,202)


(44,606)


(20,931)

Preferred stock dividends


3,956


1,512


5,468


3,024











Net loss applicable to common stock


$ (20,099)


$  (4,714)


$ (50,074)


$ (23,955)












Unrealized (gain) loss on derivatives not designated as hedges


(10,978)


(2,715)


(8,874)


3,753


Exploration - Seismic


634


-


1,047


-


Lease expirations


7,461


-


8,899


-


Dry hole cost


52


-


252


-


Gain on sale of assets


-


(72)


(43)


(72)


Other


(91)


-


(91)


-


Impairment 


-


-


-


2,662











Adjusted net loss applicable to common stock (1)


$ (23,021)


$  (7,501)


$ (48,884)


$ (17,612)












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


$  20,928


$ 34,753


$  37,249


$  64,699












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


$  31,524


$ 45,163


$  58,574


$  85,520











Weighted average common shares outstanding - basic


36,701


36,366


36,692


36,352

Weighted average common shares outstanding - diluted (4)


36,701


36,366


36,692


36,352











Earnings per share










Net loss applicable to common stock - basic


$     (0.55)


$    (0.13)


$     (1.36)


$     (0.66)


Net loss applicable to common stock - diluted


$     (0.55)


$    (0.13)


$     (1.36)


$     (0.66)











Adjusted earnings per share










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


$     (0.63)


$    (0.21)


$     (1.33)


$     (0.48)


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


$     (0.63)


$    (0.21)


$     (1.33)


$     (0.48)



 

(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 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-GAAP measure of operating cash flow is useful as an indicator of an oil and 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 GAAP. 











(3) Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. Other excluded items include Interest income and other, Gain on sale of assets, Gain on early extinguishment of debt and Other expense.











(4) Fully diluted shares excludes approximately 10.4 million and 10.3 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the three and six months ended June 30, 2013, respectively.  We report our financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-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


Six Months Ended




June 30,


June 30,




2013


2012


2013


2012











Average sales price per unit:










Oil (per Bbl)










     Including realized gain on oil derivatives 


$ 101.91


$ 107.16


$ 104.79


$ 105.63


     Excluding realized gain on oil derivatives


$ 101.62


$   98.96


$ 104.40


$ 102.36


Natural gas (per Mcf)










     Including realized gain on natural gas derivatives


$      3.75


$      5.26


$      3.59


$      5.22


     Excluding realized gain on natural gas derivatives


$      3.75


$      2.41


$      3.59


$      2.72


Natural gas and oil (per Mcfe)










     Including realized gain on oil and natural gas derivatives


$      7.23


$      7.58


$      7.54


$      7.27


     Excluding realized gain on oil and natural gas derivatives


$      7.22


$      5.00


$      7.52


$      5.09





















Costs Per Mcfe










Lease operating expense


$      0.88


$      0.81


$      1.04


$      0.88


Production and other taxes


$      0.41


$      0.25


$      0.43


$      0.24


Transportation and processing


$      0.37


$      0.43


$      0.40


$      0.45


Depreciation, depletion and amortization


$      5.18


$      4.17


$      5.49


$      3.92


Exploration


$      1.43


$      0.24


$      1.02


$      0.25


Impairment 


$            -


$            -


$            -


$      0.16


General and administrative


$      1.15


$      0.81


$      1.35


$      0.86


Gain on sale of assets/other


$    (0.01)


$    (0.01)


$            -


$            -




$      9.41


$      6.70


$      9.71


$      6.75











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


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012









Net cash provided by operating activities (GAAP)

$  29,588


$        47,393


$  35,860


$  77,930

Net changes in working capital

(8,660)


(12,640)


1,389


(13,231)

Discretionary cash flow

$  20,928


$        34,753


$  37,249


$  64,699










Weighted average common shares outstanding - basic

36,701


36,366


36,692


36,352

Weighted average common shares outstanding - diluted (4)

36,701


36,366


36,692


36,352










Supplemental Balance Sheet Data






As of







June 30,


December 31,







2013


2012















Cash and cash equivalents

$     2,650


$          1,188















Long-term debt

554,108


568,671













Reconciliation of Net income (loss) to Adjusted EBITDAX






Three Months Ended


Six Months Ended



June 30,


June 30,



2013


2012


2013


2012











Net loss (GAAP)

$ (16,143)


$         (3,202)


$ (44,606)


$ (20,931)


Exploration expense

9,511


2,019


12,846


4,232


Depreciation, depletion and amortization

34,513


34,562


69,487


66,840


Impairment

-


-


-


2,662


Stock compensation expense

1,700


1,483


3,474


3,035


Interest expense 

13,027


13,089


26,400


26,002


Unrealized (gain) loss on derivatives not designated as hedges

(10,978)


(2,715)


(8,874)


3,753


Other excluded items *

(106)


(73)


(153)


(73)


      Adjusted EBITDAX

$  31,524


$        45,163


$  58,574


$  85,520











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










Other Information






Three Months Ended


Six Months Ended



June 30,


June 30,



2013


2012


2013


2012











Interest expense - cash

$     9,599


$          9,953


$  19,558


$  19,731


Interest expense - noncash

3,428


3,136


6,842


6,271


Total Interest

13,027


13,089


26,400


26,002











Unrealized (gain) loss on derivatives not designated as hedges

(10,978)


(2,715)


(8,874)


3,753


Realized gain on derivatives not designated as hedges

(83)


(21,328)


(235)


(37,221)


Total gain on derivatives not designated as hedges

(11,061)


(24,043)


(9,109)


(33,468)











General and Administrative expense - cash

5,945


5,207


13,558


11,576


General and Administrative expense - noncash

1,700


1,483


3,474


3,035


Total General and Administrative expense

7,645


6,690


17,032


14,611


 



GOODRICH PETROLEUM CORPORATION

Selected Cash Flow Data continued (In Thousands):



















Reconciliation of Adjusted Revenues and Total Revenues (unaudited)











Three Months Ended


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012









Total Revenues (GAAP)

$  48,485


$   41,346


$  95,569


$   86,654

Realized gain on derivatives not designated as hedges

83


21,328


235


37,221

Adjusted Revenues

$  48,568


$   62,674


$  95,804


$ 123,875



















Reconciliation of Adjusted Operating Income and Operating Income (unaudited)











Three Months Ended


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012









Operating loss (GAAP)

$ (14,192)


$ (14,157)


$ (27,334)


$  (28,398)

Realized gain on derivatives not designated as hedges

83


21,328


235


37,221

Adjusted Operating Income (loss)

$ (14,109)


$     7,171


$ (27,099)


$      8,823



















Calculation of Cash operating margin (unaudited)











Three Months Ended


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012









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

$  31,524


$     45,163


$  58,574


$   85,520

Adjusted Revenues (see non-GAAP reconciliation)

$  48,568


$     62,674


$  95,804


$ 123,875

Cash operating margin

65%


72%


61%


69%



















 

 

SOURCE Goodrich Petroleum Corporation