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Goodrich Petroleum Announces Third Quarter 2012 Financial and Operational Results

  Goodrich Petroleum Announces Third Quarter 2012 Financial and Operational
                                   Results

- Adjusted EBITDAX grew 6% sequentially to $48.0 million. Discretionary cash
flow grew 6% sequentially to $36.9 million

- Adjusted Revenues, including realized gain on derivatives, totaled $64.8
million for the quarter

- Operating Income, adjusted for realized gains on derivatives was $50.7
million for the quarter. Adjusted for the Company's gain on the sale of its
South Henderson field, operating income was $6.5 million

- Total liquids production grew by 12% sequentially to 4,600 barrels per day
(70% oil and condensate, 30% natural gas liquids), which was 33% of production
and 71% of revenues for the quarter. Oil and condensate production grew by 17%
sequentially to 3,200 barrels per day, which was 23% of production and 63% of
revenues for the quarter

- Realized price per unit of production, including realized gain on
derivatives, increased 10% sequentially to $8.34 per Mcfe, while cash
operating expenses totaled $2.31 per Mcfe for the quarter, for a net operating
cash margin of $6.03 per Mcfe

- Capital expenditures for the quarter totaled $57.8 million, down 22% from
$74.3 million in the prior quarter

- Tuscaloosa Marine Shale: The Company has fraced its initial operated well,
the Denkmann 33 H-1, with 12 successful frac stages, but flowback has been
delayed due to the need to repair a casing connection. Flowback will commence
upon completion of the repair and installation of tubing. Additionally, one
non-operated well recently commenced flowback, and management is encouraged by
the drilling results from another non-operated well (see Operational Update
below)

(See accompanying tables at the end of this press release that reconcile
Adjusted Revenue, Adjusted EBITDAX, discretionary cash flow, cash operating
margin and adjusted operating income, which are non-GAAP financial measures,
to their most directly comparable GAAP financial measure.)

PR Newswire

HOUSTON, Nov. 6, 2012

HOUSTON, Nov. 6, 2012 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE:
GDP) today announced financial and operating results for the third quarter
ended September 30, 2012.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative
expenses and exploration ("Adjusted EBITDAX") increased 6% sequentially and
decreased 2% over the prior year period to $48.0 million in the quarter,
compared to $45.2 million in the second quarter of 2012 and $49.1 million in
the prior year period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, increased by 6% sequentially and
decreased 5% over the prior year period to $36.9 million in the quarter,
compared to $34.8 million in the second quarter of 2012 and $39.0 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-GAAP financial measures, to
their most directly comparable GAAP financial measure.)

NET INCOME

The Company announced net income applicable to common stock of $10.9 million
for the quarter, or $0.30 per basic share, versus net income applicable to
common stock of $12.1 million, or $0.34 per basic share in the prior year
period. The Company had an adjusted net loss applicable to common stock of
$8.3 million, or an adjusted net loss of $0.23 per basic share, when adjusted
for the gain on sale of assets of $44.2 million and unrealized loss on
derivatives of $24.9 million for the quarter.

(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.)

PRODUCTION

Net production volumes for the quarter were 7.8 billion cubic feet equivalent
("Bcfe"), or an average of 84,400 thousand cubic feet equivalent ("Mcfe") per
day, versus 10.7 Bcfe, or an average of 116,200 Mcfe per day in the prior year
period. Despite a 17% sequential increase in oil production volumes in the
quarter, total average net daily production volumes on a Mcfe basis for the
quarter decreased 7% sequentially, as a result of a 11% decline in natural gas
production volumes due to the Company's drilling and completion capital
expenditures being allocated exclusively to oil directed activity. Oil
production volumes averaged approximately 3,200 barrels of oil per day for the
quarter and natural gas liquids averaged 1,400 per day for the quarter.
Production for the fourth quarter of 2012 is expected to average between
71,600 – 80,200 Mcfe per day, with oil production expected to average between
3,600 – 4,200 barrels of oil per day, or 27 – 35% of total production, with an
additional 8 gross (5 net) wells expected to be completed and added to
production in the fourth quarter of 2012. The oil production exit rate is now
expected to be approximately 4,500 barrels of oil per day, down from the
previously announced guidance of 5,000 barrels per day, due to the sale of the
South Henderson field and expected production delays from two Tuscaloosa
Marine Shale wells.

REVENUES

Revenues for the quarter were $46.0 million versus $55.5 million in the prior
year period. Revenues, including realized gain on derivatives not designated
as hedges of $18.8 million for the quarter, would have been $64.8 million.
Average realized price per unit for the quarter was $2.87 per Mcf and $97.43
per barrel of oil, or $5.92 per Mcfe, versus $5.20 per Mcfe in the prior year
period. Including the realized gain on derivatives of $18.8 million for the
quarter, the average realized price per unit was $5.60 per Mcf and $105.63 per
barrel of oil, or $8.34 per Mcfe, versus $5.97 per Mcfe in the prior year
period.

OPERATING EXPENSES

Lease operating expense ("LOE") decreased sequentially to $6.2 million in the
quarter, or $0.80 per Mcfe, versus $6.7 million, or $0.81 per Mcfe in the
prior quarter. LOE in the prior year period was $5.4 million, or $0.51 per
Mcfe. The increase in LOE expense versus the prior year period was primarily
due to increased oil-focused drilling and production activity in the Eagle
Ford Shale Trend, which has higher LOE than most of the Company's dry gas
assets. LOE, excluding workovers, was $5.8 million, or $0.75 per Mcfe, for
the quarter.

Production and other taxes decreased sequentially to $1.7 million in the
quarter, or $0.22 per Mcfe, versus $2.1 million, or $0.25 per Mcfe in the
prior quarter. Production and other taxes in the prior year period was $1.6
million, or $0.15 per Mcfe. The increase in production and other taxes from
the prior year period was driven by higher oil production volumes, which carry
higher production tax rates.

Transportation and processing expense decreased sequentially to $3.4 million
in the quarter, or $0.44 per Mcfe, versus $3.5 million, or $0.43 per Mcfe in
the prior quarter. Transportation and processing expense in the prior year
period was $2.8 million, or $0.26 per Mcfe. Transportation and processing
expense for the quarter as compared to the prior year period was impacted by
increased processing costs under the previously disclosed East Texas
processing agreement for the Minden, Beckville and South Henderson fields.

Depreciation, depletion and amortization ("DD&A") expense was $37.3 million in
the quarter, or $4.80 per Mcfe, versus $37.3 million, or $3.49 per Mcfe in the
prior year period. Increased DD&A expense per unit of production was
primarily due to higher oil production levels coming from the Company's Eagle
Ford Shale Trend, which carries a higher DD&A rate on a volume equivalent
basis, and lower production levels coming from the Haynesville Shale Trend,
which carries a lower DD&A rate on a volume equivalent basis. The Company
adjusted its DD&A rate for the second half of the year upon receipt of its
mid-year reserve report.

Exploration expense was $2.5 million in the quarter, or $0.32 per Mcfe, versus
$2.0 million, or $0.24 per Mcfe in the prior quarter and $1.6 million, or
$0.15 per Mcfe in the prior year period. The increase in exploration expense
compared to the prior quarter was due to seismic expenditures of $0.6 million,
or $0.08 per Mcfe. Approximately $1.3 million ($0.17 per Mcfe), or 52% of
exploration expense for the quarter, was a non-cash expense associated with
the amortization of the Company's undeveloped leasehold. 

General and Administrative ("G&A") expense was $7.1 million in the quarter, or
$0.92 per Mcfe, versus $6.7 million, or $0.81 per Mcfe in the prior quarter
and $6.3 million, or $0.58 per Mcfe in the prior year period. For the
quarter, the Company recorded non-cash general and administrative expenses
related to stock based compensation for its officers and employees of $1.7
million, or $0.22 per Mcfe, versus $1.3 million, or $0.13 per Mcfe in the
prior year period.

OPERATING INCOME

Operating income, defined as revenues less operating expenses, was $31.9
million in the quarter, versus operating income of $0.2 million in the prior
year period. When adding in realized gain on derivatives not designated as
hedges of $18.8 million, adjusted operating income increased by 604%
sequentially to $50.7 million for the quarter, versus $7.2 million in the
second quarter of 2012. When adjusting for the gain on sale of asset for the
quarter of $44.2 million, adjusted operating income was $6.5 million for the
quarter.

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

INTEREST EXPENSE

Interest expense for the quarter was $13.3 million, or $1.71 per Mcfe, versus
$13.0 million, or $1.22 per Mcfe in the prior year period. Non-cash interest
expense associated with the amortization of debt issuance cost and discount on
the Company's long term debt comprised 24% of the total, or $3.1 million
($0.40 per Mcfe).

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $18.8 million on its derivatives not designated
as hedges and an unrealized loss of $24.9 million, for a net loss on
derivatives of $6.1 million for the quarter.

During the quarter, the Company hedged an additional 500 barrels of oil per
day for the remainder of 2012 and 2013 at $92.50 per barrel, bringing the
total hedged oil volumes for the fourth quarter of 2012 to 3,500 barrels of
oil per day at a blended average price of $100.14 per barrel. The Company
hedged an additional 500 barrels of oil per day for 2013 at $95.85 per barrel,
bringing the total hedged oil volumes for 2013 to 1,500 barrels of oil per day
with straight swaps at a blended average price of approximately $97.17 per
barrel and 2,500 barrels of oil per day committed under a swaption, to be
exercised at the counterparty's option, at $100.82 per barrel.

CAPITAL EXPENDITURES

Capital expenditures for the quarter were down 22% sequentially to $57.8
million, of which $51.3 million was spent on drilling and completion costs,
$3.3 million on acreage acquisitions, $1.8 million on facility costs and $1.4
million on other expenditures. Capital expenditures for the first nine months
of the year were $193.5 million, of which $164.7 million was spent on drilling
and completion costs, $21.3 million on acreage acquisitions, $4.2 million on
facility costs and $3.3 million on other expenditures. 

For the quarter, the Company spent approximately $44.3 million, or 77% of its
capital, in the Eagle Ford Shale Trend where the Company had two rigs running
during the quarter, and $10.9 million, or 19%, in the Tuscaloosa Marine Shale
Trend, for a total of $55.2 million, or 96%, of its total capital on
oil-directed activity. Of the $10.9 million spent in the Tuscaloosa Marine
Shale Trend, approximately $1.4 million was spent on leasehold, which was
accounted for in our previously disclosed $27.5 million leasehold and
infrastructure budget. 

For the quarter, the Company conducted drilling operations on 13 gross (8 net)
wells, added 6 gross (4 net) wells to production and had 18 gross (9 net)
wells waiting on completion at the end of the quarter. The Company added 6
gross (4 net) wells to production from the Eagle Ford Shale Trend, with 5
gross (3 net) wells waiting on completion.

LIQUIDITY

The Company exited the quarter with $1.6 million in cash and $99.0 million
drawn on its senior bank revolving credit facility, under which the Company
currently has a borrowing base of $210 million, yielding approximately $113
million of liquidity.

OPERATIONAL UPDATE

Tuscaloosa Marine Shale Trend ("TMS")

The Company has fraced its initial operated well, the Denkmann 33 H-1, with 12
successful frac stages, but flowback has been delayed due to the need to
repair a casing connection. Flowback will commence upon completion of the
repair and installation of tubing.

The Company has drilled, cored and logged the vertical portion of its Crosby
12H-1 (50% WI) in Wilkinson County, MS, with plans for a 7,000 foot lateral.
In addition, the Company has participated in two additional non-operated
wells, the Joe Jackson 4H-2 (25% WI) in Wilkinson County, MS, which is
currently flowing back, and the Ash 31 H-1 (19% WI) in Amite County, MS, which
is in completion phase. The Ash 31 H-1 is the first well in which the lateral
was landed just above the zone that has caused wellbore instability, with a
very favorable outcome, which if repeatable should materially reduce drilling
costs going forward.

The Company anticipates running one rig in the TMS into the first quarter of
2013, and potentially adding or reallocating a second rig to the play in 2013
pending continued success. 

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale Trend, the Company conducted drilling operations on 10
gross (7 net) wells in the quarter, and expects to conduct drilling operations
on approximately 12 gross (8 net) wells in the fourth quarter of 2012, which
would bring the total to 32 gross (21 net) wells drilled for the year. The
Company has reduced its drill time on recent wells by approximately 40% to11
days for an average 6,400 foot lateral, which has increased the well count for
the year. The Company added 6 gross (4 net) wells to production for the
quarter, and expects to add 8 gross (5 net) wells to production in the fourth
quarter of 2012, which would bring the yearly total to 26 gross (17 net) wells
added to production. The Company expects to have approximately 7 gross (5
net) wells waiting on completion at year end due primarily to timing issues
related to its pad drilling. The Company is currently running two operated
rigs in the Eagle Ford Shale Trend.

Pearsall Shale

The Company owns deep rights to approximately 10,000 net acres prospective for
the Pearsall Shale on its Eagle Ford Shale Trend acreage. The Company is in
the preliminary planning stage for an early first quarter of 2013 Pearsall
well on its acreage in Frio County near a recently reported well that tested
at approximately 1,800 BOE per day (75% liquids). 

Haynesville Shale Trend

The Company now expects to complete 13 gross (6 net) previously drilled
Haynesville Shale wells in the first half of 2013, comprised of 12 gross (5
net) non-operated wells in North Louisiana and 1 gross (1 net) operated well
in the Angelina River Trend. Total capital expenditures are expected to be
approximately $22 million to complete these wells. Assuming timely
completion, the Company expects to grow gas volumes during 2013 from these
completions by approximately 10%. The Company expects to give additional
guidance in connection with the disclosures of its intended 2013 capital
expenditure budget in December.

South Henderson Divestiture

On September 28, 2012, the Company sold its interest in non-core properties in
the South Henderson field in Rusk County, Texas for $95 million, with an
effective date of July 1, 2012. During the quarter, production from the South
Henderson field averaged approximately 9,600 Mcf/d of natural gas and 200
Bbls/d of oil net to the Company.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial
measures, including Adjusted EBITDAX, DCF, drilling and completion capital
expenditures, 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, while drilling and completion capital expenditures are a
useful measure of the Company's annual drilling expenditures. Neither
discretionary cash flow, nor Adjusted EBITDAX, 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. Nor should drilling and
completion capital expenditures be considered an alternative to costs incurred
in oil and gas property acquisition, exploration, and development activities,
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, 2011 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        Nine Months Ended
                            September 30,             September 30,
                            2012         2011         2012         2011
Volumes
 Natural gas (MMcf)         5,991        9,468        20,215       27,562
 Oil and condensate         296          204          766          418
 (MBbls)
 MMcfe - Total              7,764        10,690       24,811       30,073
 Mcfe per day               84,396       116,200      90,553       110,157
Total Revenues              $ 45,960     $ 55,542     $ 132,614    $ 149,644
Operating Expenses
 Lease operating expense    6,218        5,447        21,267       15,565
 Production and other       1,672        1,599        5,752        4,194
 taxes
 Transportation and         3,410        2,795        11,060       7,482
 processing
 Depreciation, depletion    37,298       37,348       104,138      93,234
 and amortization
 Exploration                2,523        1,638        6,755        6,379
 Impairment                -            142          2,662        1,192
 General and                7,142        6,251        21,753       21,829
 administrative
 Gain on sale of assets     (44,157)     -            (44,229)     (236)
 Other                      -            146          -            146
Operating income (loss)    31,854       176          3,456        (141)
Other income (expense)
 Interest expense           (13,314)     (13,022)     (39,316)     (36,815)
 Interest income and other  2            21           3            43
 Gain (loss) on
 derivatives not            (6,137)      26,453       27,331       27,397
 designated as hedges
 Gain from extinguishment   -            4            -            62
 of debt
                            (19,449)     13,456       (11,982)     (9,313)
Income (loss) before        12,405       13,632       (8,526)      (9,454)
income taxes
Income tax benefit         -            -            -            -
Net income (loss)         12,405       13,632       (8,526)      (9,454)
Preferred stock dividends   1,511        1,511        4,535        4,535
Net income (loss)           $ 10,894     $ 12,121     $ (13,061)  $ (13,989)
applicable to common stock
 Unrealized (gain) loss on
 derivatives not            24,943       (18,163)     28,696       (5,995)
 designated as hedges
 Other - Hoover Tree Farm   -            146          -            146
 ruling litigation
 Gain on sale of assets     (44,157)     -            (44,229)     (236)
 Gain on extinguishment of  -            (4)          -            (62)
 debt
 Impairment                -            142          2,662        1,192
Adjusted net loss
applicable to common stock  $ (8,320)   $ (5,758)   $ (25,932)  $ (18,944)
(1)
 Discretionary cash flow
 (see non-GAAP              $ 36,928     $ 39,002     $ 101,627    $  99,083
 reconciliation) (2)
 Adjusted EBITDAX (see
 calculation and non-GAAP   $ 48,000     $ 49,089     $ 133,520    $ 126,502
 reconciliation)(3)
Weighted average common     36,391       36,125       36,365       36,104
shares outstanding - basic
Weighted average common
shares outstanding -        36,619       36,297       36,365       36,104
diluted (4)
Earnings per share
 Net income (loss)                                    $          $  
 applicable to common       $   0.30  $   0.34  (0.36)      (0.39)
 stock - basic
 Net income (loss)                                    $          $  
 applicable to common       $   0.30  $   0.33  (0.36)      (0.39)
 stock - diluted
Adjusted earnings per
share
 Adjusted net loss                                    $          $  
 applicable to common       $  (0.23)  $  (0.16)  (0.71)      (0.52)
 stock - basic (1)
 Adjusted net loss                                    $          $  
 applicable to common       $  (0.23)  $  (0.16)  (0.71)      (0.52)
 stock - fully diluted (1)



(1) Adjusted net income 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 excludesapproximately 9.9 million and 10.1 million
potentially dilutive instruments that were anti-dilutive due to the net income
(loss) applicable to common stock for the three and nine months ended
September 30, 2012, 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         Nine Months Ended
                             September 30,              September 30,
                             2012          2011         2012         2011
Average sales price per
unit:
 Oil (per Bbl)
  Including realized     $  105.63   $          $  105.63  $  
 gain on oil derivatives                  92.19                    94.51
  Excluding realized     $   97.43  $          $  100.46  $  
 gain on oil derivatives                   84.18                    89.65
 Natural gas (per Mcf)
  Including realized     $         $        $        $   
 gain on natural gas         5.60          4.76         5.34         4.74
 derivatives
  Excluding realized     $         $        $        $   
 gain on natural gas         2.87          4.05         2.76         4.04
 derivatives
 Natural gas and oil (per
 Mcfe)
  Including realized     $         $        $        $   
 gain on oil and natural     8.34          5.97         7.61         5.66
 gas derivatives
  Excluding realized     $         $        $        $   
 gain on oil and natural     5.92          5.20         5.35         4.95
 gas derivatives
Costs Per Mcfe
 Lease operating expense     $         $        $        $   
                             0.80          0.51         0.86         0.52
 Production and other taxes  $         $        $        $   
                             0.22          0.15         0.23         0.14
 Transportation and          $         $        $        $   
 processing                  0.44          0.26         0.45         0.25
 Depreciation, depletion     $         $        $        $   
 and amortization            4.80          3.49         4.20         3.10
 Exploration                 $         $        $        $   
                             0.32          0.15         0.27         0.21
 Impairment                 $        $        $        $   
                              -          0.01         0.11         0.04
 General and administrative  $         $        $        $   
                             0.92          0.58         0.88         0.73
 Gain on sale of assets      $          $       $         $   
                             (5.69)        -         (1.78)      (0.01)
 Other                       $        $        $       $    
                              -          0.01          -           -
                             $         $        $        $   
                             1.82          5.18         5.21         4.98
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      Nine Months Ended
                                  September 30,           September 30,
                                  2012      2011          2012       2011
Net cash provided by operating    $       $        $       $  
activities (GAAP)                 19,643    42,016        97,573    109,937
Net changes in working capital    17,285    (3,014)       4,054      (10,854)
Discretionary cash flow           $       $        $        $   
                                  36,928    39,002        101,627   99,083
Weighted average common shares    36,391    36,125        36,365     36,104
outstanding - basic
Weighted average common shares    36,619    36,297        36,365     36,104
outstanding - diluted (4)

Supplemental Balance Sheet Data
                           As of
                           September 30,  December 31,
                           2012           2011
 Cash and cash equivalents $   1,570   $      3,347
 Long-term debt            569,953        566,126

Reconciliation of Net income (loss) to Adjusted EBITDAX
                           Three Months Ended        Nine Months Ended
                           September 30,             September 30,
                           2012        2011          2012           2011
 Net loss (GAAP)           $  12,405  $   13,632  $   (8,526)  $  
                                                                    (9,454)
 Exploration expense       2,523       1,638         6,755          6,379
 Depreciation, depletion   37,298      37,348        104,138        93,234
 and amortization
 Impairment                -           142           2,662          1,192
 Stock compensation        1,676       1,349         4,711          4,526
 expense
 Interest expense         13,314      13,022        39,316         36,815
 Unrealized (gain) loss on
 derivatives not           24,943      (18,163)      28,696         (5,995)
 designated as hedges
 Other excluded items *    (44,159)    121           (44,232)       (195)
  Adjusted EBITDAX    $  48,000  $   49,089  $ 133,520     $ 126,502

 * Other excluded items include Interest income and other, Gain on sale of
 assets, Gain on early extinguishment of debt, Income taxes and Other expense.

Other Information
                                       Three Months Ended   Nine Months Ended
                                       September 30,        September 30,
                                       2012      2011       2012      2011
 Interest expense - cash               $       $      $       $  
                                       10,178    9,545     29,909   25,138
 Interest expense - noncash            3,136     3,477      9,407     11,677
 Total Interest                        13,314    13,022     39,316    36,815
 Unrealized (gain) loss on derivatives 24,943    (18,163)   28,696    (5,995)
 not designated as hedges
 Realized gain on derivatives not      (18,806)  (8,290)    (56,027)  (21,402)
 designated as hedges
 Total (gain) loss on derivatives not  6,137     (26,453)   (27,331)  (27,397)
 designated as hedges
 General and Administrative expense -  5,466     4,902      17,042    17,303
 cash
 General and Administrative expense -  1,676     1,349      4,711     4,526
 noncash
 Total General and Administrative      7,142     6,251      21,753    21,829
 expense



GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data continued (In Thousands):
Reconciliation of Adjusted Revenues and Total Revenues (unaudited)
                                         Three Months Ended  Nine Months Ended
                                         September 30,       September 30,
                                         2012      2011      2012      2011
Total Revenues (GAAP)                    $       $      $      $   
                                         45,960    55,542    132,614   149,644
Realized gain on derivatives not         18,806    8,290     56,027    21,402
designated as hedges
Adjusted Revenues                        $       $      $      $   
                                         64,766    63,832    188,641   171,046

Reconciliation of Adjusted Operating Income and Operating Income (unaudited)
                                Three Months Ended    Nine Months Ended
                                September 30,         September 30,
                                2012      2011        2012         2011
Operating income (loss) (GAAP)  $       $       $       $     
                                31,854      176     3,456         (141)
Realized gain on derivatives    18,806    8,290       56,027       21,402
not designated as hedges
Adjusted Operating Income       $       $       $        $    
                                50,660     8,466     59,483       21,261

Calculation of Cash operating margin (unaudited)
                                     Three Months Ended  Nine Months Ended
                                     September 30,       September 30,
                                     2012        2011    2012       2011
Adjusted EBITDAX (see calculation    $ 48,000    $     $ 133,520  $ 126,502
and non-GAAP reconciliation) (3)                 49,089
Adjusted Revenues (see non-GAAP      $ 64,766    $     $ 188,641  $ 171,046
reconciliation)                                  63,832
Cash operating margin                74%         77%     71%        74%

SOURCE Goodrich Petroleum Corporation

Website: http://www.goodrichpetroleum.com
Contact: Robert C. Turnham, Jr., President, or Jan L. Schott, Chief Financial
Officer, Daniel E. Jenkins, Director of Investor Relations, +1-713-780-9494