Goodrich Petroleum Announces Year-End And Fourth Quarter Financial Results And Operational Update

Goodrich Petroleum Announces Year-End And Fourth Quarter Financial Results And
                              Operational Update

PR Newswire

HOUSTON, Feb. 20, 2013

HOUSTON, Feb. 20, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE:
GDP) today announced financial and operating results for the year and fourth
quarter ended December 31, 2012.

  oAdjusted EBITDAX grew 5 percent sequentially and 18 percent from the prior
    year period to a record$50.5 Million for the quarter, while Discretionary
    Cash Flow grew by 8 percent sequentially and 15 percent from the prior
    year period to $39.9 Million for the quarter
  oAdjusted Revenues, including realized gain on derivatives of $17.1
    Million, totaled $65.4 Million for the quarter
  oOil production grew by 12.5% sequentially and 47% over the prior year
    period to an average of 3,600 barrels of oil per day for the quarter,
    which comprised 30% of total production for the quarter. Oil production
    for the year increased by 70% over the prior year
  oTuscaloosa Marine Shale: The Crosby 12H-1 well (50% WI), the Company's
    initial operated completed well in the field, had a peak, 24-hour average
    rate of approximately 1,300 barrels of oil equivalent ("BOE") per day,
    comprised of approximately 1,200 barrels of oil and 600 Mcf of natural gas
    per day. The well hasaveraged 1,200 BOE per day over 15 days, comprised
    of 1,100 barrels of oil and 600 Mcf of natural gas per day, and is
    currently producing at 1,200 BOE per day. 

(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.)

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative
expenses and exploration (" Adjusted EBITDAX") increased by 18% to $50.5
million in the quarter, compared to $42.7 million in the prior year period and
$48.0 million in the prior quarter. Adjusted EBITDAX for the year increased
by 9% to $184.0 million versus $169.2 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 15% to $39.9
million in the quarter, compared to $34.8 million in the prior year period and
$36.9 million in the prior quarter. DCF increased by 6% to $141.5 million for
the year, versus $133.8 million in the prior year period. Net cash provided
by operating activities for the year increased by 28% to $173.8 million,
compared to $136.3 million for 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 a net loss applicable to common stock of $77.2 million
for the quarter, or ($2.12) per basic share, versus a net loss applicable to
common stock of $23.8 million, or ($0.66) per basic share in the prior year
period. The quarter was negatively impacted by non-recurring expenses of
$58.0 million, comprised of $45.2 million for impairment of natural gas assets
and $12.8 million of exploration expense associated with the Company's partial
abandonment of a well in one of its fields. The Company announced a net loss
applicable to common stock of $90.2 million for 2012, or ($2.48) per basic
share, versus a net loss applicable to common stock of $37.8 million, or
($1.05) per basic share for 2011.

(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

Production for the quarter was 6.6 billion cubic feet equivalent ("Bcfe"), or
an average of 71,800 Mcfe per day, versus 10.0 Bcfe, or an average of 108,200
Mcfe per day in the prior year period. Oil production for the quarter totaled
329,000 barrels of oil, or an average of approximately 3,600 barrels per day,
versus 225,000 barrels of oil, or 2,450 barrels per day, in the prior year
period. Peak rate for the quarter was approximately 4,350 barrels of oil per
day. Natural gas production for the quarter totaled 4.6 Bcf, or an average of
50,300 Mcf per day. Production for the year totaled 1.1 million barrels of
oil, a 70% increase over 2011, and 24.8 Bcf of natural gas, or an average of
85,800 Mcfe per day.

REVENUES

Revenues for the quarter were $48.2 million versus $51.4 million in the prior
year period. Revenues, including realized gain on derivatives not designated
as hedges of $17.1 million for the quarter, would have been $65.4 million.
Average realized price per unit for the quarter, was $7.24 per Mcfe, versus
$5.18 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
$9.83 per Mcfe, versus $6.17 in the prior year period.

Revenues for the year totaled $180.8 million, versus $201.1 million in the
prior year period. Revenues, including realized gain on derivatives not
designated as hedges of $73.2 million for the year, would have been $254.0
million. Average realized price per unit for the year, was $5.75 per Mcfe,
versus $5.01 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 $8.08 per Mcfe, versus $5.79 per Mcfe in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") was $4.7 million in the quarter, or $0.71 per
Mcfe, versus $5.9 million, or $0.60 per Mcfe in the prior year period. For
the year, LOE totaled $25.9 million, or $0.83 per Mcfe, versus $21.5 million,
or $0.54 per Mcfe in the prior year period.

Production and other taxes for the quarter were $2.4 million, or $0.36 per
Mcfe, versus $1.3 million, or $0.13 perMcfein the prior year period. For
the year, production and other taxes totaled $8.1 million, or $0.26 per Mcfe,
versus $5.5 million, or $0.14 per Mcfe in the prior year period.

Transportation and processing expense was $2.8 million, or $0.43 per Mcfe in
the quarter, versus $5.5 million, or $0.55 per Mcfe in the prior year period.
For the year, transportation expense was $13.9 million, or $0.44 per Mcfe,
versus $13.0 million, or $0.32 per Mcfe in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense for the quarter
totaled $37.1 million, or $5.62 per Mcfe, versus $38.6 million, or $3.87 per
Mcfe in the prior year period. DD&A expense for the year totaled $141.2
million, or $4.50 per Mcfe, versus $131.8 million, or $3.29 per Mcfe for the
prior year period.

Exploration expense was $16.4 million, or $2.48 per Mcfe for the quarter,
versus $1.9 million, or $0.19 per Mcfe in the prior year period. Exploration
expense for the year was $23.1 million, or $0.74 per Mcfe, versus $8.3
million, or $0.21 per Mcfe in the prior year. Approximately $12.8 million or
78% of exploration expense for the quarter and 56% for the year was associated
with the dry hole expense related to the Denkmann 33H-1 mechanical failure.

Impairment expense was $45.2 million, or $6.84 per Mcfe for the quarter,
versus $6.9 million, or $0.69 per Mcfe in the prior year period. Impairment
expense for the year was $47.8 million, or $1.52 per Mcfe, versus $8.1
million, or $0.20 per Mcfe during the prior year period. Impairment expense
during the quarter was mostly due to the impact of falling natural gas prices
on our Angelina River trend field in Texas.

General and Administrative ("G&A") expense was $7.2 million, or $1.09 per Mcfe
in the quarter, versus $8.0 million, or $0.80 per Mcfe in the prior year
period. For the quarter, the Company recorded non-cash G&A expenses related
to stock based compensation for its officers and employees of $2.2 million, or
$0.33 per Mcfe, versus $2.0 million, or $0.20 per Mcfe in the prior year
period. For the year, G&A expense totaled $28.9 million, or $0.92 per Mcfe,
versus $29.8 million, or $0.74 per Mcfe in the prior year period. Non-cash,
stock based compensation for the year was 24% of G&A expenses, or $6.9
million, which was $0.22 per Mcfe, versus $6.5 million, or $0.16 per Mcfe for
the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss
of $67.1 million for the quarter versus an operating loss of $16.9 million for
the prior year period. Operating income was negatively impacted by $58.0
million of non-recurring, non-cash expenses in the quarter. Operating income
for the year was a loss of $63.7 million versus an operating loss of $17.1
million for the prior year period.

(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 $13.1 million, or $1.98 per Mcfe, versus
$12.5 million, or $1.26 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 ($0.52 per Mcfe). For the year, interest expense was
$52.4 million, or $1.67 per Mcfe, versus $49.4 million, or $1.23 per Mcfe in
the prior year. Non-cash interest expense comprised 24% of the total for the
year, or $12.8 million ($0.41 per Mcfe).

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $57.2 million, of which $54.0
million was spent on drilling and completion costs and $3.1 million on
leasehold acquisition, facilities and other expenditures. For the full year
2012, capital expenditures totaled $250.7 million, of which $218.7 million was
for drilling and completion costs (90% oil directed activities) and $32.0
million was for leasehold, infrastructure and other miscellaneous
expenditures. Drilling and completion expenditures of $218.7 million were
comprised of $94.6 million for wells drilled in 2012 that had new reserve
additions, $73.2 million, or 33% of the Company's drilling and completion
capital expenditures for the year, for the conversion of 16 proved undeveloped
reserve locations to proved developed reserves in 2012, $28.5 million for
wells with drilling and/or completion operations in 2012 that did not have
reserves booked at year-end and $22.4 million of carry-over drilling and
completion costs from wells drilled in prior years.

YEAR-END RESERVES

The Company's proved oil and natural gas reserves as of December 31, 2012 were
333.1 Bcfe, versus 490 Bcfe in the prior year period. The Company incurred
negative reserve revisions of 121 Bcfe of natural gas reserves at year-end
that were on the books at year-end 2011 primarily related to the loss of
proved undeveloped natural gas reserves, mainly in Northwest Louisiana and
East Texas areas, as a result of such reserves being uneconomic under SEC
pricing.The Company also sold 36.1 Bcfe during the year in an asset sale of
a non-core property. Year-end proved reserves were 76% natural gas, 24% oil
and liquids (an increase from 17% at year-end 2011) and 48% developed. The
present value, using a 10% discount rate of the future net cash flows before
income taxes of the proved reserves ("PV-10"), was $359.1 million, using SEC
pricing of $2.85 per MMBtu for natural gas and $94.71 per barrel of oil. At
current five year futures NYMEX pricing of $90.13 per barrel of oil (WTI) and
$4.17 per MMBtu of natural gas, the year-end proved reserves would have been
442 Bcfe and the relatedPV-10 would have been $530 million. Year-end PV-10
of proved reserves is a non-GAAP financial measure. Please refer to "Other
Information" section for additional disclosure and nformation.

The Company had provednew reserve additions from its oil directed activities
in 2012 of 5.40 million BOE (32.4 Bcfe) and proved developed reserve
additions, adjusted for the conversion of proved undeveloped reserve locations
to proved developed reserves, of 5.87 million BOE (35.2 Bcfe). The Company
had approximately $202.1 million of net drilling and completion capital
expenditures associated with these 2012 wells, for an adjusted organic finding
and development cost of $6.23 per Mcfe ($37.43 per BOE). Adjusted proved
developed finding and development cost for 2012 wells was $5.74 per Mcfe
($34.45 per BOE). Approximately 90% of the drilling and completion capital
expenditures associated with 2012 wells were from oil-focused activities.

The Company's successful Eagle Ford Shale drilling program was the primary
driver of the growth in proved oil and liquids reserves in 2012.

The following table reflects the changes in the proved reserve estimates since
year-end 2011:

                                                                Proved
                                                      Proved   Developed
                                                      Reserves  Reserves
                                                      (Bcfe)    (Bcfe)
Reserves at December 31, 2011         489.8     208.5
                                                 (32.2)    (32.2)
Production
                                           (36.1)    (30.7)
Divestitures
 Reserve                                   32.4      35.2
Additions^(1)
 Revisions – Price and Technical     (120.9)   (22.4)
Reserves at December 31, 2012               333.1     158.4
2012 Reserve Replacement Ratio (%)^(2)         100%      109%
2012 Net Cash Drilling and Completion Capital Expenditures      $202.1 MM
(non-GAAP)^(3)
2012 Finding and Development Costs                              $6.23
($/Mcfe)^(4)                    ($37.43/BOE)
2012 Proved Developed Finding & Development Costs               $5.74
($/Mcfe)^(5)                                             ($34.45/BOE)

(1) Proved Developed Reserve Additions includes the conversion of Proved
    Undeveloped Reserves to Proved Developed Reserves.
(2) Reserve Replacement Ratio is calculated by dividing Reserve Additions
    (before price and technical revisions) by Production.
(3) See Net Cash Drilling and Completion Capital Expenditures (non-GAAP) in
    "Other Information" section for additional disclosure and information.
    Finding and Development Costs per Mcfe is calculated by dividing Net Cash
(4) Drilling and Completion Capital Expenditures (non-GAAP) for wells drilled
    in 2012 by total proved reserve additions (before price and technical
    revisions).
    Proved Developed Finding and Development Costs per Mcfe is calculated by
(5) dividing Net Cash Drilling and Completion Capital Expenditures for wells
    drilled in 2012 by Proved Developed Reserve Additions (before price and
    technical revisions).

The reserve report was prepared by Netherland, Sewell & Associates,
Inc.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $17.1 million on its derivatives not designated
as hedges and an unrealized loss of $12.6 million, for a net gain on
derivatives of $4.6 million for the quarter.

During the quarter, the Company hedged an additional 2,000 barrels of oil per
day for 2013, bringing the total hedged oil volumes for 2013 to 3,500 barrels
of oil per day at a blended average price of $94.50 per barrel.

LIQUIDITY

The Company exited the year with $1.2 million in cash and $95.0 million drawn
on its senior bank revolving credit facility, providing $116.2 million of
availableliquidity as the Company entered 2013. The Company's borrowing base
is currently $210 million, with a new borrowing base expected in the second
quarter. The Company expects to finance the vast majority of its 2013 capital
expenditure budget with cash on hand and increasing cash flow driven by growth
in oil volumes.

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 14 gross (8 net)
wells, of which 11 gross (7 net) were in the Eagle Ford and 3 gross (1 net)
were in the Tuscaloosa Marine Shale Trend. A total of 9 gross (7 net) wells
were added to production during the quarter, of which 8 gross (5 net) were in
the Eagle Ford. For the year, the Company conducted drilling operations on 46
gross (27 net) wells, with a 100% success rate. As of December 31, 2012, the
Company had 20 gross (11 net) wells waiting on completion, with 13 gross (6
net) in the Haynesville Shale Trend and 7 gross (5 net) in the Eagle Ford
Shale Trend.

Tuscaloosa Marine Shale Trend ("TMS")

The Company previously reported production results on its Crosby 12H-1 (50%
WI), the initial operated well completed in the field, at a then 24-hour peak
production rate of 1,150 BOE per day on a 15/64 choke with 2,700 psi. The well
improved after the announcement, and achieved a 24-hour peak rate of 1,300 BOE
and has averaged 1,200 BOE per day over the initial 15 day period, comprised
of 1,100 barrels of oil and 600 Mcf of gas per day. Based on the success of
the Crosby well and the Company's increasing confidence in the economic
potential of the play, the Company will accelerate the timing of its next
operated well and now anticipates spudding its Smith 29H-1 (~ 75% WI) well in
Amite County, Mississippi in April, and as previously stated, has increased
its 2013 allocation of capital to the play to $50 million, which is the higher
end of its guidance. Upon additional funding, the Company will consider
accelerating its activity level further in the TMS.

The Company is currently participating as a non-operator in the completion of
the Ash 31H-1 (12% WI) and Ash 31H-2 (12% WI) wells in Amite County,
Mississippi. The wells, which are currently being fracked, are the initial
wells in which the Company has participated that have landed above the zone
that has caused wellbore instability.

The Company is currently participating as a non-operator in two development
wells, the Anderson 17H-2 (7% WI) and Anderson 17H-3 (7% WI) wells.

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale Trend, the Company conducted drilling operations on 11
gross (7 net) wells in the quarter, and expects to drill 24 – 28 gross (16 –
19 net) wells in 2013. The Company has reduced its drill time on recent wells
by approximately 57% from the initial wells drilled in the field, to 10 days
for an average 6,000 foot lateral, which along with a reduction in frac costs,
has substantially decreased the well costs and increased the well count for
the year.

Haynesville Shale Trend

The Company 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 naturalgas volumes during 2013 from
these completions by approximately 10%.

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, Cash operating margin and year-end pretax present
worth of proved reserves discounted at 10% "PV-10". Management believes
Adjusted EBITDAX, Discretionary cash flow, Adjusted revenues, Adjusted
operating income, Adjusted net loss applicable to common stock and Cash
operating marginare 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 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 GAAP-required standardized measure of discounted
future net cash flows ("SMOG"). The company's discounted future income taxes
are estimated to be $1.6 million at December 31, 2012 to arrive at a SMOG of
$357.4 million. 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.

Quantitative Reconciliation of Net Cash Drilling and Completion Capital
Expenditures (non-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 (GAAP):

Net Cash Used In Investing Activities (GAAP)           $161,494
Less: Cash Spent in 2012 for Expenditures Booked in 2011         (22,303)
Add: Proceeds from Sale of Assets 90,922
Net Capital Expenditures Booked in 2012 (non-GAAP)        $230,113
Less:  Leasehold                                                     (22,325)
Acquisitions
 Facilities &                                               (5,176)
Infrastructure
 Furniture, Fixtures & Equipment    (558)
Net Cash Drilling and Completions Capital Expenditures (non-GAAP)   $202,054

GOODRICH PETROLEUM CORPORATION
SELECTED INCOME AND PRODUCTION DATA
(In Thousands, Except Per Share Amounts)
                                Three Months Ended      Year Ended
                                December 31,            December 31,
                                2012        2011        2012        2011
Volumes
 Natural gas (MMcf)             4,630       8,605       24,844      36,167
 Oil and condensate (MBbls)     329         225         1,095       644
 MMcfe - Total                  6,603       9,956       31,415      40,029
 Mcfe per day                   71,774      108,220     85,832      109,669
Total Revenues                  $ 48,231    $ 51,425    $ 180,845   $ 201,069
Operating Expenses
 Lease operating expense        4,671       5,925       25,938      21,490
 Production and other taxes     2,363       1,256       8,115       5,450
 Transportation and processing  2,840       5,492       13,900      12,974
 Depreciation, depletion and    37,084      38,577      141,222     131,811
 amortization
 Exploration                    16,367      1,910       23,122      8,289
 Impairment                     45,156      6,919       47,818      8,111
 General and administrative     7,177       7,970       28,930      29,799
 Gain on sale of assets         (377)       -           (44,606)    (236)
 Other                          91          302         91          448
Operating loss                  (67,141)    (16,926)    (63,685)    (17,067)
Other income (expense)
 Interest expense               (13,087)    (12,536)    (52,403)    (49,351)
 Interest income and other      1           16          4           59
 Gain on derivatives not        4,551       7,142       31,882      34,539
 designated as hedges
 Gain on extinguishment of      -           -           -           62
 debt
                                (8,535)     (5,378)     (20,517)    (14,691)
Loss before income taxes        (75,676)    (22,304)    (84,202)    (31,758)
Income tax benefit              -           -           -           -
Net loss                        (75,676)    (22,304)    (84,202)    (31,758)
Preferred stock dividends       1,512       1,512       6,047       6,047
Net loss applicable to common   $ (77,188)  $ (23,816)  $ (90,249)  $ (37,805)
stock
 Unrealized (gain) loss on
 derivatives not designated as  12,582      2,761       41,278      (3,234)
 hedges
 Other - litigation             91          302         91          448
 Gain on sale of assets         (377)       -           (44,606)    (236)
 Gain on extinguishment of      -           -           -           (62)
 debt
 Dry hole costs                 12,848      -           12,848      -
 Impairment                     45,156      6,919       47,818      8,111
Adjusted net loss applicable    $ (6,888)   $ (13,834)  $ (32,820)  $ (32,778)
to common stock (1)
 Discretionary cash flow (see   $ 39,858    $ 34,755    $ 141,485   $ 133,838
 non-GAAP reconciliation) (2)
 Adjusted EBITDAX (see
 calculation and non-GAAP       $ 50,505    $ 42,654    $ 184,025   $ 169,156
 reconciliation) (3)
Weighted average common shares  36,465      36,183      36,390      36,124
outstanding - basic
Weighted average common shares  36,465      36,183      36,390      36,124
outstanding - diluted (4)
Earnings per share
 Net loss applicable to common  $ (2.12)    $ (0.66)    $ (2.48)    $ (1.05)
 stock - basic
 Net loss applicable to common  $ (2.12)    $ (0.66)    $ (2.48)    $ (1.05)
 stock - diluted
Adjusted earnings per share
 Adjusted net loss applicable   $ (0.19)    $ (0.38)    $ (0.90)    $ (0.91)
 to common stock - basic (1)
 Adjusted net loss applicable
 to common stock - fully        $ (0.19)    $ (0.38)    $ (0.90)    $ (0.91)
 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 extinguishment of debt and Other expense.
 (4) Fully diluted shares excludes approximately 10.2 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 months and year ended
 December 31, 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         Year Ended
                               December 31,               December 31,
                               2012          2011         2012         2011
Average sales price per unit:
 Oil (per Bbl)
  Including realized gain  $  110.12   $          $  106.98  $  
 on oil derivatives                         99.42                    96.23
  Excluding realized gain  $   98.63  $          $         $  
 on oil derivatives                          94.47       99.91        91.34
 Natural gas (per Mcf)
  Including realized gain  $         $        $        $   
 on natural gas derivatives    6.20          4.54         5.50         4.70
  Excluding realized gain  $         $        $        $   
 on natural gas derivatives    3.31          3.52         2.86         3.92
 Natural gas and oil (per
 Mcfe)
  Including realized gain  $         $        $        $   
 on oil and natural gas        9.83          6.17         8.08         5.79
 derivatives
  Excluding realized gain  $         $        $        $   
 on oil and natural gas        7.24          5.18         5.75         5.01
 derivatives
Costs Per Mcfe
 Lease operating expense       $         $        $        $   
                               0.71          0.60         0.83         0.54
 Production and other taxes    $         $        $        $   
                               0.36          0.13         0.26         0.14
 Transportation and            $         $        $        $   
 processing                    0.43          0.55         0.44         0.32
 Depreciation, depletion and   $         $        $        $   
 amortization                  5.62          3.87         4.50         3.29
 Exploration                   $         $        $        $   
                               2.48          0.19         0.74         0.21
 Impairment                   $         $        $        $   
                               6.84          0.69         1.52         0.20
 General and administrative    $         $        $        $   
                               1.09          0.80         0.92         0.74
 Gain on sale of assets        $          $       $         $   
                               (0.06)          -        (1.42)       (0.01)
 Other                         $         $        $       $   
                               0.01          0.03          -         0.01
                               $          $        $        $   
                               17.47         6.87         7.78         5.45
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,
                          2012            2011           2012        2011
Net cash provided by                      $         $         $  
operating activities      $   76,216    26,403         173,789    136,340
(GAAP)
Net changes in working    (36,358)        8,352          (32,304)    (2,502)
capital
Discretionary cash flow   $   39,858    $         $         $  
                                          34,755         141,485    133,838
Weighted average common
shares outstanding -      36,465          36,183         36,390      36,124
basic
Weighted average common
shares outstanding -      36,465          36,183         36,390      36,124
diluted (4)
Supplemental Balance Sheet Data
                          As of
                          December 31,    December 31,
                          2012            2011
  Cash and cash           $            $     
  equivalents             1,188           3,347
  Long-term debt          568,671         566,126
Reconciliation of Net income (loss) to Adjusted EBITDAX
                          Three Months Ended             Year Ended
                          December 31,                   December 31,
                          2012            2011           2012        2011
  Net loss (GAAP)         $  (75,676)   $          $         $  
                                          (22,304)       (84,202)   (31,758)
  Exploration expense     16,367          1,910          23,122      8,289
  Depreciation, depletion 37,084          38,577         141,222     131,811
  and amortization
  Impairment              45,156          6,919          47,818      8,111
  Stock compensation      2,192           1,969          6,903       6,495
  expense
  Interest expense       13,087          12,536         52,403      49,351
  Unrealized (gain) loss
  on derivatives not      12,582          2,761          41,278      (3,234)
  designated as hedges
  Other excluded items *  (287)           286            (44,519)    91
   Adjusted EBITDAX  $   50,505    $         $         $  
                                          42,654         184,025    169,156
  * Other excluded items include Interest income and other, Gain on sale of
  assets, Gain on extinguishment of debt, Income taxes and Other expense.
Other Information
                          Three Months Ended             Year Ended
                          December 31,                   December 31,
                          2012            2011           2012        2011
  Interest expense - cash $            $         $        $   
                          9,674           9,862        39,583     35,000
  Interest expense -      3,413           2,674          12,820      14,351
  noncash
  Total Interest          13,087          12,536         52,403      49,351
  Unrealized (gain) loss
  on derivatives not      12,582          2,761          41,278      (3,234)
  designated as hedges
  Realized gain on
  derivatives not         (17,133)        (9,903)        (73,160)    (31,305)
  designated as hedges
  Total gain on
  derivatives not         (4,551)         (7,142)        (31,882)    (34,539)
  designated as hedges
  General and
  Administrative expense  4,985           6,001          22,027      23,304
  - cash
  General and
  Administrative expense  2,192           1,969          6,903       6,495
  - noncash
  Total General and       7,177           7,970          28,930      29,799
  Administrative expense

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,
                                2012       2011         2012         2011
Total Revenues (GAAP)           $        $         $         $   
                                48,231     51,425      180,845      201,069
Realized gain on derivatives    17,133     9,903        73,160       31,305
not designated as hedges
Adjusted Revenues               $        $       $         $   
                                65,364     61,328       254,005      232,374
Reconciliation of Adjusted Operating Income (Loss) and Operating Loss
(unaudited)
                                Three Months Ended      Year Ended
                                December 31,            December 31,
                                2012       2011         2012         2011
Operating loss (GAAP)           $         $          $         $   
                                (67,141)  (16,926)    (63,685)     (17,067)
Realized gain on derivatives    17,133     9,903        73,160       31,305
not designated as hedges
Adjusted Operating Income       $         $       $       $    
(Loss)                          (50,008)  (7,023)      9,475        14,238
Calculation of Cash operating margin (unaudited)
                                Three Months Ended      Year Ended
                                December 31,            December 31,
                                2012       2011         2012         2011
Adjusted EBITDAX (see           $        $         $         $   
calculation and non-GAAP        50,505     42,654      184,025      169,156
reconciliation) (3)
Adjusted Revenues (see non-GAAP $        $       $         $   
reconciliation)                 65,364     61,328       254,005      232,374
Cash operating margin           77%        70%          72%          73%

SOURCE Goodrich Petroleum Corporation

Website: http://www.goodrichpetroleum.com
Contact: Robert C. Turnham, Jr., President, or Jan L. Schott, Chief Financial
Officer, Main: (713) 780-9494, Fax: (713) 780-9254
 
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