Goodrich Petroleum Announces Second Quarter 2014 Financial Results And Operational Update

    Goodrich Petroleum Announces Second Quarter 2014 Financial Results And
                              Operational Update

PR Newswire

HOUSTON, Aug. 7, 2014

HOUSTON, Aug. 7, 2014 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE:
GDP) (the "Company") today announced financial and operating results for the
second quarter ended June 30, 2014.

FINANCIAL RESULTS:

  oRevenues totaled $53.3 million in the quarter versus $48.5 million in the
    prior year period. Average realized price per unit was $8.53 per Mcfe in
    the quarter versus $7.22 per Mcfe in the prior year period;
  oEarnings before interest, taxes, DD&A, non-cash general and administrative
    expenses and exploration ("Adjusted EBITDAX") totaled $31.5 million for
    the quarter and $60.5 million for the six month period ended June 30,
    compared to $31.5 million in the prior year quarter and $58.6 million in
    the prior year six month period;
  oOil production increased 30% to 381,000 barrels, or approximately 4,200
    Bbls/day, during the quarter, compared to 292,000 barrels, or
    approximately 3,200 Bbls/day in the prior year period. Oil production
    grew 11% sequentially over the prior quarter.

TUSCALOOSA MARINE SHALE ("TMS"):

  oThe Company's SLC, Inc. 81H-1 (67% WI) well in West Feliciana Parish,
    Louisiana has achieved a peak 24-hour production rate to date of
    approximately 900 Boe/day (96% oil) from an approximate 7,000 foot lateral
    with 27 frac stages.
  oThe non-operated Lewis 7-18H-1 (17% WI) well in Amite County,
    Mississippi, has achieved a peak 24-hour production rate to date of
    approximately 1,500 Boe/day (93% oil) from an approximate 8,100 foot
    lateral with 29 frac stages.
  oThe non-operated Mathis 29-32H-1 well in Amite County, Mississippi has
    achieved a peak 24-hour production rate to date of approximately 1,300
    Boe/day (92% oil) from an approximate 6,400 foot lateral with 17 frac
    stages. The Company owns a 6.5% reversionary interest in the well and the
    right to participate in subsequent wells drilled in the unit.
  oThe Company's previously announced Beech Grove 94H-1 (67% WI) well in East
    Feliciana Parish, Louisiana, which had a reported initial rate of 740
    Boe/day, achieved a 30-day average production rate of approximately 600
    Boe/day (90% oil). The Beech Grove continues to perform very well and has
    thus far exhibited a flatter decline curve profile. The well is currently
    producing approximately 550 Boe/day and is currently on the Company's 600
    MBoe type curve.

FINANCIAL RESULTS

REVENUES

Revenues totaled $53.3 million in the quarter versus $48.5 million in the
prior year period. Average realized price per unit was $8.53 per Mcfe in the
quarter versus $7.22 per Mcfe in the prior year period. When factoring in the
realized gain or loss on derivatives not designated as hedges, Adjusted
Revenues totaled $50.2 million in the quarter versus $48.6 million in the
prior year period, and average realized price per unit was $8.04 per Mcfe
versus $7.23 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.) 

PRODUCTION

Production totaled 6.2 billion cubic feet equivalent ("Bcfe") in the quarter,
or an average of 68,600 Mcfe/day, versus 6.7 Bcfe, or an average of 73,200
Mcfe/day in the prior year period. Oil production totaled 381,000 barrels of
oil in the quarter, or an average of approximately 4,200 Bbls/day, versus
292,000 barrels of oil, or an average of approximately 3,200 Bbls/day, in the
prior year period. Oil production grew 11% sequentially over the prior
quarter. Oil production growth for the quarter was back-end loaded, with
current production of approximately 4,800 – 5,000 Bbls/day and third quarter
guidance of 4,800 – 5,400 Bbls/day. Natural gas production totaled 4.0 Bcf in
the quarter, or an average of approximately 43,500 Mcf/day, versus 4.9 Bcf, or
an average of 54,000 Mcf/day, in the prior year period. The Company
anticipates producing 37,000 – 39,000 Mcf/day of natural gas during the third
quarter of 2014.

CAPITAL EXPENDITURES

Capital expenditures totaled $106.5 million in the quarter, of which $89.9
million was spent on drilling and completion costs, $13.2 million on leasehold
acquisition and $3.4 million on facilities, capital workovers and other
expenditures. Approximately 70% of the quarter's total capital expenditures
were spent in the TMS drilling and completing wells and extending existing
leasehold for future drilling operations.Capital expenditures for the first
six months of the year totaled $162.3 million, and the Company currently
anticipates that its full year 2014 capital expenditure budget will be at the
low end of the previously issued guidance range of $325 – $375 million. 

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
and the prior year period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, was $18.4 million in the
quarter, compared to $20.9 million in the prior year period. Net cash
provided by operating activities was $63.3 million in the quarter, compared to
$29.6 million in the prior year period.

DCF was impacted by non-recurring other operating expenses of $3.4 million
comprised of $2.8 million for gathering and marketing costs on non-operated
Haynesville Shale assets, which the Company is currently disputing, and a $0.6
million litigation charge pertaining to a long standing working interest
dispute on a property the Company no longer owns. Adjusted EBITDAX and DCF
were both impacted by a $3.1 million realized loss on derivatives not
designated as hedges during the quarter compared to a $0.1 million realized
gain on derivatives not designated as hedges during the prior year
period. 

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

NET INCOME

The Company announced a net loss applicable to common stock of $32.5 million
in the quarter, or ($0.73) per basic share, versus a net loss applicable to
common stock of $20.1 million, or ($0.55) per basic share in the prior year
period. Adjusted net loss applicable to common stock was $21.3 million for
the quarter, or ($0.48) per basic share, which excludes the impact of
unrealized losses on derivatives not designated as hedges of $6.7 million,
non-cash leasehold expirationof $1.1 million, and non-recurring other
expenses of $3.4 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.)

OPERATING EXPENSES

Lease operating expense ("LOE") was $7.3 million in the quarter, or $1.17 per
Mcfe, versus $5.9 million, or $0.88 per Mcfe, in the prior year period. LOE
for the quarter included $1.4 million, or $0.22 per Mcfe, for workovers
performed in the quarter, versus $1.1 million, or $0.17 per Mcfe, in the prior
year period. The majority of the Company's workover expense pertained to
cleanout operations on wells in the Eagle Ford and Haynesville Shale
trends. 

Production and other taxes were $2.0 million in the quarter, or $0.32 per
Mcfe, versus $2.7 million, or $0.41 per Mcfe, in the prior year period.
Production taxes continued to decrease in the quarter versus the prior year
period due primarily to higher oil volumes from the TMS, where new wells are
subject to no or very low production taxes until payout of the well is
achieved. 

Transportation and processing expense was $2.3 million in the quarter, or
$0.37 per Mcfe, versus $2.5 million, or $0.37 per Mcfe, in the prior year
period. 

Depreciation, depletion and amortization ("DD&A") expense was $30.1 million in
the quarter, or $4.82 per Mcfe, versus $34.5 million, or $5.18 per Mcfe, in
the prior year period. The decline in DD&A expense per unit of production was
driven primarily by higher year-end 2013 reserves and lower capital
expenditures per well in the Eagle Ford Shale trend.

Exploration expense was $2.4 million in the quarter, or $0.38 per Mcfe, versus
$9.5 million, or $1.43 per Mcfe, in the prior year period, which included
non-cash expenses associated with expiration of non-core, undeveloped
leasehold in the Eagle Ford Shale trend.

General and Administrative ("G&A") expense was $9.5 million in the quarter, or
$1.51 per Mcfe, versus $7.6 million, or $1.15 per Mcfe, in the prior year
period, primarily due to higher compensation expense and stock based
compensation in the current quarter. G&A expense related to non-cash, stock
based compensation totaled $2.3 million in the quarter, or $0.37 per Mcfe,
versus $1.7 million, or $0.26 per Mcfe, in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss
of $3.6 million in the quarter, versus an operating loss of $14.2 million in
the prior year period. Adjusted operating loss, when adjusted for realized
loss on derivatives not designated as hedges, was a loss of $6.6 million for
the quarter.

(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 totaled $11.8 million in the quarter, or $1.88 per Mcfe,
versus $13.0 million, or $1.96 per Mcfe, in the prior year period. Non-cash
interest expense associated with the Company's debt totaled $2.7 million
(representing 23% of total interest expense) in the quarter, or $0.43 per
Mcfe, versus $3.4 million, or $0.51 per Mcfe, in the prior year period.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a loss of $3.1 million on its derivatives not designated
as hedges and an unrealized loss of $6.7 million, which resulted in a net loss
of $9.8 million on its derivatives not designated as hedges in the quarter,
versus a net gain of $11.1 million during the prior year period.

For the remainder of 2014, the Company has a total of 3,800 Bbls/day swapped
at a blended price of $93.65 per Bbl, which includes 2,500 Bbls/day swapped at
a NYMEX crude oil price of $93.18 per Bbl and 1,300 Bbls/day swapped at a LLS
crude oil price of $94.55 per Bbl. For 2015, the Company now has a total of
3,500 Bbls/day swapped at an average LLS price of $96.11 per Bbl. The Company
will continue to add incremental oil hedges as production volumes increase in
the TMS.

With regard to natural gas, the Company has 30,000 MMBtu/day swapped at an
average NYMEX natural gas price of $4.76 per MMBtu for the remainder of
2014. 

LIQUIDITY

The Company exited the quarter with $0.5 million in cash, $51.8 million of
restricted cash and $48 million drawn on its senior credit facility.
Currently, the Company's senior credit facility has a borrowing base of $250
million. The Company expects to finance the remainder of its 2014 capital
expenditure budget with cash flow from operations and available capacity on
its senior credit facility.

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 15.0 gross (10.2
net) wells, of which 9.0 gross (5.8 net) were in the TMS, 5.0 gross (3.3 net)
were in the Eagle Ford Shale trend, and 1.0 gross (1.0 net) in the Angelina
River Trend / Shelby Trough area of the Haynesville Shale. A total of 7.0
gross (5.1 net) wells were added to production during the quarter, which
included 4.0 gross (3.1 net) wells in the TMS and 3.0 gross (2.0 net) wells in
the Eagle Ford Shale trend. As of June 30, 2014, the Company had 5.0 gross
(2.3 net) wells drilled and waiting on completion, which was comprised of 3.0
gross (1.0 net) wells in the TMS and 2.0 gross (1.3 net) wells in the Eagle
Ford Shale trend.

Tuscaloosa Marine Shale:

The Company's SLC, Inc. 81H-1 (67% WI) well in West Feliciana Parish,
Louisiana has achieved a peak 24-hour production rate to date of approximately
900 Boe/day, comprised of 860 Bbls of oil and 240 Mcf of natural gas (96% oil)
on a 12/64 inch choke from an approximate 7,000 foot lateral with 27 frac
stages. The well is the Company's deepest well drilled to date in the TMS
with an approximate true vertical depth of 14,000 feet.

The Company's previously announced Beech Grove 94H-1 (67% WI) well in East
Feliciana Parish, Louisiana, which had a reported initial production rate of
740 Boe/day, achieved a 30-day average production rate of approximately 600
Boe/day (90% oil). The Beech Grove continues to perform very well and has
thus far exhibited a flatter decline curve profile. The well is currently
producing approximately 550 Boe/day and is currently on the Company's 600 MBoe
type curve.

The Company participated in the non-operated Lewis 7-18H-1 (17% WI) well in
Amite County, Mississippi, which achieved a peak 24-hour production rate to
date of approximately 1,500 Boe/day, comprised of 1,400 Bbls of oil and 600
Mcf of natural gas on a 18/64 inch choke from an approximate 8,100 foot
lateral with 29 frac stages.

The Company retains a reversionary interest in the non-operated Mathis
29-32H-1 well, which achieved a peak 24-hour production rate to date of
approximately 1,300 Boe/day, comprised of 1,200 Bbls of oil and 600 Mcf of
natural gas on a 18/64 inch choke from an approximate 6,400 foot lateral with
17 frac stages. The Company owns a 6.5% reversionary interest in the well and
the right to participate in subsequent wells drilled in the unit.

In Amite County, Mississippi, the Company is currently drilling its Spears
31-6H-1 (77% WI) well, which is an offset to, and drilling off the same pad
as, the Company's C.H. Lewis 30-19H-1 (81% WI) well. In Wilkinson County,
Mississippi, the Company continues to conduct drilling operations on its
CMR/Foster Creek 31-22H-1 (90% WI) and its CMR/Foster Creek 24-13H-1 (97% WI)
wells, both of which are offsets to the Company's Crosby 12H-1 (50% WI)
well.

The Company has commenced completion operations on its Denkmann 33-28H-2 (75%
WI) wellin Amite County, Mississippi. The well was drilled with an
approximate 6,200 foot lateral and will be completed with 22 frac stages.
Upon completion of the Denkmann well, the same frac crew will move to the
Company's Bates 25-24H-1 (98% WI) well. Completion and frac operations on the
CMR/Foster Creek 24-13H-1 (97% WI) and CMR/Foster Creek 31-22H #1 (90% WI)
wells are expected to commence in late August to early September. The Company
plans to announce completion results from all four wells during the third
quarter.

The Company currently has in excess of 300,000 net acres in the TMS.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial
measures, including Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted
operating income (loss), Adjusted net loss applicable to common stock and Cash
operating margin. Management believes Adjusted EBITDAX, DCF, Adjusted
revenues, Adjusted operating income (loss), Adjusted net loss applicable to
common stock and Cash operating margin are good financial indicators of the
Company's ability to internally generate operating funds. None of DCF,
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 (loss) 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, 2013 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,
                             2014          2013        2014         2013
Volumes
 Natural gas (MMcf)          3,957         4,906       8,388        9,050
 Oil and condensate (MBbls)  381           292         722          600
 MMcfe - Total               6,245         6,658       12,721       12,651
 Mcfe per day                68,623        73,167      70,281       69,893
Total Revenues               $ 53,319     $ 48,485   $ 105,122    $ 95,569
Operating Expenses
 Lease operating expense     7,312         5,881       15,929       13,097
 Production and other taxes  1,983         2,742       4,424        5,502
 Transportation and          2,339         2,476       4,711        5,073
 processing
 Depreciation, depletion     30,076        34,513      59,314       69,487
 and amortization
 Exploration                 2,350         9,511       4,667        12,846
 General and administrative  9,454         7,645       18,395       17,032
 Gain on sale of assets      -             -           -            (43)
 Other                       3,357         (91)        3,357        (91)
Operating loss              (3,552)       (14,192)    (5,675)      (27,334)
Other income (expense)
 Interest expense            (11,751)      (13,027)    (23,629)     (26,400)
 Interest income and other   10            15          20           19
 Gain (loss) on derivatives  (9,813)       11,061      (18,314)     9,109
 not designated as hedges
                             (21,554)      (1,951)     (41,923)     (17,272)
Loss before income taxes     (25,106)      (16,143)    (47,598)     (44,606)
Income tax benefit          -             -           -            -
Net loss                   (25,106)      (16,143)    (47,598)     (44,606)
Preferred stock dividends    7,430         3,956       14,861       5,468
Net loss applicable to       $ (32,536)    $ (20,099)  $ (62,459)  $ (50,074)
common stock
 Unrealized (gain) loss on
 derivatives not designated  6,734         (10,978)    12,504       (8,874)
 as hedges
 Exploration - Seismic       -             634         -            1,047
 Lease expirations           1,142         7,461       2,373        8,899
 Dry hole cost               -             52          44           252
 Gain on sale of assets      -             -           -            (43)
 Other                       3,357         (91)        3,357        (91)
Adjusted net loss
applicable to common stock   $ (21,303)    $ (23,021)  $ (44,181)  $ (48,884)
(1)
 Discretionary cash flow
 (see non-GAAP               $ 18,384     $ 20,928   $  37,783   $ 37,249
 reconciliation) (2)
 Adjusted EBITDAX (see
 calculation and non-GAAP    $ 31,450     $ 31,524   $  60,501   $ 58,574
 reconciliation)( 3)
Weighted average common      44,308        36,701      44,290       36,692
shares outstanding - basic
Weighted average common
shares outstanding -         44,308        36,701      44,290       36,692
diluted (4)
Earnings per share
 Net loss applicable to      $   (0.73)  $         $          $  
 common stock - basic                      (0.55)      (1.41)      (1.36)
 Net loss applicable to      $   (0.73)  $         $          $  
 common stock - diluted                    (0.55)      (1.41)      (1.36)
Adjusted earnings per share
 Adjusted net loss                         $         $          $  
 applicable to common stock  $   (0.48)  (0.63)      (1.00)      (1.33)
 - basic (1)
 Adjusted net loss                         $         $          $  
 applicable to common stock  $   (0.48)  (0.63)      (1.00)      (1.33)
 - fully diluted (1)



(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 10.7 million and 10.5 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, 2014,
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,
                               2014         2013         2014      2013
Average sales price per unit:
 Oil (per Bbl)
  Including realized
 gain/(loss) on oil            $  91.23   $ 101.91    $ 91.28  $ 104.79
 derivatives
  Excluding realized
 gain/(loss) on oil            $ 100.48    $ 101.62    $ 99.44  $ 104.40
 derivatives
 Natural gas (per Mcf)
  Including realized
 gain/(loss) on natural gas    $   3.89  $   3.75  $  3.97  $   3.59
 derivatives
  Excluding realized
 gain/(loss) on natural gas    $   3.78  $   3.75  $  3.97  $   3.59
 derivatives
 Natural gas and oil (per
 Mcfe)
  Including realized
 gain/(loss) on oil and        $   8.04  $   7.23  $  7.80  $   7.54
 natural gas derivatives
  Excluding realized
 gain/(loss) on oil and        $   8.53  $   7.22  $  8.26  $   7.52
 natural gas derivatives
Costs Per Mcfe
 Lease operating expense       $   1.17  $   0.88  $  1.25  $   1.04
 Production and other taxes    $   0.32  $   0.41  $  0.35  $   0.43
 Transportation and            $   0.37  $   0.37  $  0.37  $   0.40
 processing
 Depreciation, depletion and   $   4.82  $   5.18  $  4.66  $   5.49
 amortization
 Exploration                   $   0.38  $   1.43  $  0.37  $   1.02
 General and administrative    $   1.51  $   1.15  $  1.45  $   1.35
 Gain on sale of assets/other  $   0.54  $  (0.01)  $  0.26  $  (0.01)
                               $   9.11  $   9.41  $  8.71  $   9.71
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,
                          2014          2013          2014         2013
Net cash provided by
operating activities      $  63,291    $  29,588    $  69,846  $  35,860
(GAAP)
Net changes in working    (44,907)      (8,660)       (32,063)     1,389
capital
Discretionary cash flow   $  18,384    $  20,928    $  37,783  $  37,249
Weighted average common
shares outstanding -      44,308        36,701        44,290       36,692
basic
Weighted average common
shares outstanding -      44,308        36,701        44,290       36,692
diluted (4)
Supplemental Balance Sheet Data
                          As of
                          June 30,      December 31,
                          2014          2013
 Cash and cash            $    454  $  49,220
 equivalents
 Long-term debt           486,378       435,866
Reconciliation of Net income (loss) to Adjusted
EBITDAX
                          Three Months Ended          Six Months Ended
                          June 30,                    June 30,
                          2014          2013          2014         2013
 Net loss (GAAP)          $ (25,106)    $ (16,143)   $ (47,598)  $ (44,606)
 Exploration expense      2,350         9,511         4,667        12,846
 Depreciation, depletion  30,076        34,513        59,314       69,487
 and amortization
 Stock compensation       2,298         1,700         4,648        3,474
 expense
 Interest expense        11,751        13,027        23,629       26,400
 Unrealized (gain) loss
 on derivatives not       6,734         (10,978)      12,504       (8,874)
 designated as hedges
 Other excluded items *   3,347         (106)         3,337        (153)
  Adjusted EBITDAX   $  31,450    $  31,524    $  60,501  $  58,574
 * 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,
                          2014          2013          2014         2013
 Interest expense - cash  $   9,084   $   9,599  $  18,330  $  19,558
 Interest expense -       2,667         3,428         5,299        6,842
 noncash
 Total Interest           11,751        13,027        23,629       26,400
 Unrealized (gain) loss
 on derivatives not       6,734         (10,978)      12,504       (8,874)
 designated as hedges
 Realized (gain) loss on
 derivatives not          3,079         (83)          5,810        (235)
 designated as hedges
 Total (gain) loss on
 derivatives not          9,813         (11,061)      18,314       (9,109)
 designated as hedges
 General and
 Administrative expense - 7,156         5,945         13,747       13,558
 cash
 General and
 Administrative expense - 2,298         1,700         4,648        3,474
 noncash
 Total General and        9,454         7,645         18,395       17,032
 Administrative expense



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,
                            2014        2013          2014          2013
Total Revenues (GAAP)       $ 53,319   $  48,485   $ 105,122     $ 95,569
Realized gain (loss) on
derivatives not designated  (3,079)     83            (5,810)       235
as hedges
Adjusted Revenues           $ 50,240   $  48,568   $  99,312    $ 95,804
Reconciliation of Adjusted Operating Income and Operating Income (unaudited)
                            Three Months Ended        Six Months Ended
                            June 30,                  June 30,
                            2014        2013          2014          2013
Operating loss (GAAP)       $ (3,552)  $  (14,192)  $  (5,675)  $ (27,334)
Realized gain (loss) on
derivatives not designated  (3,079)     83            (5,810)       235
as hedges
Adjusted Operating loss    $ (6,631)  $  (14,109)  $ (11,485)   $ (27,099)
Calculation of Cash operating margin (unaudited)
                            Three Months Ended        Six Months Ended
                            June 30,                  June 30,
                            2014        2013          2014          2013
Adjusted EBITDAX (see
calculation and non-GAAP    $ 31,450    $  31,524    $  60,501    $ 58,574
reconciliation) (3)
Adjusted Revenues (see      $ 50,240    $  48,568    $  99,312    $ 95,804
non-GAAP reconciliation)
Cash operating margin       63%         65%           61%           61%



SOURCE Goodrich Petroleum Corporation

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