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. 19, 2014

HOUSTON, Feb. 19, 2014 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE:
GDP) (the "Company") today announced financial and operating results for the
year and fourth quarter ended December 31, 2013.

  oProved Reserves grow by 36% to 452.2 Bcfe, with undiscounted future cash
    flow of $1.1 billion and PV-10 of $472.3 million. Finding and development
    cost, as adjusted for 2013 drilling and completion capital expenditures,
    was $21.07 per barrel of oil equivalent ("BOE") and proved developed
    finding and development cost, as adjusted for 2013 drilling and completion
    capital expenditures, was $32.89 per BOE.
  oAdjusted EBITDAX was $32.3 million for the quarter and $125.5 million for
    the year. Discretionary cash flow was $22.0 million for the quarter and
    $84.1 million for the year.
  oProduction averaged 80,800 Mcfe per day for the quarter, with 29.4% of
    volumes coming from oil, which generated 67.4% of revenue.
  oTuscaloosa Marine Shale ("TMS"):

       oThe Company's Huff 18-7H-1 well in Amite County, Mississippi reached
         peak rate from a shortened lateral of530 BOE per day, comprised
         of501 barrels of oil and 174 Mcf of gas on a 13/64 inch choke.
       oResults from the Company's Weyerhaeuser 51H-1 well are delayed due to
         drilling out the frac plugs (see below).

(PV-10, Adjusted EBITDAX and Discretionary Cash Flow are non-GAAP financial
measures; please refer to the "Other Information" section and the accompanying
tables at the end of this press release that reconcile PV-10, Adjusted EBITDAX
and Discretionary Cash Flow to their most directly comparable GAAP financial
measure.)

FINANCIAL RESULTS

REVENUES

Revenues totaled $50.6 million in the quarter versus $48.2 million in the
prior year period. Average realized price per unit was $6.81 per Mcfe in the
quarter versus $7.24 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 $65.4 million in the
prior year period, and average realized price per unit was $6.76 per Mcfe
versus $9.83 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 7.4 billion cubic feet equivalent ("Bcfe") in the quarter,
or an average of 80,800 Mcfe per day, versus 6.6 Bcfe, or an average of 71,800
Mcfe per day in the prior year period. Oil production totaled 364,000 barrels
of oil in the quarter, or an average of approximately 3,950 barrels per day,
versus 329,000 barrels of oil, or an average of approximately 3,580 barrels
per day, in the prior year period. Production for the quarter was negatively
affected by delays in the TMS trend. Production for the year was 27.8 Bcfe,
or an average of 76,100 Mcfe per day, versus 31.4 Bcfe, or an average of
85,800 Mcfe per day in the prior year period. Crude oil production for the
year totaled 1.3 million barrels of oil, a 22% increase over 2012, and 19.8
Bcf of natural gas, or an average of 54,100 Mcf per day.

The Company anticipates producing between 3,800 – 4,200 Bbls/d of oil and
48,000 – 50,000 Mcf/d of natural gas during the first quarter of 2014. The
Company anticipates capital expenditures between $45 – $60 million in the
first quarter with approximately 75% allocated towards drilling and completing
wells in the TMS. 

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative
expenses and exploration ("Adjusted EBITDAX") was $32.3 million in the
quarter, compared to $50.5 million in the prior year period.Adjusted EBITDAX
for the year was $125.5 million versus $184.0 million in the prior year
period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, was $22.0 million in the
quarter, compared to $39.9 million in the prior year period. DCF was $84.1
million for the year, versus $141.5 million in the prior year period. Net
cash provided by operating activities for the year was $71.4 million, compared
to $173.8 million for the prior year period.

Adjusted EBITDAX and DCF were both impacted by a $0.4 million realized loss on
derivatives not designated as hedges during the quarter compared to a $17.1
million realized gain on derivatives not designated as hedges during the prior
year period. For the year, Adjusted EBITDAX and DCF were both impacted by a
$3.8 million realized loss on derivatives not designated as hedges compared to
a $73.2 million realized gain on derivatives not designated as hedges 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 a net loss applicable to common stock of $30.9 million
in the quarter, or ($0.73) per basic share, versus a net loss applicable to
common stock of $77.2 million, or ($2.12) per basic share in the prior year
period.Adjusted net loss applicable to common stock was $23.9 million for the
quarter, or ($0.57) per basic share, which excludes the impact of unrealized
losses on derivatives not designated as hedges of $0.7 million, loss on
extinguishment of debt of $2.3 million and dry hole costs on the Company's
initial TMS well drilled in 2012 due to casing failure of $4.1 million.The
Company announced a net loss applicable to common stock of $113.8 million for
the year, or ($2.99) per basic share, versus a net loss applicable to common
stock of $90.2 million, or ($2.48) per basic share in the prior year
period.Adjusted net loss applicable to common stock was $105.6 million for
the year, or ($2.77) per basic share, which excludes the impact of unrealized
gains on derivatives not designated as hedges of $3.1 million, loss on
extinguishment of debt of $7.1 million and dry hole costs of $4.4 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 $7.1 million in the quarter, or $0.96 per
Mcfe, versus $4.7 million, or $0.71 per Mcfe, in the prior year period, which
included $1.6 million, or $0.22 per Mcfe, for workovers performed in the
quarter, versus $0.9 million, or $0.13 per Mcfe, in the prior year period.
For the year, LOE totaled $27.3 million, or $0.98 per Mcfe, versus $25.9
million, or $0.83 per Mcfe in the prior year period, which included $6.0
million, or $0.22 per Mcfe, for workovers, versus $4.3 million, or $0.13 per
Mcfe, in the prior year period. The majority of the Company's workover
expense pertained to wells in the Eagle Ford Shale trend. 

Production and other taxes were $1.8 million in the quarter, or $0.25 per
Mcfe, versus $2.4 million, or $0.36 per Mcfe, in the prior year period. For
the year, production and other taxes totaled $9.8 million, or $0.35 per Mcfe,
versus $8.1 million, or $0.26 per Mcfe, in the prior year period, which was
primarily driven by increasing oil volumes in the Eagle Ford Shale trend and
the absence of production tax credits on natural gas wells in Louisiana and
Texas. 

Transportation and processing expense was $2.7 million in the quarter, or
$0.36 per Mcfe, versus $2.8 million, or $0.43 per Mcfe, in the prior year
period. For the year, transportation and processing expense totaled $10.5
million, or $0.38 per Mcfe, versus $13.9 million, or $0.44 per Mcfe, in the
prior year period. 

Depreciation, depletion and amortization ("DD&A") expense was $32.6 million in
the quarter, or $4.38 per Mcfe, versus $37.1 million, or $5.62 per Mcfe, in
the prior year period. The decline in quarterly DD&A expense per unit of
production was driven by higher mid-year 2013 reserves and lower capital
expenditures per well in the Eagle Ford Shale trend. For the year, DD&A
expense totaled $135.4 million, or $4.87 per Mcfe, versus $141.2 million, or
$4.50 per Mcfe, for the prior year period, which was driven by more production
coming from the oil-focused Eagle Ford Shale trend compared to 2012.

Exploration expense was $5.8 million in the quarter, or $0.78 per Mcfe, versus
$16.4 million, or $2.48 per Mcfe, in the prior year period. For the year,
exploration expense totaled $22.8 million, or $0.82 per Mcfe, versus $23.1
million, or $0.74 per Mcfe, in the prior year period. Approximately $4.1
million, or 71% of the exploration expense for the quarter, was associated
with the remaining dry hole expense related to the mechanical failure of the
Company's initial well drilled in 2012, the Denkmann 33-28 H-1, in the TMS
trend.

General and Administrative ("G&A") expense was $8.7 million in the quarter, or
$1.18 per Mcfe, versus $7.2 million, or $1.09 per Mcfe, in the prior year
period. During the quarter, the Company incurred $0.6 million of
non-recurring G&A expense in connection with the closing of its Shreveport,
Louisiana land office and the associated employee severance and relocation
expenses. G&A expense related to non-cash, stock based compensation for its
employees totaled $2.5 million in the quarter, or $0.33 per Mcfe, versus $2.2
million, or $0.33 per Mcfe, in the prior year period. For the year, G&A
expense totaled $34.1 million, or $1.23 per Mcfe, versus $28.9 million, or
$0.92 per Mcfe, in the prior year period. For the year, G&A expense related
to non-cash, stock based compensation totaled $7.7 million, or $0.28 per Mcfe,
versus $6.9 million, or $0.22 per Mcfe, in the prior year period. 

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss
of $8.1 million in the quarter, versus an operating loss of $67.1 million in
the prior year period, which was negatively impacted by $45.2 million of
non-recurring, non-cash impairment expenses in the prior year period. For the
year, operating income totaled a loss of $36.3 million, versus an operating
loss of $63.7 million in 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 totaled $12.1 million in the quarter, or $1.63 per Mcfe,
versus $13.1 million, or $1.98 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 $0.37 per
Mcfe, versus $3.4 million, or $0.52 per Mcfe, in the prior year period. For
the year, interest expense totaled $51.2 million, or $1.84 per Mcfe, versus
$52.4 million, or $1.67 per Mcfe, in the prior year period. For the year,
non-cash interest expense, representing 25% of total interest expense, totaled
$12.7 million, or $0.46 per Mcfe, versus $12.8 million, or $0.41 per Mcfe, in
the prior year period.

CAPITAL EXPENDITURES

Capital expenditures totaled $50.8 million in the quarter, of which $38.3
million was spent on drilling and completion costs, $9.0 million on leasehold
acquisition and $3.5 million on facilities, capital workovers and other
expenditures. For the year, capital expenditures totaled $255.0 million, of
which $212.4 million was spent on drilling and completion costs, $38.4 million
on leasehold and property acquisitions and $4.2 on facilities, capital
workovers and other expenditures. Drilling and completion expenditures of
$212.4 million were comprised of $112.7 million, or 53%, for wells that had
new reserve additions in 2013, $45.6 million, or 21%, for the conversion of 10
proved undeveloped reserve locations to proved developed reserves and $54.1
million, or 26%, for wells in progress at year-end and 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, 2013
increased by 36% to 452.2 Bcfe, versus 333.1 Bcfe in the prior year period.
The Company incurred positive reserve revisions of 90.9 Bcfe on mostly natural
gas reserves in Northwest Louisiana and East Texas areas, that became economic
under 2013 SEC pricing. The Company spent $192.4 million of adjusted net
drilling and completion capital, adding 54.8 Bcfe of proved reserves,
resulting in an adjusted organic finding and development cost of $3.51 per
Mcfe ($21.07 per BOE). Year-end proved reserves were 73% natural gas, 27% oil
and liquids and 39% developed. The future net cash flows of the reserves was
$1.1 billion and the PV-10 was $472.3 million, using SEC pricing of $3.67 per
MMBtu for natural gas, $96.94 per barrel of oil and $31.44 per barrel of
natural gas liquids.

(Year-end PV-10 of proved reserves is a non-GAAP financial measure; please
refer to the "Other Information" section for additional disclosure and
information.)

The following table reflects the changes in the proved reserve estimates since
year-end 2012:

                                                                     Proved
                                                            Proved   Developed
                                                            Reserves Reserves
                                                            (Bcfe)   (Bcfe)
Reserves at December 31, 2012                               333.1    158.4
 Production                                            (29.4)   (29.4)
 Divestitures                                          (0.1)    (0.1)
 Acquisitions                                          2.9      2.9
 Reserve Additions^(1)                                 54.8     35.1
 Revisions – Price and Technical                       90.9     10.9
Reserves at December 31, 2013                               452.2    177.8
2013 Reserve Replacement Ratio (%)^(2)                      186%     119%
2013 Net Cash Drilling and Completion Capital Expenditures  $192.4 MM
(non-GAAP)^(3)
2013 Finding and Development Costs ($/Mcfe)^(4)             $3.51 ($21.07/BOE)
2013 Proved Developed Finding & Development Costs           $5.48 ($32.89/BOE)
($/Mcfe)^(5)



 (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 2013 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 2013 by Proved Developed Reserve Additions (before price and
     technical revisions).



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

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company had a net loss of $1.1 million on its derivatives not designated
as hedges in the quarter, versus a net gain of $4.6 million during the prior
year period. For the year, the Company had a net loss of $0.7 million on its
derivatives not designated as hedges, versus a net gain of $31.9 million
during the prior year period.

At year-end 2013, the Company had 1,500 Bbls/d committed under an extendable
contract for 2014 at $99.77 per Bbl that was not exercised at the
counterparty's election. For calendar year 2014, the Company has a total of
3,800 Bbls/d firmly swapped at a blended price of $93.65 per Bbl, which
includes 2,500 Bbls/d swapped at a NYMEX crude oil price of $93.18 per Bbl and
1,300 Bbls/d swapped at a LLS crude oil price of $94.55 per Bbl.

With regard to natural gas, at year-end 2013 the Company had 20,000 MMBtu/d
committed under an extendable contract for 2014 at $5.35 per MMBtu that was
not extended at the counterparty's election. For 2014, the Company has 30,000
MMBtu/d firmly swapped at a NYMEX natural gas price of $4.76 per MMBtu. 

LIQUIDITY

The Company exited the year with $49.2 million in cash, $51.8 million of
restricted cash and no outstanding borrowings under its senior credit
facility, providing approximately $320 million of available liquidity as the
Company entered 2014. The Company's borrowing base is currently $270 million,
with a new borrowing base redetermination expected in the second quarter of
2014. The Company expects to finance its 2014 capital expenditure budget with
cash on hand, cash flow from operations and available capacity on its senior
credit facility.

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 4 gross (3 net)
wells, of which 1 gross (0.67 net) were in the Eagle Ford and 3 gross (2.6
net) were in the TMS trend. A total of 7 gross (4.7 net) wells were added to
production during the quarter, of which 4 gross (2.7 net) were in the Eagle
Ford Shale trend, 1 gross (0.9 net) was in the TMS trend, and 2 gross (1 net)
were previously cased wells in our non-operated joint-venture in the
Haynesville Shale trend. For the year, the Company conducted drilling
operations on 25 gross (16 net) wells and added 43 gross (24 net) wells to
production. The wells added to production during the year consisted of 23
gross (15 net) in the Eagle Ford Shale trend, 7 gross (3 net) in the TMS
trend, 1 gross (1 net) previously cased well in the ART/Shelby Trough and 12
gross (5 net) previously cased wells in our non-operated joint-venture in the
Haynesville Shale trend.

The Company has set a $375 million capital expenditure budget for 2014. In
the TMS, the Company has preliminary plans, subject to continued success, to
spend $300 million to drill 32 gross (23 net) wells, which is predicated on an
increasing rig count throughout 2014, resulting in five operated rigs running
by the second half of 2014. In the Eagle Ford Shale trend, the Company plans
to spend $45 million to drill 9 gross (6 net) wells, and in the Haynesville
Shale, plans to drill one gross and net well on its ART / Shelby Trough
acreage by mid-2014. The Company plans to spend approximately $15 million on
leasehold, acquisitions and infrastructure in 2014. 

Tuscaloosa Marine Shale:

The Company has completed its Huff 18-7H-1 (97% WI) well in Amite County,
Mississippi. Previously announced workover operations to clean out an
obstruction at approximately 500 feet in the lateral were unsuccessful.
However, the well is currently producing and had a peak 24-hour production
rate of530 BOE per day, comprised of501 barrels of oil and174 Mcf of gas on
a 13/64 choke. The Huff well landed in the Company's upper target in the
TMS.

The Company drilled its Weyerhaeuser 51H-1 (66.7% WI) well approximately three
miles south of previously drilled Weyerhaeuser wells in St. Helena Parish,
Louisiana. The well was successfully drilled in the Company's lower target
with a lateral length of approximately 6,200 feet and was fracture stimulated
with 23 stages. The well initially flowed back through permanent frac plugs
at high frac fluid rates on similar choke sizes to other wells in the field,
but over time showed signs of plugging off on a portion of the lateral. As a
result, the Company is currently drilling out the frac plugs prior to
returning the well to production.

The Company is currently fracking its CMR 8-5 H-1 (100% WI) in Amite County,
Mississippi, which is a 5,300 foot lateral with 20 planned frac stages. The
CMR 8-5 H-1 well landed in the Company's lower target in the TMS.

The Company is currently drilling its Blades 33H-1 (66.7% WI) well in
Tangipahoa Parish, Louisiana and its CH Lewis 30-19H-1 (81.4% WI) well in
Amite County, Mississippi. A third operated rig is expected in the field in
early March.

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, drilling and completion capital
expenditures, Adjusted revenues, Adjusted operating income, Adjusted net loss
applicable to common stock, Cash operating margin and year-end pretax present
worth of proved reserves discounted at 10%, or "PV-10". Management believes
Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income, Adjusted
net loss applicable to common stock and Cash operating margin are good
financial indicators of the Company's ability to internally generate operating
funds, while drilling and completion capital expenditures are a useful measure
of the Company's annual drilling expenditures. Neither DCF, nor Adjusted
EBITDAX, should be considered an alternative to net cash provided by operating
activities, as defined by 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 $4.1 million at December 31, 2013 to arrive
at a SMOG of $468.1 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 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)                      $250,654
Less: Cash Spent in 2013 for Expenditures Booked in 2012          (18,609)
Add: Proceeds from Sale of Assets                                 449
Net Capital Expenditures Booked in 2013 (non-GAAP)                $232,494
Less:  Leasehold Acquisitions                                    (14,874)
 Facilities & Infrastructure                            (966)
 Furniture, Fixtures & Equipment                        (748)
 Acquisition                                            (23,521)
Net Cash Drilling and Completions Capital Expenditures (non-GAAP) $192,385



GOODRICH PETROLEUM CORPORATION
SELECTED INCOME AND PRODUCTION DATA
(In Thousands, Except Per Share Amounts)
                             Three Months Ended       Year Ended
                             December 31,             December 31,
                             2013        2012         2013         2012
Volumes
 Natural gas (MMcf)          5,254       4,630        19,760       24,844
 Oil and condensate (MBbls)  364         329          1,338        1,095
 MMcfe - Total               7,437       6,603        27,785       31,415
 Mcfe per day                80,832      71,774       76,124       85,832
Total Revenues               $ 50,565   $ 48,231    $ 203,295   $ 180,845
Operating Expenses
 Lease operating expense     7,124       4,671        27,293       25,938
 Production and other taxes  1,848       2,363        9,812        8,115
 Transportation and          2,657       2,840        10,498       13,900
 processing
 Depreciation, depletion     32,550      37,084       135,357      141,222
 and amortization
 Exploration                 5,813       16,367       22,774       23,122
 Impairment                 -           45,156       -            47,818
 General and administrative  8,743       7,177        34,069       28,930
 Gain on sale of assets      (48)        (377)        (107)        (44,606)
 Other                       -           91           (91)         91
Operating loss              (8,122)     (67,141)     (36,310)     (63,685)
Other income (expense)
 Interest expense            (12,108)    (13,087)     (51,187)     (52,403)
 Interest income and other   83          1            101          4
 Gain (loss) on derivatives  (1,052)     4,551        (702)        31,882
 not designated as hedges
 Loss on extinguishment of   (2,296)     -            (7,088)      -
 debt
                             (15,373)    (8,535)      (58,876)     (20,517)
Loss before income taxes     (23,495)    (75,676)     (95,186)     (84,202)
Income tax benefit          -           -            -            -
Net loss                     (23,495)    (75,676)     (95,186)     (84,202)
Preferred stock dividends    7,431       1,512        18,604       6,047
Net loss applicable to       $ (30,926)  $ (77,188)   $ (113,790)  $ (90,249)
common stock
 Unrealized (gain) loss on
 derivatives not designated  678         12,582       (3,084)      41,278
 as hedges
 Other                      -           91           (91)         91
 Gain on sale of assets      (48)        (377)        (107)        (44,606)
 Loss on extinguishment of   2,296       -            7,088        -
 debt
 Dry hole costs              4,069       12,848       4,390        12,848
 Impairment                 -           45,156       -            47,818
Adjusted net loss
applicable to common stock   $ (23,931)  $  (6,888)  $ (105,594)  $ (32,820)
(1)
 Discretionary cash flow                              $  
 (see non-GAAP               $ 22,049   $ 39,858    84,122       $ 141,485
 reconciliation) (2)
 Adjusted EBITDAX (see
 calculation and non-GAAP    $ 32,288   $ 50,505    $ 125,517   $ 184,025
 reconciliation)(3)
Weighted average common      42,229      36,465       38,098       36,390
shares outstanding - basic
Weighted average common
shares outstanding -         42,229      36,465       38,098       36,390
diluted (4)
Earnings per share
 Net loss applicable to      $         $          $         $  
 common stock - basic        (0.73)      (2.12)       (2.99)      (2.48)
 Net loss applicable to      $         $          $         $  
 common stock - diluted      (0.73)      (2.12)       (2.99)      (2.48)
Adjusted earnings per share
 Adjusted net loss           $         $          $         $  
 applicable to common stock  (0.57)      (0.19)       (2.77)      (0.90)
 - basic (1)
 Adjusted net loss           $         $          $         $  
 applicable to common stock  (0.57)      (0.19)       (2.77)      (0.90)
 - fully diluted (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
(1)      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.
         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
(2)      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.
         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
(3)      gains (losses) from derivatives but exclude unrealized gains (losses)
         from derivatives. Other excluded items include Interest income and
         other, Gain on sale of assets, Loss on extinguishment of debt and
         Other expense.
         Fully diluted shares excludes approximately 10.7 million and 10.5
         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, 2013, respectively. We report our
(4)      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,
                             2013          2012         2013       2012
Average sales price per
unit:
 Oil (per Bbl)
  Including realized
 gain/ loss on oil          $ 91.17       $ 110.12     $  98.70  $ 106.98
 derivatives
  Excluding realized
 gain / loss on oil          $ 93.66       $  98.63    $ 101.96   $  99.91
 derivatives
 Natural gas (per Mcf)
  Including realized                                $  
 gain / loss on natural gas  $  3.25      $   6.20  3.38      $   5.50
 derivatives
  Excluding realized                                $  
 gain / loss on natural gas  $  3.15      $   3.31  3.35      $   2.86
 derivatives
 Natural gas and oil (per
 Mcfe)
  Including realized                                $  
 gain / loss on oil and      $  6.76      $   9.83  7.15      $   8.08
 natural gas derivatives
  Excluding realized                                $  
 gain / loss on oil and      $  6.81      $   7.24  7.29      $   5.75
 natural gas derivatives
Costs Per Mcfe
 Lease operating expense     $  0.96     $   0.71  $        $   0.83
                                                        0.98
 Production and other taxes  $  0.25     $   0.36  $        $   0.26
                                                        0.35
 Transportation and          $  0.36     $   0.43  $        $   0.44
 processing                                             0.38
 Depreciation, depletion     $  4.38     $   5.62  $        $   4.50
 and amortization                                       4.87
 Exploration                 $  0.78     $   2.48  $        $   0.74
                                                        0.82
 Impairment                 $     -  $   6.84  $      $   1.52
                                                         -
 General and administrative  $  1.18     $   1.09  $        $   0.92
                                                        1.23
 Gain on sale of assets      $ (0.01)     $  (0.06)  $      $  (1.42)
                                                         -
 Other                       $     -  $   0.01  $      $     
                                                         -       -
                             $  7.89     $  17.47   $        $   7.78
                                                        8.62
Note: Amounts on a per Mcfe basis may not total due to rounding.



GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
Reconciliation of Discretionary Cash Flow and Net Cash Provided by Operating
Activities (unaudited)
                         Three Months Ended           Year Ended
                         December 31,                 December 31,
                         2013          2012           2013         2012
Net cash provided by
operating activities     $   30,564  $   76,216   $  71,405   $ 173,789
(GAAP)
Net changes in working   (8,515)       (36,358)       12,717       (32,304)
capital
Discretionary cash flow  $   22,049  $   39,858   $  84,122   $ 141,485
Weighted average common
shares outstanding -     42,229        36,465         38,098       36,390
basic
Weighted average common
shares outstanding -     42,229        36,465         38,098       36,390
diluted (4)
Supplemental Balance Sheet Data
                         As of
                         December 31,  December 31,
                         2013          2012
 Cash and cash           $   49,220  $   
 equivalents                           1,188
 Long-term debt          435,866       568,671
Reconciliation of Net income (loss) to Adjusted
EBITDAX
                         Three Months Ended           Year Ended
                         December 31,                 December 31,
                         2013          2012           2013         2012
 Net loss (GAAP)         $  (23,495)  $  (75,676)  $ (95,186)  $ (84,202)
 Exploration expense     5,813         16,367         22,774       23,122
 Depreciation, depletion 32,550        37,084         135,357      141,222
 and amortization
 Impairment              -             45,156         -            47,818
 Loss on extinguishment  2,296         -              7,088        -
 of debt
 Stock compensation      2,469         2,192          7,680        6,903
 expense
 Interest expense       12,108        13,087         51,187       52,403
 Unrealized (gain) loss
 on derivatives not      678           12,582         (3,084)      41,278
 designated as hedges
 Other excluded items *  (131)         (287)          (299)        (44,519)
  Adjusted EBITDAX  $   32,288  $   50,505   $ 125,517    $ 184,025
 * Other excluded items include Interest income and other, Gain on sale of
 assets, Income taxes and Other expense.
Other Information
                         Three Months Ended           Year Ended
                         December 31,                 December 31,
                         2013          2012           2013         2012
 Interest expense - cash $          $           $  38,441   $  39,583
                         9,367         9,674
 Interest expense -      2,741         3,413          12,746       12,820
 noncash
 Total Interest          12,108        13,087         51,187       52,403
 Unrealized (gain) loss
 on derivatives not      678           12,582         (3,084)      41,278
 designated as hedges
 Realized (gain) loss on
 derivatives not         374           (17,133)       3,786        (73,160)
 designated as hedges
 Total (gain) loss on
 derivatives not         1,052         (4,551)        702          (31,882)
 designated as hedges
 General and
 Administrative expense  6,274         4,985          26,389       22,027
 - cash
 General and
 Administrative expense  2,469         2,192          7,680        6,903
 - noncash
 Total General and       8,743         7,177          34,069       28,930
 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,
                           2013        2012          2013         2012
Total Revenues (GAAP)      $ 50,565    $ 48,231     $ 203,295    $ 180,845
Realized gain (loss) on
derivatives not designated (374)       17,133        (3,786)      73,160
as hedges
Adjusted Revenues          $ 50,191    $   65,364  $ 199,509    $ 254,005
Reconciliation of Adjusted Operating Income (Loss) and Operating Loss
(unaudited)
                           Three Months Ended        Year Ended
                           December 31,              December 31,
                           2013        2012          2013         2012
Operating loss (GAAP)      $ (8,122)  $ (67,141)    $ (36,310)  $ (63,685)
Realized gain (loss) on
derivatives not designated (374)       17,133        (3,786)      73,160
as hedges
Adjusted Operating Income  $ (8,496)  $            $ (40,096)  $   9,475
(Loss)                                 (50,008)
Calculation of Cash operating margin (unaudited)
                           Three Months Ended        Year Ended
                           December 31,              December 31,
                           2013        2012          2013         2012
Adjusted EBITDAX (see
calculation and non-GAAP   $ 32,288    $ 50,505     $ 125,517    $ 184,025
reconciliation) (3)
Adjusted Revenues (see     $ 50,191    $   65,364  $ 199,509    $ 254,005
non-GAAP reconciliation)
Cash operating margin      64%         77%           63%          72%



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, +1-713-780-9494
 
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