Goodrich Petroleum Announces First Quarter 2013 Financial Results And Operational Update

    Goodrich Petroleum Announces First Quarter 2013 Financial Results And
                              Operational Update

PR Newswire

HOUSTON, May 6, 2013

HOUSTON, May 6, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE:
GDP) today announced financial and operating results for the first quarter
ended March 31, 2013.

  oProduction for the quarter averaged 66.6 million cubic feet equivalent per
    day, comprised of an average of 3,423 barrels of oil and 46.0 million
    cubic feet per day. Oil and gas production for the quarter was negatively
    impacted by approximately 300 barrels of oil and 4,000 Mcf per day due to
    shut-in wells while fracing pad-drilled and/or offset wells in both the
    Eagle Ford and Haynesville Shale areas. Despite the shut-ins for the
    quarter, the Company reaffirms full year guidance of annual oil production
    volume growth of 40-60% and natural gas production volume growth of 10%
    from fourth quarter of 2012 to fourth quarter of 2013, as completions will
    accelerate at a faster pace than in the first quarter.
  oOil production comprised 31% of total production and 70% of revenues for
    the first quarter, with average realized oil price of $107.02 due to
    premium pricing agreements. Average realized price per Mcfe of production
    was $7.88 per Mcfe, including realized gain on hedges.
  oTuscaloosa Marine Shale development continuing, with four wells in
    completion phase and second operated well (Smith 5-29H-1) drilling.
    Improving drilling cycle times experienced on recent wells, are leading to
    improved drilling costs. The Goodrich Petroleum - Crosby 12H-1 well
    continuing to outperform the Company's 800,000 BOE type curve, with
    approximately 75,000 BOE (91% oil) produced in three months, with current
    production of approximately 700 BOE per day. The Company has participated
    with a non-operated working interest in the Ash 31H-2 well, which is a
    5,300 foot lateral with 18 frac stages. The well has been flowing back for
    approximately two weeks and is still cleaning up due to the large frac job
    of one million pounds of proppant and 29,000 barrels of fluid per stage.
    Current 24-hour peak rate is approximately 730 BOE per day (92% oil), with
    4% of the frac fluid recovered.
  oLiquidity enhanced with increased borrowing base to $225 million and $110
    million in gross proceeds from issuance of non-convertible perpetual
    preferred stock in April 2013. Proforma liquidity of approximately $190
    million at quarter-end.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative
expenses and exploration ("Adjusted EBITDAX") was $27.1 million in the
quarter, compared to $40.4 million in the prior year period and $50.5 million
in the prior quarter. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, was $16.3 million in the
quarter, compared to $29.9 million in the prior year period and $39.9 million
in the prior quarter. Net cash provided by operating activities was $6.3
million, compared to $30.5 million for the prior year period.

For the quarter both Adjusted EBITDAX and DCF were impacted by additional
general and administrative expense of $1.5 million primarily for 2012 employee
bonuses paid in 2013 and increased payroll taxes, approximately $1.6 million
for workovers performed in the quarter, primarily in the Eagle Ford trend and
$0.4 million for seismic expense.

(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 $30.0 million
for the quarter, or ($0.82) per basic share, versus a net loss applicable to
common stock of $19.2 million, or ($0.53) per basic share in the prior year
period. Adjusted net loss applicable to common stock, taking into effect the
unrealized loss on derivatives not designated as hedges of $2.1 million and
non-recurring exploration expense of $0.2 million, was $27.7 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.)

PRODUCTION

Production for the quarter was 6.0 billion cubic feet equivalent ("Bcfe"), or
an average of 66,600 Mcfe per day, versus 8.8 Bcfe, or an average of 96,300
Mcfe per day in the prior year period. Oil production for the quarter totaled
308,000 barrels of oil, or an average of 3,423 barrels per day, versus
217,000 barrels of oil, or 2,400 barrels per day, in the prior year period.
Natural gas production for the quarter totaled 4.1 Bcf, or an average of
46,000 Mcf per day. Oil and gas production for the quarter was negatively
impacted by approximately 300 barrels of oil and 4,000 Mcf per day due to
completion delays and the necessity to shut in wells while fracing pad-drilled
and/or offset wells in both the Eagle Ford and Haynesville Shale areas.

REVENUES

Revenues for the quarter were $47.1 million versus $45.3 million in the prior
year period. Revenues, including realized gain on derivatives not designated
as hedges of $0.1 million for the quarter, would have been $47.2 million.
Average realized price per unit for the quarter, was $7.85 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
$7.88 per Mcfe, versus $6.99 per Mcfe in the prior year period.

(See accompanying tables at the end of this press release that reconciles
Adjusted Revenues, a non-GAAP measure, to its most directly comparable GAAP
financial measure.)

OPERATING EXPENSES

Lease operating expense ("LOE") was $7.2 million in the quarter, or $1.20 per
Mcfe, versus $8.4 million, or $0.95 per Mcfe in the prior year period. LOE
included $1.6 million or $0.27 per Mcfe for workovers performed in the
quarter, primarily in the Eagle Ford trend.

Production and other taxes for the quarter were $2.8 million, or $0.46 per
Mcfe, versus $2.0 million, or $0.23 in the prior year period, driven by higher
oil volumes as a percentage of total volumes. 

Transportation and processing expense was $2.6 million, or $0.43 per Mcfe in
the quarter, versus $4.1 million, or $0.47 per Mcfe in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense for the quarter
totaled $35.0 million, or $5.84 per Mcfe, versus $32.3 million, or $3.68 per
Mcfe in the prior year period. DD&A rate for the quarter was higher than the
prior year due to a higher percentage of production volumes coming from oil,
which carries a higher DD&A rate. DD&A expense per unit was $5.62 per Mcfe
for the prior quarter.

Exploration expense was $3.3 million, or $0.56 per Mcfe for the quarter,
versus $2.2 million, or $0.25 per Mcfe in the prior year period.
Approximately $1.4 million or 42% of exploration expense for the quarter was
associated with the expiration of undeveloped leasehold, and $0.4 million was
associated with seismic expense.

General and Administrative ("G&A") expense was $9.4 million, or $1.57 per Mcfe
in the quarter, versus $7.9 million, or $0.90 per Mcfe in the prior year
period. The first quarter includes additional expense of $1.5 million or
$0.25 per Mcfe primarily for 2012 employee bonuses paid in 2013 and increased
payroll taxes. For the quarter, the Company recorded non-cash G&A expenses
related to stock based compensation for its employees of $1.8 million, or
$0.30 per Mcfe, versus $1.6 million, or $0.18 per Mcfe in the prior year
period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss
of $13.1 million for the quarter versus an operating loss of $14.2 million for
the prior year period. Adjusted operating loss, when adjusting for realized
gain on derivatives not designated as hedges was $13.0 million.

(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 $13.4 million, or $2.24 per Mcfe, versus
$12.9 million, or $1.48 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 ($0.57 per Mcfe).

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $48.3 million, of which $46.0
million was spent on drilling and completion costs and $2.3 million on
leasehold acquisition, facilities and other expenditures. Approximately 54%
of the capital was spent in the Eagle Ford Shale trend, 19% in the Tuscaloosa
Marine Shale trend and 27% on the completion of previously drilled Haynesville
Shale wells that will be brought online in the second quarter.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $0.1 million on its derivatives not designated
as hedges and an unrealized loss of $2.1 million, for a net loss on
derivatives not designated as hedges of $2.0 million for the quarter.

Subsequent to quarter end, the Company added hedges on 2,000 barrels of oil
per day for 2014 at $91.98 and 10,000 MMBtu of natural gas per day for October
2013 through December 2014 at $4.18. The Company currently has 3,500 barrels
of oil per day hedged for 2013 at $94.50.

LIQUIDITY

The Company exited the quarter with $4.0 million in cash and $145.0 million
drawn on its senior bank revolving credit facility. Subsequent to quarter-end,
the Company issued $110 million of non-convertible, perpetual preferred stock,
receiving net proceeds of $106.2 million. Proforma for the preferred
offering, the Company had net debt of approximately $35 million at the end of
the quarter. The Company has recently received an increase in its borrowing
base to $225 million, providing proforma liquidity at quarter-end of
approximately $190 million. 

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 8 gross (3.6
net) wells, of which 5 gross (3.3 net) were in the Eagle Ford and 3 gross (1
net) were in the Tuscaloosa Marine Shale trend. A total of 8 gross (4 net)
wells were added to production during the quarter, of which 3 gross (2 net)
were in the Eagle Ford. As of March 31, 2013, the Company had 18 gross (10
net) wells waiting on completion, with 9 gross (4 net) in the Haynesville
Shale trend and 9 gross (6 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 24-hour peak
production rate of 1,300 BOE per day. The well has produced approximately
75,000 BOE in three months and is currently producing approximately 700 BOE
per day. The Company has spud its Smith 5-29H-1 (~ 88% WI) well in Amite
County, Mississippi, and currently plans to drill two additional operated
wells after the Smith 5-29H-1 by the end of the year. 

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 Ash 31H-1, which is a 7,000 foot lateral with 22 frac stages,
is still in completion phase, and the Ash 31H-2 well, which is a 5,300 foot
lateral with 18 frac stages has been flowing back for approximately two weeks
and is still cleaning up due to the large frac job of one million pounds of
proppant and 29,000 barrels of fluid per stage. Current 24-hour peak rate is
approximately 730 BOE (92% oil) per day, with 4% of the frac fluid recovered.
The Ash wells were stimulated with slick water fracs with 60-100% more frac
fluid and proppant per stage than any of the prior wells drilled to date. 

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, both of
which are in completion phase and were drilled with very little downtime. Both
wells are expected to be completed within 45 days. 

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale trend, the Company conducted drilling operations on 5
gross (3.3 net) wells in the quarter, and expects to drill 24 gross (16 net)
wells in 2013. In the quarter, 3 gross (two net) wells were completed, and
the Company expects to complete 25 gross (16.8 net) wells for the year. 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 (5.7 net) previously drilled
Haynesville Shale wells in 2013, comprised of 12 gross (4.7 net) non-operated
wells in North Louisiana and 1 gross (1 net) operated well in the Angelina
River trend. In the first quarter, 4 gross (1.5 net) wells were completed.

Subsequent to the first quarter, the Company completed its ACLCO No. 1H (100%
WI) well in the Angelina River trend. The well continues to clean up with a
current peak rate of 7,000 Mcfe per day on a restricted 15/64 inch choke with
7,775 psi with 2% of the frac fluid recovered. The Company intends to produce
the well on a restricted choke program similar to its core Haynesville Shale
wells in North Louisiana.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial
measures, including Adjusted EBITDAX, Discretionary cash flow, Adjusted
revenues, Adjusted operating income, Adjusted net loss applicable to common
stock and Cash operating margin. Management believes Adjusted EBITDAX,
Discretionary cash flow, Adjusted revenues, Adjusted operating income,
Adjusted net loss applicable to common stock and Cash margin are good
financial indicators of the Company's ability to internally generate operating
funds. None of Discretionary cash flow, Adjusted EBITDAX or Cash operating
margin, should be considered an alternative to net cash provided by operating
activities, as defined by GAAP. Adjusted revenues should not be considered an
alternative to total revenues, as defined by GAAP. Adjusted operating income
should not be considered an alternative to operating income (loss), as defined
by GAAP. Adjusted net loss applicable to common stock should not be
considered an alternative to net loss applicable to common stock, as defined
by GAAP. Management believes that all of these non-GAAP financial measures
provide useful information to investors because they are monitored and used by
Company management and widely used by professional research analysts in the
valuation and investment recommendations of companies within the oil and gas
exploration and production industry.

Initial production rates are subject to decline over time and should not be
regarded as reflective of sustained production levels. In particular,
production from horizontal drilling in shale oil and natural gas resource
plays and tight natural gas plays that are stimulated with extensive pressure
fracturing are typically characterized by significant early declines in
production rates.

Unless otherwise stated, oil production volumes include condensate.

Certain statements in this news release regarding future expectations and
plans for future activities may be regarded as "forward looking statements"
within the meaning of the Securities Litigation Reform Act. They are subject
to various risks, such as financial market conditions, changes in commodities
prices and costs of drilling and completion, operating hazards, drilling
risks, and the inherent uncertainties in interpreting engineering data
relating to underground accumulations of oil and gas, as well as other risks
discussed in detail in the Company's Annual Report on Form 10-K for the year
ended December 31, 2012 and other subsequent filings with the Securities and
Exchange Commission. Although the Company believes that the expectations
reflected in such forward looking statements are reasonable, it can give no
assurance that such expectations will prove to be correct.

Goodrich Petroleum is an independent oil and gas exploration and production
company listed on the New York Stock Exchange.



GOODRICH PETROLEUM CORPORATION
SELECTED INCOME AND PRODUCTION DATA
(In Thousands, Except Per Share Amounts)
                                                   Three Months Ended
                                                   March 31,
                                                   2013          2012
Volumes
 Natural gas (MMcf)                                4,144         7,466
 Oil and condensate (MBbls)                        308           217
 MMcfe - Total                                     5,992         8,765
 Mcfe per day                                      66,582        96,324
Total Revenues                                     $ 47,084     $ 45,308
Operating Expenses
 Lease operating expense                           7,216         8,354
 Production and other taxes                        2,760         1,993
 Transportation and processing                     2,597         4,128
 Depreciation, depletion and amortization          34,974        32,278
 Exploration                                       3,335         2,213
 Impairment                                       -             2,662
 General and administrative                        9,387         7,921
 Gain on sale of assets                            (43)          -
Operating loss                                    (13,142)      (14,241)
Other income (expense)
 Interest expense                                  (13,373)      (12,913)
 Interest income and other                         4             -
 Gain (Loss) on derivatives not designated as      (1,952)       9,425
 hedges
                                                   (15,321)      (3,488)
Loss before income taxes                           (28,463)      (17,729)
Income tax benefit                                -             -
Net loss                                           (28,463)      (17,729)
Preferred stock dividends                          1,512         1,512
Net loss applicable to common stock                $ (29,975)    $ (19,241)
 Unrealized loss on derivatives not designated as  2,104         6,468
 hedges
 Gain on sale of assets                            (43)          -
 Dry hole costs                                    200           -
 Impairment                                       -             2,662
Adjusted net loss applicable to common stock (1)   $ (27,714)    $ (10,111)
 Discretionary cash flow (see non-GAAP             $ 16,320     $ 29,946
 reconciliation) (2)
 Adjusted EBITDAX (see calculation and non-GAAP    $ 27,050     $ 40,357
 reconciliation)( 3)
Weighted average common shares outstanding -       36,684        36,338
basic
Weighted average common shares outstanding -       36,684        36,338
diluted (4)
Earnings per share
 Net loss applicable to common stock - basic       $   (0.82)  $   (0.53)
 Net loss applicable to common stock - diluted     $   (0.82)  $   (0.53)
Adjusted earnings per share
 Adjusted net loss applicable to common stock -    $   (0.76)  $   (0.28)
 basic (1)
 Adjusted net loss applicable to common stock -    $   (0.76)  $   (0.28)
 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 natural 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 potentially
dilutive instruments that were anti-dilutive due to the net income (loss)
applicable to common stock for the three months and year ended March 31, 2013,
respectively. We report our financial results in accordance with accounting
principles generally accepted in the United States of America ("GAAP").
However, management believes certain non-GAAP performance measures may provide
users of this financial information with additional meaningful comparisons
between current results and the results of our peers and of prior periods.

GOODRICH PETROLEUM CORPORATION
Per Unit Sales Prices and Costs
                                                Three Months Ended
                                                March 31,
                                                2013            2012
Average sales price per unit:
 Oil (per Bbl)
  Including realized gain on oil            $ 107.52        $ 103.84
 derivatives
  Excluding realized gain on oil            $ 107.02        $ 106.35
 derivatives
 Natural gas (per Mcf)
  Including realized gain on natural gas    $   3.40     $   5.19
 derivatives
  Excluding realized gain on natural gas    $   3.40     $   2.99
 derivatives
 Natural gas and oil (per Mcfe)
  Including realized gain on oil and        $   7.88     $   6.99
 natural gas derivatives
  Excluding realized gain on oil and        $   7.85     $   5.18
 natural gas derivatives
Costs Per Mcfe
 Lease operating expense                        $   1.20     $   0.95
 Production and other taxes                     $   0.46     $   0.23
 Transportation and processing                  $   0.43     $   0.47
 Depreciation, depletion and amortization       $   5.84     $   3.68
 Exploration                                    $   0.56     $   0.25
 Impairment                                    $      -  $   0.30
 General and administrative                     $   1.57     $   0.90
 Gain on sale of assets                         $  (0.01)     $      -
                                                $  10.05       $   6.79
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
                                     March 31,
                                     2013               2012
Net cash provided by operating       $   6,272        $    30,537
activities (GAAP)
Net changes in working capital       10,048             (591)
Discretionary cash flow              $ 16,320          $    29,946
Weighted average common shares       36,684             36,338
outstanding - basic
Weighted average common shares       36,684             36,338
outstanding - diluted (4)
Supplemental Balance Sheet Data
                                     As of
                                     March 31,          December 31,
                                     2013               2012
  Cash and cash equivalents          $   4,048        $     1,188
  Long-term debt                     621,390            568,671
Reconciliation of Net income (loss) to Adjusted EBITDAX
                                     Three Months Ended
                                     March 31,
                                     2013               2012
  Net loss (GAAP)                    $ (28,463)         $   (17,729)
  Exploration expense                3,335              2,213
  Depreciation, depletion and        34,974             32,278
  amortization
  Impairment                         -                  2,662
  Stock compensation expense         1,774              1,552
  Interest expense                  13,373             12,913
  Unrealized loss on derivatives not 2,104              6,468
  designated as hedges
  Other excluded items *             (47)               -
   Adjusted EBITDAX             $ 27,050          $    40,357
  * 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
                                     March 31,
                                     2013               2012
  Interest expense - cash            $   9,959        $     9,778
  Interest expense - noncash         3,414              3,135
  Total Interest                     13,373             12,913
  Unrealized loss on derivatives not 2,104              6,468
  designated as hedges
  Realized gain on derivatives not   (152)              (15,893)
  designated as hedges
  Total (gain) loss on derivatives   1,952              (9,425)
  not designated as hedges
  General and Administrative expense 7,613              6,369
  - cash
  General and Administrative expense 1,774              1,552
  - noncash
  Total General and Administrative   9,387              7,921
  expense



GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data continued (In Thousands):
Reconciliation of Adjusted Revenues and Total Revenues (unaudited)
                                                   Three Months Ended
                                                   March 31,
                                                   2013        2012
Total Revenues (GAAP)                              $ 47,084   $ 45,308
Realized gain on derivatives not designated as     152         15,893
hedges
Adjusted Revenues                                  $ 47,236   $   61,201
Reconciliation of Adjusted Operating Income (Loss) and Operating Loss
(unaudited)
                                                   Three Months Ended
                                                   March 31,
                                                   2013        2012
Operating loss (GAAP)                              $ (13,142)  $ (14,241)
Realized gain on derivatives not designated as     152         15,893
hedges
Adjusted Operating Income (Loss)                   $ (12,990)  $    1,652
Calculation of Cash operating margin (unaudited)
                                                   Three Months Ended
                                                   March 31,
                                                   2013        2012
Adjusted EBITDAX (see calculation and non-GAAP     $ 27,050   $ 40,357
reconciliation) (3)
Adjusted Revenues (see non-GAAP reconciliation)    $ 47,236   $   61,201
Cash operating margin                              57%         66%



SOURCE Goodrich Petroleum Corporation

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