Goodrich Petroleum Announces First Quarter 2014 Financial Results And Operational Update

    Goodrich Petroleum Announces First Quarter 2014 Financial Results And
                              Operational Update

PR Newswire

HOUSTON, May 6, 2014

HOUSTON, May 6, 2014 /PRNewswire/ --Goodrich Petroleum Corporation (NYSE:
GDP) (the "Company") today announced financial and operating results for the
first quarter ended March 31, 2014.

FINANCIAL RESULTS:

  oRevenues totaled $51.8 million in the quarter versus $47.1 million in the
    prior year period. Average realized price per unit was $8.00 per Mcfe in
    the quarter versus $7.85 per Mcfe in the prior year period;
  oEarnings before interest, taxes, DD&A, non-cash general and administrative
    expenses and exploration ("Adjusted EBITDAX") was $29.1 million in the
    quarter, compared to $27.1 million in the prior year period;
  oProduction totaled 6.5 billion cubic feet equivalent ("Bcfe") in the
    quarter, or an average of 72,000 Mcfe per day, versus 6.0 Bcfe, or an
    average of 66,600 Mcfe per day in the prior year period.

TUSCALOOSA MARINE SHALE ("TMS"):

  oThe Company is currently fracking its C.H. Lewis 30-19H-1 (81.4% WI) well
    in Amite County, Mississippi, which was drilled in 36 days and will have
    an approximate 6,600 foot lateral with 26 planned frac stages. The
    Company will use the same enhanced completion design of reduced frac
    intervals and additional proppant per stage as used on its last well
    drilled in the TMS;
  oThe Company has recently moved into completion operations on its Nunnery
    12-1H #1 (94.1% WI) well in Amite County, Mississippi and its Beech Grove
    94H #1 (66.7% WI) well in East Feliciana Parish, Louisiana, with plans to
    frac both wells in May;
  oThe Company is currently drilling its SLC, Inc. 81H-1 (66.7% WI) well in
    West Feliciana Parish, Louisiana and will commence drilling operations on
    its Bates 25-24H #1 (97.6% WI) and Denkmann 33-28H #2 (75% WI) wells in
    Amite County, Mississippi in the coming days.

FINANCIAL RESULTS

REVENUES

Revenues totaled $51.8 million in the quarter versus $47.1 million in the
prior year period. Average realized price per unit was $8.00 per Mcfe in the
quarter versus $7.85 per Mcfe in the prior year period. When factoring in the
realized gain or loss on derivatives not designated as hedges, Adjusted
Revenues totaled $49.1 million in the quarter versus $47.2 million in the
prior year period, and average realized price per unit was $7.58 per Mcfe
versus $7.88 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 6.5 billion cubic feet equivalent ("Bcfe") in the quarter,
or an average of 72,000 Mcfe per day, versus 6.0 Bcfe, or an average of 66,600
Mcfe per day in the prior year period. Oil production totaled 341,000 barrels
of oil in the quarter, or an average of 3,787 barrels per day, versus 308,000
barrels of oil, or an average of 3,423 barrels per day, in the prior year
period. Production for the quarter was negatively affected by production
downtime in the Eagle Ford Shale trend, completion delays and previously
disclosed mechanical issues with the Company's Huff 18-7H-1 (97% WI) and
Weyerhaeuser 51H-1 (66.7% WI) wells in the TMS. Natural gas production
totaled 4.4 Bcf in the quarter, or an average of 49,230 Mcf per day, versus
4.1 Bcf, or an average of 46,000 Mcf per day, in the prior year period.

The Company anticipates producing between 4,200 – 4,500 Bbls/d of oil and
43,000 – 46,000 Mcf/d of natural gas during the second quarter of 2014, with
an expected further acceleration in the rate of growth in oil volumes
beginning in the third quarter due to an increase in capital expenditures and
well completions in the TMS and Eagle Ford Shale trend from the second quarter
through the end of the year.

CAPITAL EXPENDITURES

Capital expenditures totaled $55.8 million in the quarter, of which $45.3
million was spent on drilling and completion costs, $5.8 million on leasehold
acquisition and $4.7 million on facilities, capital workovers and other
expenditures. Approximately 85% of the quarter's total capital expenditures
were spent in the TMS drilling and completing wells and extending existing
leasehold for future drilling operations. The Company anticipates capital
expenditures between $90 – 110 million in the second quarter with
approximately 85% allocated towards oil focused drilling and completion
activities in the TMS and Eagle Ford Shale trend. 

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative
expenses and exploration ("Adjusted EBITDAX") was $29.1 million in the
quarter, compared to $27.1 million in the prior year period.

Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, was $19.4 million in the
quarter, compared to $16.3 million in the prior year period and $22.0 million
in the prior quarter. Net cash provided by operating activities was $6.6
million in the quarter, compared to $6.3 million in the prior year period.

Adjusted EBITDAX and DCF were both impacted by a $2.7 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 $29.9 million
in the quarter, or ($0.68) per basic share, versus a net loss applicable to
common stock of $30.0 million, or ($0.82) per basic share in the prior year
period. Adjusted net loss applicable to common stock was $24.1 million for
the quarter, or ($0.54) per basic share, which excludes the impact of
unrealized losses on derivatives not designated as hedges of $5.8 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 $8.6 million in the quarter, or $1.33 per
Mcfe, versus $7.2 million, or $1.20 per Mcfe, in the prior year period, which
included $2.0 million, or $0.30 per Mcfe, for workovers performed in the
quarter, versus $1.6 million, or $0.27 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 Shale trend. 

Production and other taxes were $2.4 million in the quarter, or $0.38 per
Mcfe, versus $2.8 million, or $0.46 per Mcfe, in the prior year period.
Production taxes decreased 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 $2.4 million in the quarter, or
$0.37 per Mcfe, versus $2.6 million, or $0.43 per Mcfe, in the prior year
period. 

Depreciation, depletion and amortization ("DD&A") expense was $29.2 million in
the quarter, or $4.51 per Mcfe, versus $35.0 million, or $5.84 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 $2.3 million in the quarter, or $0.36 per Mcfe, versus
$3.3 million, or $0.56 per Mcfe, in the prior year period. Approximately $1.2
million, or 53% of the exploration expense for the quarter, was associated
with leases in the far northwest corner of the Company's Eagle Ford Shale
trend acreage position that were not extended or renewed.

General and Administrative ("G&A") expense was $8.9 million in the quarter, or
$1.38 per Mcfe, versus $9.4 million, or $1.57 per Mcfe, in the prior year
period. G&A expense related to non-cash, stock based compensation for its
employees totaled $2.4 million in the quarter, or $0.36 per Mcfe, versus $1.8
million, or $0.30 per Mcfe, in the prior year period. 

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss
of $2.1 million in the quarter, versus an operating loss of $13.1 million in
the prior year period. Adjusted operating loss, when adjusted for realized
gain on derivatives not designated as hedges, was a loss of $4.9 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 $11.9 million in the quarter, or $1.83 per Mcfe,
versus $13.4 million, or $2.23 per Mcfe, in the prior year period. Non-cash
interest expense, associated with the Company's debt, totaled $2.6 million
(representing 22% of total interest expense) in the quarter, or $0.41 per
Mcfe, versus $3.4 million, or $0.57 per Mcfe, in the prior year period.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a loss of $2.7 million on its derivatives not designated
as hedges and an unrealized loss of $5.8 million, which resulted in a net loss
of $8.5 million on its derivatives not designated as hedges in the quarter,
versus a net loss of $2.0 million during the prior year period.

For the remainder of 2014, the Company has a total of 3,800 Bbls/d 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, the Company has 30,000 MMBtu/d 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 $0.8 million in cash, $51.8 million of
restricted cash and $10.0 million drawn on its senior credit facility,
providing approximately $260.0 million of available liquidity, excluding the
$51.8 million of restricted cash, as the Company exited the quarter. The
Company's borrowing base was reduced to $250.0 million in April pursuant to
the spring borrowing base redetermination period, primarily due to lower bank
deck natural gas pricing. 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 11 gross (6.8
net) wells, of which 3 gross (2 net) were in the Eagle Ford Shale trend and 8
gross (4.8 net) were in the TMS. A total of 3 gross (2.6 net) wells were
added to production during the quarter, of which all were in the TMS. As of
March 31, 2014, the Company had 2 gross (1.3 net) wells drilled and waiting on
completion, which was comprised of one gross (0.67 net) well in the Eagle Ford
Shale trend and one gross (0.67 net) well in the TMS.

Tuscaloosa Marine Shale:

The Company previously reported production results from both the CMR 8-5H-1
(100% WI) and Blades 33H-1 (66.7% WI) wells completed in Amite County,
Mississippi and Tangipahoa Parish, Louisiana, respectively. The CMR 8-5H-1
was a lower target well that achieved a peak 24-hour production rate of 950
barrels of oil equivalent ("BOE") per day with approximately 5,300 feet of
lateral and 20 frac stages. The Blades 33H-1 was a lower target well that
achieved a peak 24-hour production rate of 1,270 BOE/day with approximately
5,000 feet of lateral and 20 frac stages. The Company enhanced its frac
design on the Blades well by narrowing the frac intervals and pumping
approximately 100,000 pounds of additional proppant per stage. Both wells
were completed using composite frac plugs that were all successfully drilled
out before flowback operations commenced.

The Company is currently fracking its C.H. Lewis 30-19H-1 (81.4% WI) well in
Amite County, Mississippi, which was drilled in 36 days and will have an
approximate 6,600 foot lateral with 26 planned frac stages. The Company will
utilize its enhanced completion design of reduced frac intervals and
additional proppant per stage.

The Company has recently moved into completion operations on its Nunnery 12-1H
#1 (94.1% WI) well in Amite County, Mississippi and its Beech Grove 94H #1
(66.7% WI) well in East Feliciana Parish, Louisiana. With regard to the
Nunnery 12-1H #1, the Company drilled an approximate 6,000 foot lateral and is
scheduled to commence fracking operations immediately after the C.H. Lewis
30-19H-1 well. The Company's Beech Grove 94H #1 well, which was drilled with
an approximate 6,000 foot lateral, is scheduled to be fracked the end of May.


The Company is currently drilling its SLC, Inc. 81H-1 (66.7% WI) well in West
Feliciana Parish, Louisiana and will commence drilling operations on its Bates
25-24H #1 (97.6% WI) and Denkmann 33-28H #2 (75% WI) wells in the coming
days. The Company currently has three rigs running in the field with plans to
add two additional rigs by the end of the year pending continued success. 

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

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas:

The Company commenced drilling operations in the Eagle Ford Shale trend in
February and has begun completion operations on its Burns Ranch A 56H, 70H and
71H (66.7% WI) wells in LaSalle County, Texas. All three wells were drilled
off the same pad and have an average of 8,750 foot laterals with 33 planned
frac stages per well. All three wells are scheduled to be fracked by the end
of May. The Company has commenced drilling operations on its Gemini 4H and 5H
(estimated 66.7% WI) wells from a single pad. Both wells have a scheduled
frac date in early June.

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
                                                   March 31,
                                                   2014          2013
 Volumes
   Natural gas (MMcf)                              4,431         4,144
   Oil and condensate (MBbls)                      341           308
   MMcfe - Total                                   6,476         5,992
   Mcfe per day                                    71,957        66,582
 Total Revenues                                    $ 51,803     $ 47,084
 Operating Expenses
   Lease operating expense                         8,617         7,216
   Production and other taxes                      2,441         2,760
   Transportation and processing                   2,372         2,597
   Depreciation, depletion and amortization        29,238        34,974
   Exploration                                     2,317         3,335
   General and administrative                      8,941         9,387
   Gain on sale of assets                          -             (43)
 Operating loss                                   (2,123)       (13,142)
 Other income (expense)
   Interest expense                                (11,878)      (13,373)
   Interest income and other                       10            4
   Loss on derivatives not designated as hedges    (8,501)       (1,952)
                                                   (20,369)      (15,321)
 Loss before income taxes                          (22,492)      (28,463)
 Income tax benefit                               -             -
 Net loss                                          (22,492)      (28,463)
 Preferred stock dividends                         7,431         1,512
 Net loss applicable to common stock               $ (29,923)    $ (29,975)
   Unrealized loss on derivatives not designated   5,770         2,104
   as hedges
   Gain on sale of assets                          -             (43)
   Dry hole costs                                  44            200
 Adjusted net loss applicable to common stock (1)  $ (24,109)    $ (27,714)
   Discretionary cash flow (see non-GAAP           $ 19,399     $ 16,320
   reconciliation) (2)
   Adjusted EBITDAX (see calculation and non-GAAP  $ 29,051     $ 27,050
   reconciliation)(3)
 Weighted average common shares outstanding -      44,273        36,684
 basic
 Weighted average common shares outstanding -      44,273        36,684
 diluted (4)
 Earnings per share
   Net loss applicable to common stock - basic     $   (0.68)  $   (0.82)
   Net loss applicable to common stock - diluted   $   (0.68)  $   (0.82)
 Adjusted earnings per share
   Adjusted net loss applicable to common stock -  $   (0.54)  $   (0.76)
   basic (1)
   Adjusted net loss applicable to common stock -  $   (0.54)  $   (0.76)
   fully diluted (1)

 (1) Adjusted net loss applicable to common stock is defined as net 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 excludesapproximately10.2 millionpotentially
 dilutive instruments that were anti-dilutive due to the net loss applicable
 to common stock for each the three months ended March 31, 2014 and March 31,
 2013. 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,
                                         2014               2013
 Average sales price per unit:
  Oil (per Bbl)
   Including realized oil            $   91.34       $  107.52
  derivatives
   Excluding realized on oil         $   98.27       $  107.02
  derivatives
  Natural gas (per Mcf)
   Including realized natural gas    $     4.05     $     3.40
  derivatives
   Excluding realized natural gas    $     4.13     $     3.40
  derivatives
  Natural gas and oil (per Mcfe)
   Including realized oil and        $     7.58     $     7.88
  natural gas derivatives
   Excluding realized oil and        $     8.00     $     7.85
  natural gas derivatives
 Costs Per Mcfe
  Lease operating expense                $     1.33     $     1.20
  Production and other taxes             $     0.38     $     0.46
  Transportation and processing          $     0.37     $     0.43
  Depreciation, depletion and            $     4.51     $     5.84
  amortization
  Exploration                            $     0.36     $     0.56
  General and administrative             $     1.38     $     1.57
  Gain on sale of assets                 $        -  $    (0.01)
                                         $     8.33     $    10.05
 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,
                                               2014          2013
 Net cash provided by operating activities     $   6,555   $     6,272
 (GAAP)
 Net changes in working capital                12,844        10,048
 Discretionary cash flow                       $ 19,399     $    16,320
 Weighted average common shares outstanding -  44,273        36,684
 basic
 Weighted average common shares outstanding -  44,273        36,684
 diluted (4)
 Supplemental Balance Sheet Data
                                               As of
                                               March 31,     December 31,
                                               2014          2013
  Cash and cash equivalents                    $    810  $    49,220
  Long-term debt                               447,115       435,866
 Reconciliation of Net loss to Adjusted EBITDAX
                                               Three Months Ended
                                               March 31,
                                               2014          2013
  Net loss (GAAP)                              $ (22,492)   $   (28,463)
  Exploration expense                          2,317         3,335
  Depreciation, depletion and amortization     29,238        34,974
  Stock compensation expense                   2,350         1,774
  Interest expense                            11,878        13,373
  Unrealized loss on derivatives not           5,770         2,104
  designated as hedges
  Other excluded items *                       (10)          (47)
   Adjusted EBITDAX                       $  29,051   $    27,050
  * Other excluded items include Interest income and other and gain on sale
  of assets.
 Other Information
                                               Three Months Ended
                                               March 31,
                                               2014          2013
  Interest expense - cash                      $   9,246   $     9,959
  Interest expense - noncash                   2,632         3,414
  Total Interest                               11,878        13,373
  Unrealized loss on derivatives not           5,770         2,104
  designated as hedges
  Realized (gain) loss on derivatives not      2,731         (152)
  designated as hedges
  Total loss on derivatives not designated as  8,501         1,952
  hedges
  General and Administrative expense - cash    6,591         7,613
  General and Administrative expense - noncash 2,350         1,774
  Total General and Administrative expense     8,941         9,387



 GOODRICH PETROLEUM CORPORATION
 Selected Cash Flow Data continued (In Thousands):
 Reconciliation of Adjusted Revenues and Total Revenues (unaudited)

                                                      Three Months Ended
                                                      March 31,
                                                      2014       2013
 Total Revenues (GAAP)                                $ 51,803  $   47,084
 Realized gain (loss) on derivatives not designated   (2,731)    152
 as hedges
 Adjusted Revenues                                    $ 49,072  $   47,236

 Reconciliation of Adjusted Operating Loss and Operating Loss (unaudited)

                                                   Three Months Ended
                                                   March 31,
                                                   2014        2013
 Operating loss (GAAP)                             $ (2,123)  $   (13,142)
 Realized gain (loss) on derivatives not           (2,731)     152
 designated as hedges
 Adjusted Operating Loss                           $ (4,854)  $  (12,990)

 Calculation of Cash operating margin (unaudited)

                                                       Three Months Ended
                                                       March 31,
                                                       2014        2013
 Adjusted EBITDAX (see calculation and non-GAAP        $  29,051  $  27,050
 reconciliation) (3)
 Adjusted Revenues (see non-GAAP reconciliation)       $  49,072  $  47,236
 Cash operating margin                                 59%         57%



SOURCE Goodrich Petroleum Corporation

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