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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