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Goodrich Petroleum Announces First Quarter 2015 Financial Results And Operational Update

HOUSTON, May 6, 2015 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial results and an operational update for the first quarter ended March 31, 2015. 

FINANCIAL RESULTS:

  • Adjusted Revenues were $37.1 million for the quarter versus $49.1 million in the prior year period;
  • Earnings before interest, taxes, non-cash General & Administrative ("G&A") expenses and exploration ("Adjusted EBITDAX") was $24.5 million in the quarter, compared to $29.1 million in the prior year period;
  • Capital expenditures for the quarter totaled $48.4 million, which will be reduced to an estimated $10 – 15 million in the second quarter;
  • Production for the quarter totaled 780,000 barrels of oil equivalent ("Boe") (56% oil), which was affected by deferred completions. Oil volume growth expected to resume in the third quarter as previously drilled wells are completed beginning in June and additional drilling operations commence;
  • Cost cutting initiatives in place, including a projected 20 – 25% reduction in cash G&A for 2015;
  • Operating expenses for the quarter were lower by $16.4 million or 30% from the prior year period due to cost reduction efforts and the sale of a non-core property in December 2014;
  • Additional liquidity provided from $148 million of capital raised in the first quarter.

TUSCALOOSA MARINE SHALE ("TMS"):

  • Industry-wide well results continuing to improve, with a recent well producing at a peak rate in excess of 1,900 Boe (92% oil) per day and the top ten well results averaging peak rates of approximately 1,500 Boe (93% oil) per day; and
  • Current well costs lower by approximately $3 million due to reduced drilling days and lower service costs, resulting in competitive rates of return at current strip prices.

THE COMPANY HAS POSTED A NEW PRESENTATION ON THE COMPANY'S WEBSITE WHICH WILL BE REVIEWED ON THE EARNINGS CONFERENCE CALL.  INVESTORS CAN ACCESS THE SLIDES AT: http://goodrichpetroleum.investorroom.com/events-and-presentations

FINANCIAL RESULTS

REVENUES

Revenues totaled $24.0 million in the quarter versus $51.8 million in the prior year period.  Average realized price per unit was $30.94 per Boe in the quarter versus $47.99 per Boe in the prior year period.  When factoring in the realized gain or loss on derivatives not designated as hedges, Adjusted Revenues totaled $37.1 million in the quarter versus $49.1 million in the prior year period, and average realized price per unit was $47.71 per Boe versus $45.46 per Boe in the prior year period.

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

PRODUCTION

Production totaled approximately 780,000 Boe in the quarter, or an average of 8,671 Boe per day, versus 1,079,000 Boe, or an average of 11,993 Boe per day, in the prior year period.  Oil production totaled 435,000 barrels of oil in the quarter (56% of total production), or an average of approximately 4,800 Bbls per day, versus 341,000 barrels of oil (32% of total production), or an average of approximately 3,800 Bbls per day, in the prior year period.  Oil production for the quarter was negatively impacted from the completion deferral of six wells in the TMS.  Oil volume growth expected to resume in the third quarter as previously drilled wells are completed beginning in June.  Natural gas production totaled 2.1 Bcf in the quarter, or an average of approximately 23,000 Mcf per day, versus 4.4 Bcf, or an average of 49,200 Mcf per day, in the prior year period.  Natural gas production for the quarter was negatively impacted by the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas.

CAPITAL EXPENDITURES

Capital expenditures totaled $48.4 million in the quarter, of which $43.3 million was spent on drilling and completion costs, $0.9 million on leasehold acquisition and $4.2 million on facilities, capital workovers and other expenditures.  While we booked capital expenditures of $48.5 million in the quarter, we paid out cash amounts totaling $68.4 million in the three months ended March 3,1 2015.  Cash paid for capital combined with negative changes in working capital of $7.7 million for the quarter ended March 31, 2015 totaled $76.1 million.  Approximately 80% of the quarter's total capital expenditures were spent in the TMS drilling and completing wells and extending leases for future drilling operations.  The Company currently has no rigs running in the TMS with six wells waiting on completion, which are currently scheduled to begin completion operations in June.  The Company anticipates capital expenditures between $10 - 15 million in the second quarter and reaffirms its full year preliminary capital budget of $90 - 110 million.    

GUIDANCE

The Company anticipates producing between 4,250 – 4,650 Bbls/d of oil and 22,500 – 26,500 Mcf/d of natural gas during the second quarter of 2015, with oil volumes increasing as we exit the second quarter and begin completing six previously drilled TMS wells.  The Company reaffirms its previously announced full year 2015 production guidance of 4,800 – 5,200 Bbls/d of oil and 23,000 – 26,000 Mcf/d of natural gas with a total net capital expenditure budget of $90 – 110 million.   

CASH FLOW

Adjusted EBITDAX was $24.5 million in the quarter, compared to $29.1 million in the prior year period. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $13.4 million in the quarter, compared to $19.4 million in the prior year period.  Net cash provided by operating activities was $5.7 million in the quarter, compared to $6.6 million 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-US GAAP financial measures, to their most directly comparable US GAAP financial measure.)

NET INCOME

The Company announced a net loss applicable to common stock of $28.5 million in the quarter, or ($0.58) per basic share, versus a net loss applicable to common stock of $29.9 million, or ($0.68) per basic share in the prior year period.  Adjusted net loss applicable to common stock was $18.9 million for the quarter, or ($0.38) per basic share, versus an adjusted net loss applicable to common stock of $22.9 million, or ($0.52) per basic share in the prior year period.

(See accompanying tables at the end of this press release that reconcile adjusted net loss applicable to common stock, a non-US GAAP measure, to its most directly comparable US GAAP financial measure.) 

OPERATING EXPENSES

Lease operating expense ("LOE") was lower by $4.5 million to $4.1 million in the quarter, or $5.30 per Boe, versus $8.6 million, or $7.98 per Boe, in the prior year period.  LOE for the quarter included $0.2 million, or $0.32 per Boe, for workovers, versus $2.0 million, or $1.82 per Boe, in the prior year period.  The decrease in LOE was primarily due to (i) the divestment of our East Texas assets during the fourth quarter of 2014; (ii) a reduction in workover activity in the Eagle Ford and Tuscaloosa Marine Shale trends; and (iii) the first phase of service cost reductions.    

Production and other taxes were $1.0 million lower to $1.4 million in the quarter, or $1.81 per Boe, versus $2.4 million, or $2.26 per Boe, in the prior year period.  The decrease in production and other taxes was primarily due to the divestment of our East Texas assets during the fourth quarter of 2014 and more oil production from the TMS, which has severance tax abatement for a minimum of twenty-four months after initial production.     

Transportation and processing expense was lower by $1.2 million to $1.2 million in the quarter, or $1.60 per Boe, versus $2.4 million, or $2.20 per Boe, in the prior year period.  The decrease in transportation and processing expense pertains directly to lower operated natural gas production due to the divestment of our East Texas assets during the fourth quarter of 2014. 

Depreciation, depletion and amortization ("DD&A") expense was lower by $9.0 million to $20.2 million in the quarter, or $25.93 per Boe, versus $29.2 million, or $27.09 per Boe, in the prior year period.  The decrease in DD&A expense was primarily due to the divestment of our East Texas assets during the fourth quarter of 2014 and lower Eagle Ford Shale trend DD&A. 

Exploration expense was higher by $1.4 million to $3.7 million in the quarter, or $4.69 per Boe, versus $2.3 million, or $2.15 per Boe, in the prior year period.  The increase in exploration expense pertains to non-cash lease expiration expense in the Eagle Ford and Tuscaloosa Marine Shale trends and early drilling rig termination payments.

General and Administrative expense was lower by $1.1 million to $7.8 million in the quarter, or $9.93 per Boe, versus $8.9 million, or $8.28 per Boe, in the prior year period.  G&A expense related to non-cash, stock based compensation totaled $1.9 million in the quarter, or $2.42 per Boe, versus $2.4 million, or $2.18 per Boe, in the prior year period.  G&A expense for the quarter was negatively impacted by $0.3 million associated with non-recurring expenses primarily associated with severance payments due to a 20% reduction in employees.  The Company expects year over year cash G&A for 2015 to be down 20 – 25% versus the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $13.5 million in the quarter, versus an operating loss of $2.1 million in the prior year period.  Adjusted operating loss, when adjusted for cash received in settlement of derivative instruments of $13.1 million, was a loss of $0.4 million for the quarter.   

(See accompanying tables at the end of this press release that reconcile adjusted operating loss, a non-US GAAP financial measure to its most directly comparable US GAAP financial measure.) 

INTEREST EXPENSE

Interest expense totaled $12.1 million in the quarter, or $15.49 per Boe, versus $11.9 million, or $11.00 per Boe, in the prior year period.  Non-cash interest expense associated with the Company's debt totaled $2.1 million (representing 17% of total interest expense) in the quarter, or $2.68 per Boe, versus $2.6 million, or $2.44 per Boe, in the prior year period.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company had a realized gain of $4.4 million on its derivatives not designated as hedges in the quarter, versus a loss of $8.5 million during the prior year period.  For 2015, the Company has a total of 3,500 Bbls/day (70% of the midpoint of production guidance) swapped at an average price of $96.11 per Bbl.     

LIQUIDITY

The Company exited the quarter with credit facility borrowings, net of cash on hand, of $45.6 million with a borrowing base of $150 million.  The next borrowing base redetermination is scheduled for October 1, 2015. The Company expects to finance the remainder of its 2015 capital expenditure budget of approximately $50 million from cash flow from operations and available capacity on its senior credit facility. 

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 5.0 gross (3.9 net) TMS wells.  A total of 4.0 gross (3.6 net) wells were added to production during the quarter, which included 3.0 gross (2.6 net) wells added late in the quarter in the TMS and 1.00 gross (1.0 net) wells in the Haynesville Shale trend.  As of March 31, 2015, the Company had 6.0 gross (4.8 net) TMS wells drilled and waiting on completion.

Tuscaloosa Marine Shale:

The Company has completed its first two well pad, the CMR/Foster Creek 8H-1 (79% WI) and CMR/Foster Creek 8H-2 (82% WI) wells in Wilkinson County, Mississippi.  The CMR/Foster Creek 8H-1 well was completed in March and achieved a peak 24-hour production rate to date of approximately 980 Boe per day, comprised of 920 Bbls of oil (94%) and 350 Mcf of natural gas from an approximate 4,300 foot completed lateral with 14 frac stages.  The CMR/Foster Creek 8H-2 well was completed in March and achieved a peak 24-hour production rate to date of approximately 950 Boe per day, comprised of 870 Bbls of oil (92%) and 470 Mcf of natural gas from an approximate 5,900 foot completed lateral with 19 frac stages. 

The Company completed its Kent 41H-1 (99% WI) well in Tangipahoa Parish, Louisiana in the first quarter; however, after rigging up a coiled tubing unit to drill out frac plugs with a slightly oversized mill, operations were shut down due to tight hole conditions.  The Company plans to resume operations with an undersized mill once completion operations resume in the June/July timeframe.  While waiting to resume coiled tubing operations, the Company flowed the well back through the frac plugs at a rate of 650 Boe per day.  Since this completion, the Company has successfully utilized fully dissolvable frac plugs, which eliminates the need to drill out frac plugs and saves approximately $0.5 million per well.  

The Company plans to commence completion operations on its backlog of six gross uncompleted TMS wells starting in June and anticipates all wells completed and added to production by the beginning of September.  The Company currently has no rigs running in the play but expects to add a rig to its TMS operations later in the year.

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

Haynesville Shale – Angelina River Trend

The Company has completed its ACLCO No. 2H (100% WI) well in Angelina County, Texas on a restricted 12/64 inch choke at 7,100 Mcf per day with 11,100 psi.  The Company intends to keep the well choked back to minimize drawdown and maximize its reserve.

OTHER INFORMATION

In this press release, the Company refers to several non-US 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 performance and ability to internally generate operating funds.  Neither DCF nor Cash operating margin, should be considered an alternative to net cash provided by operating activities, as defined by US GAAP.  Adjusted revenues should not be considered an alternative to total revenues, as defined by US GAAP.  Adjusted operating income (loss) should not be considered an alternative to operating income (loss), as defined by US GAAP.  Adjusted net loss applicable to common stock and Adjusted EBITDAX should not be considered an alternative to net loss applicable to common stock, as defined by US GAAP.  Management believes that all of these non-US 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, 2014 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 natural 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,





2015


2014


Volumes







Natural gas (MMcf)


2,071


4,431



Oil and condensate (MBbls)


435


341



Boe - Total


780


1,079










Boe per day


8,671


11,993









Total Revenues


$  24,030


$  51,803









Operating Expenses







Lease operating expense


4,138


8,617



Production and other taxes


1,409


2,441



Transportation and processing


1,247


2,372



Depreciation, depletion and amortization


20,233


29,238



Exploration


3,658


2,317



General and administrative


7,751


8,941



(Gain) on sale of assets


(892)


-



Other


(45)


-


Operating  loss


(13,469)


(2,123)









Other income (expense)







Interest expense


(12,079)


(11,878)



Interest income and other


-


10



Gain (loss) on derivatives not designated as hedges


4,430


(8,501)





(7,649)


(20,369)









Loss before income taxes


(21,118)


(22,492)


Income tax benefit 


-


-


Net loss  


(21,118)


(22,492)


Preferred stock dividends


7,431


7,431









Net loss applicable to common stock


$ (28,549)


$ (29,923)










(Gain) loss on derivatives not designated as hedges


(4,430)


8,501



Net cash received (paid) in settlement of derivative instruments


13,094


(2,731)



Lease expirations


1,952


1,231



Dry hole cost


8


44



(Gain) loss on sale of assets


(892)


-



Other


(45)


-









Adjusted net loss applicable to common stock (1)


$ (18,862)


$ (22,878)










Discretionary cash flow (see non-US GAAP reconciliation) (2)


$  13,391


$  19,399










Adjusted EBITDAX (see calculation and non-US GAAP reconciliation) (3)


$  24,465


$  29,051









Weighted average common shares outstanding - basic


49,110


44,273


Weighted average common shares outstanding - diluted (4)


49,110


44,273









Earnings per share







Net loss applicable to common stock - basic


$     (0.58)


$     (0.68)



Net loss applicable to common stock - diluted


$     (0.58)


$     (0.68)









Adjusted earnings per share







Adjusted net loss applicable to common stock - basic (1)


$     (0.38)


$     (0.52)



Adjusted net loss applicable to common stock - fully diluted (1)


$     (0.38)


$     (0.52)



(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  accounting principles generally accepted in the United States of America ("US 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-US GAAP measure of operating cash flow is useful as an indicator of an oil and natural 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 US 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 adjusted EBITDAX, gain/losses on derivatives, less net cash received or paid in settlement of commodity derivatives are excluded from Adjusted EBITDAX. Other excluded items include Interest income and other, (Gain) loss on sale of assets, Loss on early extinguishment of debt, Stock compensation expense and Other expense.


(4) Fully diluted shares excludes approximately 15.9 million and 12.3 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the three months ended March 31, 2015 and 2014, respectively.  We report our financial results in accordance with US GAAP. However, management believes certain non-US 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,





2015


2014









Average sales price per unit:







Oil (per Bbl)







     Including net cash received/paid to settle oil derivatives 


$ 75.95


$ 91.34



     Excluding net cash received/paid to settle oil derivatives


$ 45.86


$ 98.27



Natural gas (per Mcf)







     Including net cash received/paid to settle natural gas derivatives


$   2.02


$   4.05



     Excluding net cash received/paid to settle natural gas derivatives


$   2.02


$   4.13



Oil and natural gas (per Boe)







     Including net cash received/paid to settle oil and natural gas derivatives


$ 47.71


$ 45.46



     Excluding net cash received/paid to settle oil and natural gas derivatives


$ 30.94


$ 47.99
















Costs Per Boe







Lease operating expense


$   5.30


$   7.98



Production and other taxes


$   1.81


$   2.26



Transportation and processing


$   1.60


$   2.20



Depreciation, depletion and amortization


$ 25.93


$ 27.09



Exploration


$   4.69


$   2.15



General and administrative


$   9.93


$   8.28



(Gain) loss on sale of assets


$ (1.14)


$         -



Other


$ (0.06)


$         -





$ 48.08


$ 49.98









Note: Amounts on a per Boe 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,



2015


2014







Net cash provided by operating activities (US GAAP)

5,717


6,555


Net changes in working capital

(7,674)


(12,844)


Discretionary cash flow

$  13,391


$        19,399








Weighted average common shares outstanding - basic

49,110


44,273


Weighted average common shares outstanding - diluted (4)

49,110


44,273








Supplemental Balance Sheet Data



As of




March 31,


December 31,




2015


2014









  Cash and cash equivalents

$     6,426


$                  8









  Long-term debt

585,591


568,625







Reconciliation of Net loss to Adjusted EBITDAX



Three Months Ended




March 31,




2015


2014









  Net loss (US GAAP)

$ (21,118)


$      (22,492)



  Exploration expense

3,658


2,317



  Depreciation, depletion and amortization ("DD&A")

20,233


29,238



  Stock compensation expense

1,886


2,350



  Interest expense 

12,079


11,878



  (Gain) loss on derivatives not designated as hedges

(4,430)


8,501



  Net cash received (paid) in settlement of derivative instruments

13,094


(2,731)



  Other excluded items *

(937)


(10)



      Adjusted EBITDAX

$  24,465


$        29,051









*  Other excluded items include Interest income and other, (Gain) loss on sale of assets and Other expense.







Other Information



Three Months Ended




March 31,




2015


2014









Interest expense - cash

$     9,988


$          9,246



Interest expense - noncash

2,091


2,632



Total Interest

$  12,079


$        11,878









Change in fair value of derivatives not designated as hedges prior to cash settlement

$     8,664


$          5,770



Net cash (received) paid in settlement of derivative instruments

(13,094)


2,731



Total (gain) on derivatives not designated as hedges

$   (4,430)


$          8,501









General and Administrative expense - cash

$     5,865


$          6,591



General and Administrative expense - noncash

1,886


2,350



Total General and Administrative expense

$     7,751


$          8,941


 

 

GOODRICH PETROLEUM CORPORATION

Selected Cash Flow Data continued (In Thousands):













Reconciliation of Adjusted Revenues and Total Revenues (unaudited)








Three Months Ended



March 31,



2015


2014







Total Revenues (US GAAP)

$  24,030


$ 51,803


Net cash received (paid) in settlement of derivative instruments

13,094


(2,731)


Adjusted Revenues

$  37,124


$    49,072














Reconciliation of Adjusted Operating Income and Operating Income (unaudited)








Three Months Ended



March 31,



2015


2014







Operating loss (US GAAP)

$ (13,469)


$  (2,123)


Net cash received (paid) in settlement of derivative instruments

13,094


(2,731)


Impairment

-


-


Adjusted Operating  loss

$      (375)


$     (4,854)














Calculation of Cash operating margin (unaudited)








Three Months Ended



March 31,



2015


2014







Adjusted EBITDAX (see calculation and non-US GAAP reconciliation) (3)

$  24,465


$ 29,051


Adjusted Revenues (see non-US GAAP reconciliation)

$  37,124


$    49,072


Cash operating margin

66%


59%


 

SOURCE Goodrich Petroleum Corporation

For further information: Robert C. Turnham, President, Jan L. Schott, Chief Financial Officer, Daniel E. Jenkins, Director of Investor Relations, (713) 780-9494