Goodrich Petroleum Announces First Quarter 2014 Financial Results And Operational Update

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:

  • 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;
  • 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;
  • 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. 

TUSCALOOSA MARINE SHALE ("TMS"):

  • 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 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;
  • 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 plans to frac both wells in 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 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 as hedges


5,770


2,104




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 reconciliation) (2)


$  19,399


$  16,320












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

$  29,051


$  27,050











Weighted average common shares outstanding - basic


44,273


36,684



Weighted average common shares outstanding - diluted (4)


44,273


36,684











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 - basic (1)


$     (0.54)


$     (0.76)




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


$     (0.54)


$     (0.76)















(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 derivatives 


$      91.34


$    107.52







     Excluding realized on oil derivatives


$      98.27


$    107.02







Natural gas (per Mcf)











     Including realized natural gas derivatives


$         4.05


$         3.40







     Excluding realized natural gas derivatives


$         4.13


$         3.40







Natural gas and oil (per Mcfe)











     Including realized oil and natural gas derivatives


$         7.58


$         7.88







     Excluding realized oil and natural gas derivatives


$         8.00


$         7.85




























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 amortization


$         4.51


$         5.84







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 (GAAP)

$     6,555


$          6,272



Net changes in working capital

12,844


10,048



Discretionary cash flow

$  19,399


$        16,320










Weighted average common shares outstanding - basic

44,273


36,684



Weighted average common shares outstanding - diluted (4)

44,273


36,684










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 designated as hedges

5,770


2,104




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 designated as hedges

5,770


2,104




Realized (gain) loss on derivatives not designated as hedges

2,731


(152)




Total loss on derivatives not designated as hedges

8,501


1,952











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 as hedges

(2,731)


152



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 designated as hedges

(2,731)


152



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 reconciliation) (3)

$   29,051


$   27,050



Adjusted Revenues (see non-GAAP reconciliation)

$   49,072


$   47,236



Cash operating margin

59%


57%


 

SOURCE Goodrich Petroleum Corporation



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