Goodrich Petroleum Announces Second Quarter 2015 Financial Results And Operational Update

Aug 05, 2015, 07:00 ET from Goodrich Petroleum Corporation

HOUSTON, Aug. 5, 2015 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial results and an operational update for the second quarter ended June 30, 2015. 

HIGHLIGHTS:

  • Adjusted Revenues, which includes the benefit of realized gains on the Company's oil hedges, were $37.3 million for the quarter versus $50.2 million in the prior year period;
  • Operating Expenses were lower by $19.9 million in the quarter versus the prior year period and $0.5 million sequentially;
  • Earnings before interest, taxes, non-cash General & Administrative ("G&A") expenses and exploration ("Adjusted EBITDAX") was $24.8 million in the quarter, compared to $31.5 million in the prior year period;
  • Capital expenditures for the quarter totaled $17.1 million;
  • Production for the quarter totaled 758,000 barrels of oil equivalent ("Boe") (50% oil), which was affected by deferred completions. Natural gas production for the quarter versus the prior year period was negatively impacted by the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas;
  • Since the end of the quarter, the Company announced the agreement to sell its proved reserves and associated acreage in the Eagle Ford Shale for $118 million, subject to customary closing and post-closing adjustments. The transaction has an effective date of July 1, 2015 and is expected to close on or before September 4, 2015. The Company expects to book a gain of $50-60 million on the sale, pay off its bank revolver and retain the balance in cash from the sales proceeds.

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

TUSCALOOSA MARINE SHALE ("TMS"):

  • The Company has completed two additional wells on restricted chokes at an average rate of approximately 875 BOE (99% oil) per day;
  • Current well costs have been lowered to approximately $10.5 million on the most recent drilled and completed well (B-Nez 48H-2) due to reduced drilling days and lower service costs. Current bids are lower than the last well drilled, as two well pad costs now estimated at approximately $9.3 million per well.

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

Commenting on the quarter, the Company's Chairman of the Board and Chief Executive Officer Walter G. "Gil" Goodrich stated, "Since late 2014 and throughout 2015, we have undertaken a number of strategic initiatives designed to strengthen our balance sheet, enhance liquidity and reduce costs across our operations. With the previously announced sale of a portion of our Eagle Ford Shale acreage and associated proved reserves, we have taken another solid step toward enhancing our liquidity during the currently depressed crude oil market. Upon closing, we plan to pay off our senior credit facility in full and retain the balance in cash. With no debt maturities until October of 2017, this transaction improves our ability to execute our plans for 2016 while we continue to conserve capital and further improve our balance sheet. Service cost reductions and our team's diligent efforts are leading to reduced completed well costs, as our B-Nez 48H-2 came in at approximately $10.5 million for a 6,000' lateral and a 20-stage frac even though it was drilled in a higher cost environment."

FINANCIAL RESULTS

REVENUES

Revenues prior to realized gain on derivatives totaled $26.1 million in the quarter versus $53.3 million in the prior year period.  Average realized price per unit was $34.34 per Boe in the quarter versus $51.19 per Boe in the prior year period.  When factoring in the net cash received in settlement of derivative instruments, Adjusted Revenues totaled $37.3 million in the quarter versus $50.2 million in the prior year period, and average realized price per unit was $49.07 per Boe versus $48.23 per Boe in the prior year period. Revenues for the quarter were negatively impacted by the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas when compared to the previous 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 758,000 Boe in the quarter, or an average of 8,332 Boe per day, versus 1,041,000 Boe, or an average of 11,437 Boe per day, in the prior year period.  Oil production totaled 382,000 barrels of oil in the quarter (50% of total production), or an average of approximately 4,200 Bbls per day, which was flat to the prior year period. Oil production for the quarter was negatively impacted from the completion deferral of six wells in the TMS.  Natural gas production totaled 2.3 Bcf in the quarter, or an average of approximately 24,800 Mcf per day, versus 4.0 Bcf, or an average of 43,500 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 when compared to the previous year period.

CAPITAL EXPENDITURES

Capital expenditures totaled $17.1 million in the quarter, of which $14.1 million was spent on drilling and completion costs, $1.9 million on leasehold acquisition and $1.1 million on facilities, capital workovers and other expenditures.  While we booked capital expenditures of $17.1 million in the quarter, we paid out cash amounts totaling $23.1 million.  The Company estimates the vast majority of its negative change in working capital occurred in the first two quarters of the year.  Approximately 94% of the quarter's total capital expenditures were spent drilling and completing wells and extending leases for future drilling operations in the TMS. The Company currently has no rigs running in the TMS with three wells in early flow back, one well fracked but waiting on flow back to commence and two wells waiting on completion.  The Company anticipates capital expenditures between $15-20 million in the third quarter and reaffirms its full year preliminary capital budget of $90 – 110 million.

GUIDANCE

The Company previously issued full year 2015 production guidance of an average of 4,800 – 5,200 barrels of oil and 23,000 – 26,000 Mcf of natural gas per day. When factoring in the sale of the Eagle Ford Shale production and proved reserves, estimated to close September 4, 2015, as well as completion deferrals in the TMS, third quarter production is expected to average approximately 4,000 – 4,300 barrels per day and full year oil production is expected to be lower by 15 - 20% from previous guidance.  Natural gas production, when factoring in the sale of the Eagle Ford production and proved reserves, is expected to average approximately 20,500 – 22,500 Mcf per day in the third quarter and be lower by 10 - 15% for the year versus previous guidance.  

CASH FLOW

Adjusted EBITDAX was $24.8 million in the quarter, compared to $31.5 million in the prior year period. 

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $13.5 million in the quarter, compared to $18.4 million in the prior year period.  Net cash used in operating activities was $11.2 million in the quarter, compared to net cash provided by operating activities of $63.3 million in the prior year period.

DCF and Adjusted EBITDAX for the quarter were negatively impacted by completion deferrals and the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas when compared to the previous 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 $39.1 million in the quarter, or ($0.68) per basic share, versus a net loss applicable to common stock of $32.5 million, or ($0.73) per basic share in the prior year period.  Adjusted net loss applicable to common stock was $18.9  million for the quarter, or ($0.33) per basic share, versus an adjusted net loss applicable to common stock of $21.3 million, or ($0.48) per basic share in the prior year period. Net income for the quarter was negatively impacted by completion deferrals and the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas when compared to the previous 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

Operating expenses for the quarter were lower by $19.9 million (35%) than the prior year period, broken out as follows:

Lease operating expense ("LOE") was lower by $2.4 million to $4.9 million in the quarter, versus $7.3 million in the prior year period.  LOE for the quarter included $0.6 million for workovers, versus $1.4 million in the prior year period.  The decrease in LOE was primarily due to (i) field level cost cutting results; (ii) the divestment of our East Texas assets during the fourth quarter of 2014; and (iii) a reduction in workover activity in the Eagle Ford and Tuscaloosa Marine Shale trends.    

Production and other taxes were lower by $0.6 million to $1.4 million in the quarter versus $2.0 million 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 $0.7 million to $1.6 million in the quarter versus $2.3 million in the prior year period.  The decrease in transportation and processing expense pertains 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 $11.1 million to $19.0 million in the quarter versus $30.1 million 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 $4.1 million to $6.5 million in the quarter versus $2.4 million in the prior year period.  Non-cash lease expiration expense mostly for non-core acreage in the Eagle Ford and Tuscaloosa Marine Shale, represents 92% of total exploration expense in the quarter.

General and Administrative expense was lower by $3.0 million to $6.5 million in the quarter versus $9.5 million in the prior year period.  G&A expense related to non-cash, stock based compensation totaled $1.9 million in the quarter versus $2.3 million in the prior year period.  G&A was lower versus the prior year period primarily due to the Company's cost cutting efforts and staff reductions. 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 $10.9 million in the quarter, versus an operating loss of $3.6 million in the prior year period.  Adjusted operating income, when adjusted for cash received in settlement of derivative instruments of $11.2 million, was a gain of $0.3 million for the quarter.  Operating income for the quarter was negatively impacted by completion deferrals and the Company's sale in December 2014 of its non-core, Beckville/Minden field in East Texas when compared to the previous year period.

(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 $14.8 million in the quarter versus $11.8 million in the prior year period.  Non-cash interest expense associated with the Company's debt totaled $3.7 million (representing 25% of total interest expense) in the quarter versus $2.7 million in the prior year period.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company had a non-cash loss of $6.0 million on its derivatives not designated as hedges in the quarter, versus a loss of $9.8 million during the prior year period.  The company received net cash receipts and realized a gain of $11.2 million this quarter for the settlement of our oil derivatives.  For 2015, the Company has a total of 3,500 Bbls/day (85% at the midpoint of revised 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 $85.7 million with a borrowing base of $150 million.  The Company expects to use net proceeds from the sale of properties in the Eagle Ford Shale to pay down borrowings on the revolver to zero with remaining cash on hand.  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 $25-35 million from cash flow from operations, cash on hand, proceeds from asset sales, and available capacity on its senior credit facility, if necessary. 

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 1.0 gross (0.7 net) TMS wells.  A total of 2.0 gross (1.4 net) wells were added to production during the quarter. As of June 30, 2015, the Company had 4.0 gross (3.4 net) TMS wells drilled and waiting on completion in the TMS.

Tuscaloosa Marine Shale:

The Company has completed on restricted chokes, its B-Nez 43H-1 (70% WI) and B-Nez 43H-2 (74% WI) wells in Tangipahoa Parish, Louisiana at an average production rate of 875 BOE (99% oil) per day. The wells produced at similar rates and averaged 6,250 feet of lateral and 20.5 stages. The Company has also fracked its Kinchen 58H-1 (78% WI) well in Tangipahoa Parish, Louisiana, a 6,000 foot lateral with 20 stages, and its T. Lewis 7-38H-1 (91% WI) well in Amite County, Mississippi, a 5,400 foot lateral with 20 stages. The Kinchen well is in early flow back and the T. Lewis is expected to commence flow back within a week. The Company expects to complete its Painter et al 5H-1 (73% WI) well in Tangipahoa Parish, Louisiana and Alford 10H-1 (100% WI) well in Washington Parish, Louisiana early in the fourth quarter in anticipation of better crude oil pricing. The Company currently has no rigs running in the play but expects to commence drilling operations in early 2016 assuming acceptable crude oil prices.

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

Eagle Ford Shale

As previously reported, the Company has entered into a definitive agreement to sell its proved reserves and associated acreage for $118 million, with an effective date of July 1, 2015 and expected closing date on or before September 4, 2015. The Company will use the proceeds to pay off its bank revolver balance and keep the remainder in cash on the balance sheet.  The Company expects to book a gain of $50-60 million on the sale.

The Company is maintaining 17,000 net acres or 58% of its prior leasehold for future development or sale. The vast majority of the retained leasehold has approximately four years of term remaining, and the Company projects approximately 150 potential drilling locations.

Haynesville Shale – Angelina River Trend

As previously announced, the Company completed its ACLCO No. 2H (100% WI) well in Angelina County, Texas in the first quarter. The  well has experienced very little decline over its initial five month period, averaging and currently producing approximately 5,800 Mcf per day on a 12/64 inch choke with 10,750 psi, which is 400 psi of drawdown since peak rate.  The Company intends to keep the well choked back to continue to minimize drawdown and maximize its EUR.

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

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Volumes

Natural gas (MMcf)

2,259

3,957

4,330

8,388

Oil and condensate (MBbls)

382

381

817

722

MBoe - Total

758

1,041

1,539

2,120

Boe per day

8,332

11,437

8,501

11,713

Total Revenues

$  26,101

$  53,319

$  50,131

$ 105,122

Operating Expenses

Lease operating expense

4,942

7,312

9,080

15,929

Production and other taxes

1,378

1,983

2,787

4,424

Transportation and processing

1,608

2,339

2,855

4,711

Depreciation, depletion and amortization

19,000

30,076

39,233

59,314

Exploration

6,462

2,350

10,120

4,667

General and administrative

6,459

9,454

14,210

18,395

Gain on sale of assets

(2,869)

-

(3,761)

-

Other

-

3,357

(45)

3,357

Operating  loss

(10,879)

(3,552)

(24,348)

(5,675)

Other income (expense)

Interest expense

(14,785)

(11,751)

(26,864)

(23,629)

Interest income and other

-

10

-

20

Loss on derivatives not designated as hedges

(5,974)

(9,813)

(1,544)

(18,314)

(20,759)

(21,554)

(28,408)

(41,923)

Loss before income taxes

(31,638)

(25,106)

(52,756)

(47,598)

Income tax benefit 

-

-

-

-

Net loss  

(31,638)

(25,106)

(52,756)

(47,598)

Preferred stock dividends

7,430

7,430

14,861

14,861

Net loss applicable to common stock

$ (39,068)

$ (32,536)

$ (67,617)

$  (62,459)

Loss on derivatives not designated as hedges

5,974

9,813

1,544

18,314

Net cash received (paid) in settlement of derivative instruments

11,168

(3,079)

24,262

(5,810)

Lease expirations

5,928

1,142

7,880

2,373

Dry hole cost

(52)

-

(43)

44

Gain on sale of assets

(2,869)

-

(3,761)

-

Other

-

3,357

(45)

3,357

Adjusted net loss applicable to common stock (1)

$ (18,919)

$ (21,303)

$ (37,780)

$  (44,181)

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

$  13,471

$  18,384

$  26,862

$   37,783

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

$  24,823

$  31,450

$  49,288

$   60,501

Weighted average common shares outstanding - basic

57,280

44,308

53,218

44,290

Weighted average common shares outstanding - diluted (4)

57,280

44,308

53,218

44,290

Earnings per share

Net loss applicable to common stock - basic

$     (0.68)

$     (0.73)

$     (1.27)

$      (1.41)

Net loss applicable to common stock - diluted

$     (0.68)

$     (0.73)

$     (1.27)

$      (1.41)

Adjusted earnings per share

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

$     (0.33)

$     (0.48)

$     (0.71)

$      (1.00)

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

$     (0.33)

$     (0.48)

$     (0.71)

$      (1.00)

 

(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 15.7 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the three months and six months ended June 30, 2015.  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

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Average sales price per unit:

Oil (per Bbl)

     Including net cash received/paid to settle oil derivatives 

$ 86.49

$   91.23

$ 80.87

$   91.28

     Excluding net cash received/paid to settle oil derivatives

$ 57.23

$ 100.48

$ 51.17

$   99.44

Natural gas (per Mcf)

     Including net cash received/paid to settle natural gas derivatives

$   1.86

$      3.89

$   1.93

$      3.97

     Excluding net cash received/paid to settle natural gas derivatives

$   1.86

$      3.78

$   1.93

$      3.97

Oil and natural gas (per Boe)

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

$ 49.07

$   48.23

$ 48.38

$   46.82

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

$ 34.34

$   51.19

$ 32.61

$   49.56

Costs Per Boe

Lease operating expense

$    6.52

$      7.03

$     5.90

$      7.51

Production and other taxes

$    1.82

$      1.91

$     1.81

$      2.09

Transportation and processing

$    2.12

$      2.25

$     1.86

$      2.22

Depreciation, depletion and amortization

$  25.06

$    28.90

$   25.50

$    27.98

Exploration

$    8.52

$      2.26

$     6.58

$      2.20

General and administrative

$    8.52

$      9.08

$     9.24

$      8.68

Gain on sale of assets

$  (3.78)

$            -

$   (2.44)

$            -

Other

$          -

$      3.23

$   (0.03)

$      1.58

$  48.79

$    54.66

$   48.39

$    52.26

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

Six Month Ended

June 30,

June 30,

2015

2014

2015

2014

Net cash (used in) provided by operating activities (US GAAP)

(11,229)

$       63,291

$   (5,512)

$  69,846

Net changes in working capital

24,700

(44,907)

32,374

(32,063)

Discretionary cash flow

$  13,471

$       18,384

$  26,862

$  37,783

Weighted average common shares outstanding - basic

57,280

44,308

53,218

44,290

Weighted average common shares outstanding - diluted (4)

57,280

44,308

53,218

44,290

Supplemental Balance Sheet Data

As of

June 30

December 31

2015

2014

Cash and cash equivalents

$        348

$                 8

Long-term debt

622,403

568,625

Reconciliation of Net loss to Adjusted EBITDAX

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Net loss (US GAAP)

$ (31,638)

$     (25,106)

$ (52,756)

$ (47,598)

Exploration expense

6,462

2,350

10,120

4,667

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

19,000

30,076

39,233

59,314

Stock compensation expense

1,941

2,298

3,827

4,648

Interest expense 

14,785

11,751

26,864

23,629

Loss on derivatives not designated as hedges

5,974

9,813

1,544

18,314

Net cash received (paid) in settlement of derivative instruments

11,168

(3,079)

24,262

(5,810)

Other excluded items *

(2,869)

3,347

(3,806)

3,337

      Adjusted EBITDAX

$  24,823

$       31,450

$  49,288

$  60,501

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

Other Information

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Interest expense - cash

$  11,066

$         9,084

$  21,053

$  18,330

Interest expense - noncash

3,719

2,667

5,811

5,299

Total Interest

$  14,785

$       11,751

$  26,864

$  23,629

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

$  17,142

6,734

$  25,806

$  12,504

Net cash (received) paid in settlement of derivative instruments

(11,168)

3,079

(24,262)

5,810

Loss on derivatives not designated as hedges

$     5,974

$         9,813

$     1,544

$  18,314

General and Administrative expense - cash

$     4,518

7,156

$  10,383

$  13,747

General and Administrative expense - noncash

1,941

2,298

3,827

4,648

Total General and Administrative expense

$     6,459

$         9,454

$  14,210

$  18,395

 

GOODRICH PETROLEUM CORPORATION

Selected Cash Flow Data continued (In Thousands):

Reconciliation of Adjusted Revenues and Total Revenues (unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Total Revenues (US GAAP)

$  26,101

$ 53,319

$  50,131

$ 105,122

Net cash received (paid) in settlement of derivative instruments

11,168

(3,079)

24,262

(5,810)

Adjusted Revenues

$  37,269

$    50,240

$  74,393

$   99,312

Reconciliation of Adjusted Operating Income and Operating Income (unaudited)

Three Months Ended

Year Ended

June 30,

June 30,

2015

2014

2015

2014

Operating loss (US GAAP)

$ (10,879)

$  (3,552)

$ (24,348)

$    (5,675)

Net cash received (paid) in settlement of derivative instruments

11,168

(3,079)

24,262

(5,810)

Adjusted Operating  gain (loss)

$        289

$     (6,631)

$         (86)

$  (11,485)

Calculation of Cash operating margin (unaudited)

Three Months Ended

Year Ended

June 30,

June 30,

2015

2014

2015

2014

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

$  24,823

$ 31,450

$  49,288

$   60,501

Adjusted Revenues (see non-US GAAP reconciliation)

$  37,269

$    50,240

$  74,393

$   99,312

Cash operating margin

67%

63%

66%

61%

 

SOURCE Goodrich Petroleum Corporation



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