Goodrich Petroleum Announces Third Quarter Financial and Operational Results
CASH FLOW: Adjusted EBITDAX for the quarter was a record $49.1 million, an increase of 75% from the prior year period and 12% sequentially, driven by increased oil volumes and lower operating costs. Discretionary cash flow was $39.0 million for the quarter, an increase of 17% sequentially.
CASH OPERATING MARGIN: Cash operating margin, defined as Adjusted EBITDAX divided by Adjusted Revenue, increased to 77% for the quarter from 64% for the prior year period. Adjusted Revenues, defined as revenues plus realized gain on derivatives not designated as hedges of $8.3 million for the quarter, were $63.8 million vs. $43.8 million for the prior year period. Revenues for the quarter were $55.5 million versus $37.4 million in the prior year period.
ADJUSTED OPERATING INCOME: Adjusted operating income, defined as revenues plus realized gain on derivatives not designated as hedges minus operating expenses, totaled $8.5 million for the quarter, a 5% sequential increase over the second quarter of 2011. Operating income totaled $0.2 million for the quarter
PRODUCTION: Production for the quarter increased by 27% from the prior year period and 3% sequentially from the second quarter of 2011 to an average of 116,200 Mcfe per day. Oil volumes grew sequentially by 50% to approximately 2,215 barrels of oil per day, which comprised approximately 11% of total production and 31% of total revenue
PRICE REALIZATIONS: The Company's oil-directed drilling strategy and increasing oil volumes resulted in increased realized prices on a per Mcfe basis. Average prices for the quarter prior to hedging effect were $4.05 per Mcf and $84.18 per barrel, or $5.20 per Mcfe. Prices benefited further from the Company's hedging strategy, with realized prices, including realized gains on derivatives, averaging $4.76 per Mcf and $92.19 per barrel, or $5.97 per Mcfe
CASH COST STRUCTURE LOWER: Per unit cash costs for the quarter, which includes lease operating, production and other taxes, transportation and general and administrative expenses, were lower by 26% versus the prior year period as follows:
-- Lease operating expense ("LOE") decreased by 31% from the prior year period and was flat sequentially to $0.51 per Mcfe;
-- Transportation expense decreased by 26% from the prior year period and increased 18% sequentially to $0.26 per Mcfe;
-- Production and other taxes increased to $0.15 per Mcfe from $0.08 per Mcfe from the prior year period and flat sequentially; and
-- General and administrative expense decreased 33% per Mcfe from the prior year period and decreased 18% sequentially to $0.58 per Mcfe.
RESERVES: The Company has received its mid-year reserve report, which had 492 Bcfe of proved reserves and was 44% developed using un-escalated SEC pricing of $4.21 per Mcf and $86.60 per barrel. The Company had total reserve additions of 53.5 Bcfe on $177.6 million of drilling and completion costs in the first half of 2011, which equates to 6.1% reserve growth over year-end 2010 and finding and development cost of $19.92 per BOE or $3.32 per Mcfe. Approximately 64% of drilling and completion capital expenditures in the first half of 2011 were associated with oil directed activity
BORROWING BASE INCREASE AND LIQUIDITY: The Company has received a $50 million increase in its borrowing base to $275 million and currently has borrowings of $79.5 million with $32.7 million of cash and cash equivalents and restricted cash, providing quarter-end liquidity of $228 million
CAPITAL EXPENDITURES: Capital expenditures for the quarter totaled $79.9 million and the Company expects capital expenditures of approximately $50 million in the fourth quarter
HEDGING: The Company incurred a gain on derivatives not designated as hedges of $26.5 million for the quarter, comprised of a realized gain of $8.3 million and an unrealized gain of $18.2 million. The Company had a net derivative asset of $41.8 million at September 20, 2011, which is comprised of a current asset of $44.8 million, a non-current asset of $6.8 million and a non-current liability of $9.8 million
OPERATIONAL UPDATE: The Company announced five Eagle Ford Shale wells with an average 24-hour peak production rate of 907 barrels of oil equivalent ("BOE") per day, two Buda Lime wells with an average 24-hour peak rate of 834 BOE per day and two Cotton Valley Taylor Sand wells with an average 24-hour peak rate of 7,854 Mcfe per day
HOUSTON, Nov. 3, 2011 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial and operating results for the quarter ended September 30, 2011.
CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX"), increased by 75% to $49.1 million for the quarter, compared to $28.1 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities). EBITDAX was 12% higher sequentially.
Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $39.0 million for the quarter, compared to $27.4 million in the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities). DCF increased by 17% sequentially.
NET INCOME
The Company announced net income applicable to common stock of $12.1 million for the quarter, or $0.34 per basic share, versus a net loss applicable to common stock of $226.6 million, or $6.31 per basic share in the prior year period. The prior year period was negatively affected by non-cash impairment expense of $234.9 million.
PRODUCTION
Net production volumes in the quarter increased by 27% to 10.7 billion cubic feet equivalent ("Bcfe"), or an average of 116,200 Mcfe per day, versus 8.4 Bcfe, or an average of approximately 91,700 Mcfe per day in the prior year period. Average net daily production volumes for the quarter were up 3% sequentially from the second quarter of 2011. Oil production increased by 518% over the prior year period and 50% sequentially to an average of 2,215 barrels of oil per day for the quarter.
Production is expected to average 108,000 – 112,000 Mcfe per day in the fourth quarter of 2011, due to an approximate 40% reduction in capital expenditures for the quarter, along with pipeline curtailment issues in the Eagle Ford Shale, which is expected to reduce volumes by approximately 5,000 Mcfe per day for the quarter. The curtailment is expected to be rectified in January of 2012. Oil production is expected to grow sequentially by 15 – 25% in the fourth quarter, or an average of 2,500 – 2,800 barrels of oil per day which would comprise approximately 13.5 – 15.5% of total volumes for the quarter.
Full year 2011 production guidance is confirmed at an average of 108,000 – 112,000 Mcfe per day, a 15 – 25% increase over 2010.
REVENUES
Revenues for the quarter were $55.5 million versus $37.4 million in the prior year period. Adjusted revenues, including realized gain on derivatives not designated as hedges of $8.3 million for the quarter, was $63.8 million (see accompanying table for a reconciliation of adjusted revenues, a non-GAAP measure, to revenues). Average realized price per unit for the quarter, prior to factoring in the Company's realized hedging gains, was $5.20 per Mcfe, versus $4.44 per Mcfe in the prior year period. When factoring in the Company's realized gains, average realized price per unit was $5.97 per Mcfe, versus $5.19 in the prior year period.
OPERATING EXPENSES
Lease operating expense ("LOE") per unit of production decreased by 31% to $5.4 million in the quarter, or $0.51 per Mcfe, versus $6.3 million, or $0.74 per Mcfe in the prior year period. Per unit LOE for the quarter was flat sequentially. Lower per unit LOE continued to be driven by the Company's Haynesville Shale wells, which comprised 64% of Company volumes and averaged $0.17 per Mcfe for the quarter. The Company expects LOE per unit to average $0.55 – $0.65 per Mcfe in the fourth quarter.
Production and other taxes for the quarter increased on a unit basis by 88% to $1.6 million, or $0.15 per Mcfe, versus $0.7 million, or $0.08 per Mcfe in the prior year period, with the increase driven by higher oil production and lower high cost credits for the quarter. Production and other taxes decreased by 6% sequentially on a unit basis.
Transportation expense on a unit basis decreased by 26% to $2.8 million, or $0.26 per Mcfe in the quarter, versus $3.0 million, or $0.35 per Mcfe in the prior year period. Transportation expense on a unit basis increased by 18% sequentially.
Depreciation, depletion and amortization ("DD&A") expense on a unit basis increased by 13% to $37.3 million, or $3.49 per Mcfe in the quarter, versus $26.0 million, or $3.09 per Mcfe in the prior year period. DD&A expense for the quarter on a unit basis increased by 16% sequentially due to higher production volumes coming from its Eagle Ford Shale trend, which provides higher cash margins from the associated oil production but carries a higher DD&A rate on a Mcfe basis.
Exploration expense on a unit basis decreased by 38% to $1.6 million, or $0.15 per Mcfe for the quarter, versus $2.0 million, or $0.24 per Mcfe in the prior year period. Exploration expense for the quarter on a unit basis decreased by 35% sequentially. Approximately $1.2 million ($0.11 per Mcfe), or 75% of exploration expense for the quarter, was non-cash expense associated with amortization of the Company's undeveloped leasehold.
General and Administrative ("G&A") expense on a unit basis decreased by 33% to $6.3 million, or $0.58 per Mcfe in the quarter, versus $7.3 million, or $0.86 Mcfe in the prior year period. Per unit G&A expense decreased by 18% sequentially. Of the total G&A expense for the quarter, $1.3 million ($0.13 per Mcfe), or 22% of the total, was non-cash expense associated with stock based compensation.
OPERATING INCOME
Operating income, defined as revenues minus operating expenses, totaled $0.2 million for the quarter versus an operating loss of $238.5 million for the prior year period. When adding in realized gain on derivatives not designated as hedges of $8.3 million, adjusted operating income for the quarter is $8.5 million (see accompanying table for a reconciliation of adjusted operating income, a non-GAAP measure, to operating income). Operating income from the prior year period was negatively affected by non-cash impairment.
OTHER INCOME (EXPENSE)
Interest expense for the quarter was $13.0 million, or $1.22 per Mcfe, versus $9.2 million, or $1.09 per Mcfe in the prior year period. Non-cash interest expense primarily associated with the Company's convertible notes comprised 27% of the total, or $3.5 million ($0.33 per Mcfe).
Gain (loss) on derivatives not designated as hedges for the quarter was $26.5 million, or $2.47 per Mcfe, versus a gain of $22.5 million, or $2.67 per Mcfe in the prior year period. The derivative gain for the quarter is comprised of a realized gain of $8.3 million and an unrealized gain of $18.2 million. The Company currently has a net derivative asset of $41.8 million.
LIQUIDITY
The Company ended the quarter with approximately $32.7 million in cash and cash equivalents and restricted cash, with $79.5 million drawn on its senior credit facility, under which the Company currently has a borrowing base of $275 million, providing $228 million of liquidity.
CAPITAL EXPENDITURES
Capital expenditures for the quarter were $79.9 million, of which $71.9 million was spent on drilling and completion costs, $1.0 million on acreage acquisitions, $5.8 million on facility costs and $1.2 million on other expenditures. For the quarter, the Company conducted drilling operations on 10 gross (8 net) wells, added 9 gross (5 net) wells to production and had 9 gross (5 net) wells waiting on completion at the end of the quarter. The Company added 9 gross (5 net) wells from the Eagle Ford Shale trend, with 4 gross (2.5 net) wells waiting on completion. The Company expects capital expenditures of approximately $50 million in the fourth quarter.
HEDGING
The Company has entered into new derivative contracts for 2,000 barrels of oil per day at an average swap price of $100.20 per barrel and 20,000 MMBtu per day of natural gas at $5.35 per Mcf for calendar year 2012. The Company now has 1,500 barrels of oil per day (68% of third quarter oil volumes) hedged for the fourth quarter of 2011 at a blended average price of $102.10, and 2,000 barrels of oil per day (90% of third quarter oil volumes) hedged for 2012 at a blended average price of $100.20. On natural gas, the Company has 40,000 MMBtu per day (39% of third quarter natural gas volumes) hedged for the fourth quarter of 2011 at a blended average floor price of $6.00 per Mcf, and 60,000 MMBtu per day (58% of third quarter natural gas volumes) hedged for 2012 at a blended average floor price of $5.78 per Mcf.
OPERATIONAL UPDATE
Texas
Eagle Ford Shale, LaSalle and Frio Counties, Texas
The Company completed the following five Eagle Ford Shale wells during the quarter, with an average 24-hour peak production rate of 907 BOE per day:
- Burns Ranch 20H (67% WI), a 5,960 foot lateral with 21 frac stages, at a 24-hour peak production rate of 1,080 barrels oil equivalent ("BOE") per day;
- Burns Ranch 2H (67% WI), an 8,320 foot lateral with 29 frac stages, at a 24-hour peak production rate of 1,004 BOE per day;
- Burns Ranch 3H (67% WI), a 5,160 foot lateral with 19 frac stages, at a 24-hour peak production rate of 953 BOE per day;
- Burns Ranch 18H (67% WI), a 5,060 foot lateral with 19 frac stages, at a 24-hour peak production rate of 883 BOE per day;
- Burns Ranch 19H (67% WI), a 5,940 foot lateral with 21 frac stages, at a 24-hour peak production rate of 613 BOE per day.
The Company completed two additional Buda Lime wells in the quarter:
- Carnes 7H (65% WI), an un-stimulated 4,215 foot lateral, at a 24-hour peak production rate of 1,167 BOE per day and a 30-day average of 871 BOE per day (762 BO and 655 Mcf per day);
- Burns Ranch 30H (67% WI), a 5,060 foot lateral with 19 frac stages, at a 24-hour peak production rate of 500 BOE per day.
The Company is in completion phase on the following wells:
- Burns Ranch 35H (67% WI), an 8,880 foot lateral with 32 planned frac stages;
- Burns Ranch 16H (67% WI), a 5,710 foot lateral with 20 planned frac stages;
- Burns Ranch 22H (67% WI), a 5,520 foot lateral with 20 planned frac stages;
- Shiner G-1 (67% WI), a 4,190 foot lateral in the Buda Lime;
- Shiner G-4 (67% WI), a 4,130 foot lateral in the Buda Lime;
Angelina River Trend, Nacogdoches and Angelina Counties, Texas
The Company is scheduled to spud its next well in the field, the ACLCO 1H (100% WI), late November, with an expected completion date in January.
Cotton Valley Taylor Sand, South Henderson Field, Rusk County, Texas
Since the end of the third quarter, the Company completed the following two Cotton Valley Taylor Sand wells at an average 7,854 Mcfe per day (15% oil/condensate):
Rayford – Siler No. 1H (100% WI), a 4,331 foot lateral with 13 frac stages, at a 24-hour peak production rate of 7,997 Mcfe per day, comprised of 6,943 Mcf and 176 barrels of oil per day;
Crow – Holland 1H (100% WI), a 5,011 foot lateral with 15 frac stages, at a 24-hour peak production rate of 7,712 Mcfe per day, comprised of 6,398 Mcf and 219 barrels of oil per day.
OTHER INFORMATION
In this press release, the Company refers to several non-GAAP financial measures, Adjusted EBITDAX, discretionary cash flow, cash operating margin, Adjusted Revenue and Adjusted Operating Income. We define Adjusted Revenues as revenues plus realized gain (or loss) on derivatives not designated as hedges. We define cash operating margin as Adjusted EBITDAX divided by Adjusted Revenues. A full reconciliation of Adjusted EBITDAX and discretionary cash flow to comparable GAAP measure is included with this release. .
Management believes that each of these measures is a good financial indicator of the Company's ability to internally generate operating funds. Management also believes that the two non-GAAP financial measures of cash flow, Adjusted EBITDAX and discretionary cash flow provide useful information to investors because they are widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. Non-GAAP financial measures should be reviewed in addition to, and not as an alternative for the Company's reported results prepared in accordance to GAAP.
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 and uncertainties, such as availability of drilling rigs and completion crews and equipment, financial market conditions, 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 and other 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. References to prior year periods in this release refer to the comparable quarterly period of the prior calendar year.
Initial production rates stated in this release are expected to differ substantially from longer term average production rates. “24-hour peak rate” mentioned in this press release is the highest 24-hour production rate for the referenced well. Forward looking estimates of production growth assume drilling results comparable to recent prior periods, which may not be realized. The Company is commencing its initial operations in the Eagle Ford Shale and the success of its drilling and completion strategy is subject to more uncertainty relative to areas where the Company has already established drilling and production history.
Goodrich Petroleum Corporation is an independent oil and gas exploration and production company listed on the New York Stock Exchange. Substantially all of its properties are located in Louisiana and Texas.
GOODRICH PETROLEUM CORPORATION |
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SELECTED INCOME AND PRODUCTION DATA |
|||||||||
(In Thousands, Except Per Share Amounts) |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
(As adjusted) |
(As adjusted) |
||||||||
Volumes |
|||||||||
Natural gas (MMcf) |
9,468 |
8,235 |
27,562 |
24,202 |
|||||
Oil liquids (MBbls) |
204 |
33 |
418 |
97 |
|||||
MMcfe - Total |
10,690 |
8,433 |
30,073 |
24,785 |
|||||
Mcfe per day |
116,200 |
91,665 |
110,157 |
90,786 |
|||||
Total Revenues |
$ 55,542 |
$ 37,424 |
$ 149,644 |
$ 112,041 |
|||||
Operating Expenses |
|||||||||
Lease operating expense |
5,447 |
6,280 |
15,565 |
19,841 |
|||||
Production and other taxes |
1,599 |
664 |
4,194 |
2,017 |
|||||
Transportation |
2,795 |
2,977 |
7,482 |
7,619 |
|||||
Depreciation, depletion and amortization |
37,348 |
26,022 |
93,234 |
84,638 |
|||||
Exploration |
1,638 |
2,033 |
6,379 |
7,639 |
|||||
Impairment |
142 |
234,887 |
1,192 |
234,887 |
|||||
General and administrative |
6,251 |
7,275 |
21,829 |
23,722 |
|||||
Gain on sale of assets |
- |
- |
(236) |
- |
|||||
Other |
146 |
(4,232) |
146 |
4,268 |
|||||
Operating income (loss) |
176 |
(238,482) |
(141) |
(272,590) |
|||||
Other income (expense) |
|||||||||
Interest expense |
(13,022) |
(9,154) |
(36,815) |
(27,469) |
|||||
Interest income and other |
21 |
11 |
43 |
117 |
|||||
Gain on derivatives not designated as hedges |
26,453 |
22,494 |
27,397 |
57,543 |
|||||
Gain from extinguishment of debt |
4 |
- |
62 |
- |
|||||
13,456 |
13,351 |
(9,313) |
30,191 |
||||||
Income (loss) before income taxes |
13,632 |
(225,131) |
(9,454) |
(242,399) |
|||||
Income tax benefit (expense) |
- |
- |
- |
- |
|||||
Net income (loss) |
13,632 |
(225,131) |
(9,454) |
(242,399) |
|||||
Preferred stock dividends |
1,511 |
1,511 |
4,535 |
4,535 |
|||||
Net income (loss) applicable to common stock |
$ 12,121 |
$ (226,642) |
$ (13,989) |
$ (246,934) |
|||||
Unrealized gain on derivatives not designated as hedges |
(18,163) |
(16,165) |
(5,995) |
(42,994) |
|||||
Other - Hoover Tree Farm ruling litigation |
146 |
(4,232) |
146 |
4,268 |
|||||
G&A - resignation of an officer of the company |
- |
- |
- |
867 |
|||||
G&A - additional 2009 bonus paid in March 2010 |
- |
- |
- |
875 |
|||||
Exploration - Angelina River Trend 3-D seismic |
- |
220 |
- |
1,100 |
|||||
Gain on sale of assets |
- |
- |
(236) |
- |
|||||
Gain on extinguishment of debt |
(4) |
- |
(62) |
- |
|||||
Impairment |
142 |
234,887 |
1,192 |
234,887 |
|||||
Adjusted net loss applicable to common stock (1) |
$ (5,758) |
$ (11,932) |
$ (18,944) |
$ (47,931) |
|||||
Discretionary cash flow (see non-GAAP reconciliation) (2) |
$ 39,002 |
$ 27,364 |
$ 99,083 |
$ 59,562 |
|||||
Adjusted EBITDAX (see calculation and non-GAAP reconciliation)( 3) |
$ 49,089 |
$ 28,064 |
$ 126,502 |
$ 78,887 |
|||||
Weighted average common shares outstanding - basic |
36,125 |
35,936 |
36,104 |
35,904 |
|||||
Weighted average common shares outstanding - diluted (4) |
36,297 |
35,936 |
36,104 |
35,904 |
|||||
Earnings per share |
|||||||||
Net income (loss) applicable to common stock - basic |
$ 0.34 |
$ (6.31) |
$ (0.39) |
$ (6.88) |
|||||
Net income (loss) applicable to common stock - diluted |
$ 0.33 |
$ (6.31) |
$ (0.39) |
$ (6.88) |
|||||
Adjusted earnings per share |
|||||||||
Adjusted net loss applicable to common stock - basic (1) |
$ (0.16) |
$ (0.33) |
$ (0.52) |
$ (1.33) |
|||||
Adjusted net loss applicable to common stock - fully diluted (1) |
$ (0.16) |
$ (0.33) |
$ (0.52) |
$ (1.33) |
|||||
(1) Adjusted net income 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 GAAP. |
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(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 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 (loss) on sale of assets, Gain on early extinguishment of debt and Other expense |
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(4) Fully diluted shares excludes approximately 11 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the year to date period ended September 30, 2011. 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. |
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GOODRICH PETROLEUM CORPORATION |
||||||||||
Per Unit Sales Prices and Costs |
||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||
September 30, |
September 30, |
|||||||||
2011 |
2010 |
2011 |
2010 |
|||||||
(As adjusted) |
(As adjusted) |
|||||||||
Average sales price per unit: |
||||||||||
Oil (per Bbl) |
||||||||||
Including realized gain on oil derivatives |
$ 92.19 |
$ 72.30 |
* |
$ 94.51 |
$ 73.85 |
* |
||||
Excluding realized gain on oil derivatives |
$ 84.18 |
$ 72.30 |
$ 89.65 |
$ 73.85 |
||||||
Natural gas (per Mcf) |
||||||||||
Including realized gain on natural gas derivatives |
$ 4.76 |
$ 5.03 |
$ 4.74 |
$ 4.98 |
||||||
Excluding realized gain on natural gas derivatives |
$ 4.05 |
$ 4.26 |
$ 4.04 |
$ 4.33 |
||||||
Natural gas and oil (per Mcfe) |
||||||||||
Including realized gain on oil and natural gas derivatives |
$ 5.97 |
$ 5.19 |
$ 5.66 |
$ 5.15 |
||||||
Excluding realized gain on oil and natural gas derivatives |
$ 5.20 |
$ 4.44 |
$ 4.95 |
$ 4.52 |
||||||
* |
No oil derivatives in the periods presented in 2010. |
|||||||||
Costs Per Mcfe |
||||||||||
Lease operating expense |
$ 0.51 |
$ 0.74 |
$ 0.52 |
$ 0.80 |
||||||
Production and other taxes |
$ 0.15 |
$ 0.08 |
$ 0.14 |
$ 0.08 |
||||||
Transportation |
$ 0.26 |
$ 0.35 |
$ 0.25 |
$ 0.31 |
||||||
Depreciation, depletion and amortization |
$ 3.49 |
$ 3.09 |
$ 3.10 |
$ 3.41 |
||||||
Exploration |
$ 0.15 |
$ 0.24 |
$ 0.21 |
$ 0.31 |
||||||
Impairment |
$ 0.01 |
$ 27.85 |
$ 0.04 |
$ 9.48 |
||||||
General and administrative |
$ 0.58 |
$ 0.86 |
$ 0.73 |
$ 0.96 |
||||||
Gain on sale of assets |
$ - |
$ - |
$ (0.01) |
$ - |
||||||
Other |
$ 0.01 |
$ (0.50) |
$ - |
$ 0.17 |
||||||
$ 5.18 |
$ 32.72 |
$ 4.98 |
$ 15.52 |
|||||||
Note: Amounts on a per Mcfe basis may not total due to rounding. |
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GOODRICH PETROLEUM CORPORATION |
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Selected Cash Flow Data (In Thousands): |
|||||||||
Reconciliation of Discretionary Cash Flow and Net Cash Provided by Operating Activities (unaudited) |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
Net cash provided by operating activities (GAAP) |
$ 42,016 |
$ 29,309 |
$ 109,937 |
$ 76,962 |
|||||
Net changes in working capital |
3,014 |
1,945 |
10,854 |
17,400 |
|||||
Discretionary cash flow |
$ 39,002 |
$ 27,364 |
$ 99,083 |
$ 59,562 |
|||||
Supplemental Balance Sheet Data |
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As of |
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September 30, |
December 31, |
||||||||
2011 |
2010 |
||||||||
(Unaudited) |
|||||||||
Cash and cash equivalents |
$ 3,441 |
$ 17,788 |
|||||||
Restricted cash |
29,286 |
4,232 |
|||||||
Current portion of debt |
24,837 |
167,086 |
|||||||
Long-term debt |
540,254 |
179,171 |
|||||||
$ 565,091 |
$ 346,257 |
||||||||
Reconciliation of Net income (loss) to Adjusted EBITDAX |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
(As adjusted) |
(As adjusted) |
||||||||
Net Income (loss) (GAAP) |
$ 13,632 |
$ (225,131) |
$ (9,454) |
$ (242,399) |
|||||
Exploration expense |
1,638 |
2,033 |
6,379 |
7,639 |
|||||
Depreciation, depletion and amortization |
37,348 |
26,022 |
93,234 |
84,638 |
|||||
Impairment |
142 |
234,887 |
1,192 |
234,887 |
|||||
Stock compensation expense |
1,349 |
1,507 |
4,526 |
5,496 |
|||||
Interest expense |
13,022 |
9,154 |
36,815 |
27,469 |
|||||
Unrealized gain on derivatives not designated as hedges |
(18,163) |
(16,165) |
(5,995) |
(42,994) |
|||||
Other excluded items * |
121 |
(4,243) |
(195) |
4,151 |
|||||
Adjusted EBITDAX |
$ 49,089 |
$ 28,064 |
$ 126,502 |
$ 78,887 |
|||||
* Other excluded items include Interest income and other, Gain (loss) on sale of assets, Gain on early extinguishment of debt and Other expense |
|||||||||
Other Information |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
Interest expense - cash |
$ 9,545 |
$ 4,407 |
$ 25,138 |
$ 13,227 |
|||||
Interest expense - noncash |
3,477 |
4,747 |
11,677 |
14,242 |
|||||
Total Interest |
13,022 |
9,154 |
36,815 |
27,469 |
|||||
Unrealized gain on derivatives not designated as hedges |
(18,163) |
(16,165) |
(5,995) |
(42,994) |
|||||
Realized gain on derivatives not designated as hedges |
(8,290) |
(6,329) |
(21,402) |
(14,549) |
|||||
Total gain on derivatives not designated as hedges |
(26,453) |
(22,494) |
(27,397) |
(57,543) |
|||||
General and Administrative expense - cash |
4,902 |
5,768 |
17,303 |
18,226 |
|||||
General and Administrative expense - noncash |
1,349 |
1,507 |
4,526 |
5,496 |
|||||
Total General and Administrative expense |
6,251 |
7,275 |
21,829 |
23,722 |
|||||
GOODRICH PETROLEUM CORPORATION |
|||||||||
Selected Cash Flow Data continued (In Thousands): |
|||||||||
Reconciliation of Adjusted Revenues and Total Revenues (unaudited) |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
Total Revenues (GAAP) |
$ 55,542 |
$ 37,424 |
$ 149,644 |
$ 112,041 |
|||||
Realized gain on derivatives not designated as hedges |
(8,290) |
(6,329) |
(21,402) |
(14,549) |
|||||
Adjusted Revenues |
$ 63,832 |
$ 43,753 |
$ 171,046 |
$ 126,590 |
|||||
Reconciliation of Adjusted Operating Income and Operating Income (unaudited) |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
Operating income (loss) (GAAP) |
$ 176 |
$ (238,482) |
$ (141) |
$ (272,590) |
|||||
Realized gain on derivatives not designated as hedges |
(8,290) |
(6,329) |
(21,402) |
(14,549) |
|||||
Adjusted Operating Income (loss) |
$ 8,466 |
$ (232,153) |
$ 21,261 |
$ (258,041) |
|||||
Calculation of Cash operating margin (unaudited) |
|||||||||
Three Months Ended |
Nine Months Ended |
||||||||
September 30, |
September 30, |
||||||||
2011 |
2010 |
2011 |
2010 |
||||||
Adjusted EBITDAX (see calculation and non-GAAP reconciliation) (3) |
$ 49,089 |
$ 28,064 |
$ 126,502 |
$ 78,887 |
|||||
Adjusted Revenues (see non-GAAP reconciliation) |
$ 63,832 |
$ 43,753 |
$ 171,046 |
$ 126,590 |
|||||
Cash operating margin |
77% |
64% |
74% |
62% |
|||||
SOURCE Goodrich Petroleum Corporation
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