Exhibit 99.1
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NEWS from 
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801 Louisiana Street, Suite 700
Houston, Texas 77002
Main: (713) 780-9494
Fax: (713) 780-9254
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| Contact: | | |
| Robert C. Turnham, Jr., President | | Traded: NYSE (GDP) |
| David R. Looney, Chief Financial Officer | | |
FOR IMMEDIATE RELEASE
GOODRICH PETROLEUM ANNOUNCES THIRD QUARTER
FINANCIAL AND OPERATIONAL RESULTS AND GUIDANCE
| | • | | Net Production Volumes Averaged 82,500 Mcfe Per Day for the Quarter, Representing Slight Sequential Growth and 20% Growth Over the Prior Year Period. |
| | • | | Haynesville Shale Volumes Grew by 50% Sequentially to a Total of 30% of Company Volumes |
| | • | | Capital Expenditures Totaled $41.0 Million for the Quarter, down 37% Sequentially and 60% from the Prior Year Period |
| | • | | Company Exits the Quarter with $131.5 Million in Cash and Zero Borrowings Outstanding Under Its Bank Revolving Credit Facility |
| | • | | Lifting Costs (Lease Operating Expenses, Production and Other Taxes and Transportation) Reduced by 27% From Prior Year Period to $1.44 Per Mcfe |
Houston, Texas – November 4, 2009. Goodrich Petroleum Corporation today announced its financial and operating results for the third quarter ended September 30, 2009.
PRODUCTION
Net production volumes in the third quarter of 2009 increased by approximately 20% to 7.6 billion cubic feet equivalent (“Bcfe”), or an average of approximately 82,500 Mcfe per day, versus 6.3 Bcfe, or an average of approximately 68,800 Mcfe per day in the third quarter of 2008. Average net daily production volumes for the third quarter were up slightly from the second quarter of 2009, with Haynesville Shale volumes growing by 50% sequentially to comprise 30% of Company volumes for the quarter.
The Company currently expects drilling and completion capital expenditures of $35.0 – $40.0 million and net daily production volumes to average between 82,000 and 85,000 Mcfe per day for the fourth quarter of 2009.
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NET INCOME
Net income applicable to common stock for the quarter was a loss of $31.0 million ($(0.87) per basic and diluted share) versus net income applicable to common stock of $184.8 million ($5.21 per basic and $4.47 per diluted share) for the third quarter of 2008, as the prior year period included both a $145.9 million gain on sale of undeveloped leasehold rights in North Louisiana and an $83.5 million gain on derivatives not designated as hedges. Net loss for the third quarter of 2009 included a $1.5 million pre-tax loss on derivatives not designated as hedges, which was comprised of a $27.6 million pre-tax realized gain on settled gas derivative contracts during the quarter, offset by a $28.9 million pre-tax unrealized loss resulting primarily from the expiration of those contracts during the quarter, and a $0.2 million pre-tax loss on interest rate swaps.
CASH FLOW.
Earnings before interest, taxes, DD&A and exploration (“EBITDAX”) for the quarter, was $34.5 million compared to $41.1 million in the third quarter of 2008, which excludes the $146.0 million gain on the sale of undeveloped leasehold rights (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities). EBITDAX for the quarter was negatively impacted by a 68% drop in natural gas prices versus the prior year period.
Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital was $30.4 million in the quarter compared to $26.0 million for the third quarter of 2008, excluding the $146.0 million gain on the sale of undeveloped leasehold rights (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities). Net cash provided by operating activities was $16.9 million for the third quarter of 2009 compared to $41.1 million in the third quarter of 2008, as the Company’s reduced drilling activity in 2009 continued to result in the unwinding of working capital financing evidenced by a sizable reduction in accounts payable of $15.8 million during the quarter.
REVENUES
Total revenues for the quarter, which do not include realized gains of $27.6 million on natural gas derivatives not designated as hedges, was $23.5 million, versus $60.4 million for the prior year period. Average net natural gas and oil prices received in the third quarter of 2009 were $2.89 per Mcf and $64.43 per barrel (“Bbl”), down 68% and 45% respectively from $9.14 per Mcf and $117.65 per Bbl in the prior year period. On a Mcfe basis, the blended price was $3.11 per Mcfe in the quarter versus $9.54 per Mcfe in the prior year period. Total revenues and average prices received in the quarter do not include realized gains of $27.6 million received on the Company’s settled natural gas derivatives, none of which were designated as hedges.
OPERATING INCOME
Operating income (loss) (defined as revenues less lease operating expenses, production taxes, transportation, DD&A, exploration and general and administrative expenses), was a loss of $37.7 million for the quarter, versus income of $158.0 million for the prior year period, which includes the $146.0 million gain on sale of certain deep interests in North Louisiana. The primary reason for the significant decrease in operating income from the prior year period was largely the result of the gain on sale recognized in the prior period and the decreased prices mentioned above, as well as an increase in non-cash expenses detailed below.
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OPERATING EXPENSES
Lease operating expenses (LOE) totaled $7.4 million in the quarter, or $0.97 per Mcfe of production, versus $8.2 million, or $1.29 per Mcfe for the prior year period. For the second consecutive quarter, LOE per Mcfe was down 25% from the prior year period, reflecting the significant strides the Company has made in the areas of salt water disposal (SWD) and compression costs. Additionally, the continuing impact of the Haynesville Shale production volumes were apparent in the quarter, as the per unit rate of LOE from the Haynesville Shale production is significantly less than our historical LOE rate.
General and administrative (G&A) expenses totaled $6.8 million for the quarter, or $0.90 per Mcfe, versus $6.2 million, or $0.98 per Mcfe, during the prior year period. G&A expenses were down on a per unit basis over the prior year period as the Company grew production volumes faster than the rate of increase of G&A. Additionally, G&A expenses were essentially flat from the second quarter of 2009 on both an absolute basis ($6.7 million in the second quarter) and a per unit basis ($0.90 in the second quarter). Included in G&A expenses, the Company recorded a non-cash expense related to stock based compensation for its officers, employees and directors of $1.5 million during the quarter, which was up slightly from the prior year period.
Production and other taxes, which are tied directly to oil and natural gas price levels, were $1.3 million, or $0.17 per Mcfe, in the quarter versus $2.1 million, or $0.33 per Mcfe in the prior year period. On a per unit basis, both transportation expenses and exploration expenses were down meaningfully from the prior year period as transportation expense fell from $0.35 per Mcfe in the prior year period to $0.30 per Mcfe in the quarter, while exploration expense decreased from $0.33 per Mcfe in the prior year period to $0.21 per Mcfe in the quarter. Both of these expense categories are reflective of the Company’s ongoing efforts to rationalize production transportation agreements and improve efficiencies throughout the organization.
Depreciation, depletion and amortization (“DD&A”) expense.The Company utilizes the successful efforts method of accounting, whereby the majority of DD&A expense is represented by capitalized drilling and completion costs divided by proved developed reserves only, based on the most recent reserve report available to the Company. We calculated the DD&A rate for the three month period ended September 30, 2009 using an internally generated reserve report dated June 30, 2009, with a NYMEX gas price of $3.88 per MMbtu, down from $5.71 per MMbtu at December 31, 2008. While this internal reserve report was prepared in accordance with existing SEC guidelines, it should not be construed as a fully independent engineering reserve report similar to what we have used in the past and what we envision using at year end. As a result of the impact of lower natural gas prices on our traditional Cotton Valley Trend reserves, which are predominately associated with vertical wells and represent 90% of our proved reserves at June 30, 2009, the DD&A rate utilized for the three month period ended September 30, 2009 increased to $5.54 per Mcfe versus $4.17 per Mcfe in the three month period ended September 30, 2008. Similarly, the higher rate for the third quarter resulted in the DD&A rate for the nine month period ended September 30, 2009 being $5.13 per Mcfe, a 13% increase from the nine month period ended September 30, 2008.
INTEREST EXPENSE
Interest expense increased to $6.6 million in the quarter from $5.5 million in the prior year period, due primarily to approximately $1.3 million of additional interest expense booked in conjunction with the early
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termination of our second lien term loan, which was fully repaid on September 29, 2009. Of the total $6.6 million in interest expense during the quarter, only approximately $2.9 million represents ongoing cash interest expense due to our contractual debt obligations. In addition to the early termination charges referenced above, approximately $2.4 million represented non-cash charges related to the amortization of deferred financing costs and debt discounts booked in accordance with current accounting guidance.
LIQUIDITY
In late September, the Company issued new convertible senior notes totaling $218.5 million, the proceeds of which were used to fully prepay the $75.0 million second lien term loan and $5.0 million in outstanding borrowings under the Company’s senior bank credit facility. As such, the Company exited the quarter with approximately $131.5 million in cash and short term investments and nothing drawn on its senior credit facility, with a borrowing base of $175.0 million.
CAPITAL EXPENDITURES
The Company conducted drilling and/or completion operations on twelve gross (six net) horizontal wells in the quarter with a 100% success rate. Capital expenditures for the quarter totaled $41.0 million, down approximately 60% from the prior year period, which was $103.0 million. Of the $41.0 million in capital expenditures for the quarter, approximately $37.8 million, or 92% of the total was associated with the drilling and/or completion of 15 gross wells, versus $87.4 million expended for drilling and completion of 38 gross wells during the prior year period. Additionally, in the current quarter, approximately $1.4 million was spent on leasehold acquisitions, and approximately $2.0 million was associated with seismic and other development costs.
OPERATIONAL UPDATE
DRILLING
During the quarter, the Company conducted drilling operations on twelve gross Cotton Valley trend wells, all of which targeted the Haynesville Shale. During the same period, the Company reached total depth on nine gross wells and added eight gross (five net) wells to production. All of the wells added to production in the quarter produced from the Haynesville Shale.
CORE PROPERTIES
Louisiana
Bethany-Longstreet Field, Caddo and DeSoto Parishes, Louisiana. In the Bethany Longstreet field, the Company conducted drilling operations on nine gross Haynesville Shale horizontal wells during the quarter. In addition, the Company conducted completion operations on seven gross and added a total of three gross (1.2 net) wells to production during the quarter.
The Company has completed its initial operated well in the field, the Goodrich Petroleum Company – Plants 26 H-1 (36% WI), at a 24-hour peak rate of 15,300 Mcfe per day on a 22/64 inch choke with 7,000 psi. The Company is currently in completion phase on its second well operated in the field, the Garland 25 H-1 (37% WI), and drilling its third operated well, the Fallon 18 H-1 (57% WI).
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The Company has also participated in the completion of three Chesapeake operated wells in the field. The Hunsicker 13 H-1 (50% WI) was completed at a 24-hour peak rate of 14,300 Mcfe per day on a 20/64 inch choke with 7,900 psi. The Bray 34 H-1 (21% WI) was completed at a 24-hour peak rate of 15,400 Mcfe per day on a 22/64 inch choke with 7,400 psi, and the Caddo Parish 30 H-1 (25% WI) was completed at a 24-hour peak rate of 12,950 Mcfe per day on a 22/64 inch choke with 7,200 psi.
To date, the Company has completed and added to production a total of fourteen gross Haynesville horizontal wells in the Bethany Longstreet field with an average initial production rate of 14,300 Mcfe per day.
The Company is currently running two operated and two non-operated rigs in Northwest Louisiana.
Texas
Beckville and Minden Fields, Panola and Rusk Counties, Texas. During the quarter, the Company conducted drilling operations on and completed two horizontal wells in the field, both of which have previously been announced (T. Swiley 4H and Beard Taylor 1H). The Company has completed the drilling of its Billy Harris 1H, a horizontal Haynesville Shale well with a lateral of 5,200 feet, and anticipates completing the well, along with two previously deferred Cotton Valley Taylor sand horizontals in the fourth quarter.
Management Comments
Commenting on the third quarter results, W. “Gil” Goodrich, Vice Chairman and CEO said, “Despite the fact that we dramatically reduced our level of activity and capital expenditures during the quarter, we maintained and actually grew production volumes slightly on a sequential basis. Capital expenditures were down 37% sequentially as we both reduced our rig count and focused our activities on the development of the Haynesville Shale. Our focus on the Haynesville Shale is again paying dividends, as our production from the Haynesville Shale grew 50% sequentially over the second quarter to an average of approximately 25,000 Mcfe per day or 30% of Company volumes during the quarter. In East Texas, our two initial Cotton Valley (Taylor Sand) horizontal wells in the N. Minden and Beckville fields have both now been online for approximately six months and are exhibiting flatter decline curves, and continue to exceed our expectations. We will continue to allocate a portion of our 2010 budget to additional Cotton Valley (Taylor Sand) horizontal drilling at both Beckville and Minden, as well as South Henderson in Rusk County. We are also very pleased with the results of our initial operated Haynesville Shale horizontal wells in northwest Louisiana, with the Trosper 2H-1 in the Greenwood-Waskom area testing at 11,700 Mcf per day and the Plants 26H-1 in the Bethany-Longstreet field testing at 15,300 Mcf per day. During the quarter, we realized approximately $27.6 million in cash from the settlement of our natural gas hedges, which was not included in reported revenues of $23.5 million. As a result, we had another strong quarter with approximately $34.5 million of EBITDAX and $30.4 million of discretionary cash flow. Finally, with the completion of our successful convertible notes offering in September, our liquidity remains very strong with $131.5 million in cash and short term investments on our balance sheet as we exited the third quarter and no borrowings under our bank revolving credit facility which currently has a borrowing base of $175.0 million.”
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OTHER INFORMATION
In this press release, the Company refers to two non-GAAP financial measures, EBITDAX and discretionary cash flow. 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 these non-GAAP financial measures of 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. Neither discretionary cash flow nor EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by 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, such as 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.
Initial production rates stated in this release are expected to differ substantially from longer term average production rates. Forward looking estimates of production growth assume drilling results comparable to recent prior periods, which may not be realized.
Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange. The majority of its properties are in Louisiana and Texas.
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GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | | | (as adjusted) | | | | | | (as adjusted) | |
Total Revenues | | $ | 23,525 | | | $ | 60,376 | | | $ | 78,249 | | | $ | 171,902 | |
| | | | |
Operating Expenses | | | | | | | | | | | | | | | | |
Lease operating expense | | | 7,363 | | | | 8,165 | | | | 23,343 | | | | 22,931 | |
Production and other taxes | | | 1,294 | | | | 2,110 | | | | 3,831 | | | | 5,699 | |
Transportation | | | 2,300 | | | | 2,224 | | | | 7,479 | | | | 6,480 | |
Depreciation, depletion and amortization | | | 42,063 | | | | 26,414 | | | | 112,258 | | | | 80,532 | |
Exploration | | | 1,625 | | | | 2,062 | | | | 6,804 | | | | 5,841 | |
Impairment of oil and gas properties | | | - | | | | 1,059 | | | | 23,490 | | | | 1,059 | |
General and administrative | | | 6,802 | | | | 6,207 | | | | 20,572 | | | | 17,567 | |
Gain on sale of assets | | | (182 | ) | | | (145,868 | ) | | | (295 | ) | | | (145,868 | ) |
| | | | |
Operating income (loss) | | | (37,740 | ) | | | 158,003 | | | | (119,233 | ) | | | 177,661 | |
| | | | |
Other income (expense) | | | | | | | | | | | | | | | | |
Interest expense | | | (6,646 | ) | | | (5,524 | ) | | | (17,152 | ) | | | (16,971 | ) |
Interest income | | | 4 | | | | 1,260 | | | | 387 | | | | 1,260 | |
Gain (Loss) on derivatives not designated as hedges | | | (1,545 | ) | | | 83,477 | | | | 38,017 | | | | 10,043 | |
| | | | |
| | | (8,187 | ) | | | 79,213 | | | | 21,252 | | | | (5,668 | ) |
| | | | |
Income (loss) from continuing operations before income taxes | | | (45,927 | ) | | | 237,216 | | | | (97,981 | ) | | | 171,993 | |
Income tax (expense) benefit | | | 16,394 | | | | (50,618 | ) | | | 36,545 | | | | (50,618 | ) |
Income (loss) from continuing operations | | | (29,533 | ) | | | 186,598 | | | | (61,436 | ) | | | 121,375 | |
| | | | |
Discontinued operations: | | | | | | | | | | | | | | | | |
Gain (loss) on sale assets net of tax | | | - | | | | (252 | ) | | | - | | | | 28 | |
Income (loss) from discontinued operations, net of tax | | | 14 | | | | (44 | ) | | | 79 | | | | 240 | |
| | | 14 | | | | (296 | ) | | | 79 | | | | 268 | |
| | | | |
Net income (loss) | | | (29,519 | ) | | | 186,302 | | | | (61,357 | ) | | | 121,643 | |
Preferred stock dividends | | | 1,512 | | | | 1,512 | | | | 4,536 | | | | 4,535 | |
| | | | |
Income (loss) applicable to common stock | | $ | (31,031 | ) | | $ | 184,790 | | | $ | (65,893 | ) | | $ | 117,108 | |
| | | | |
INCOME (LOSS) PER COMMON SHARE- BASIC: | | | | | | | | | | | | | | | | |
From continuing operations | | $ | (0.87 | ) | | $ | 5.22 | | | $ | (1.84 | ) | | $ | 3.53 | |
From discontinued operations | | $ | - | | | $ | (0.01 | ) | | $ | - | | | $ | 0.01 | |
| | | | | | | | | | | | | | | | |
Income (loss) applicable to common stock | | $ | (0.87 | ) | | $ | 5.21 | | | $ | (1.84 | ) | | $ | 3.54 | |
| | | | | | | | | | | | | | | | |
INCOME (LOSS) PER COMMON SHARE- DILUTED: | | | | | | | | | | | | | | | | |
From continuing operations | | $ | (0.87 | ) | | $ | 4.48 | | | $ | (1.84 | ) | | $ | 3.21 | |
From discontinued operations | | $ | - | | | $ | (0.01 | ) | | $ | - | | | $ | 0.01 | |
| | | | | | | | | | | | | | | | |
Income (loss) applicable to common stock | | $ | (0.87 | ) | | $ | 4.47 | | | $ | (1.84 | ) | | $ | 3.22 | |
| | | | | | | | | | | | | | | | |
| | | | |
Weighted average common shares outstanding: | | | | | | | | | | | | | | | | |
Basic | | | 35,771 | | | | 35,440 | | | | 35,892 | | | | 33,098 | |
Diluted | | | 35,771 | | | | 42,185 | | | | 35,892 | | | | 39,740 | |
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GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | |
Calculation of EBITDAX: | | | | | | | | | | | | | | | | |
Revenue | | | 23,525 | | | | 60,376 | | | | 78,249 | | | | 171,902 | |
Lease operating expense | | | (7,363 | ) | | | (8,165 | ) | | | (23,343 | ) | | | (22,931 | ) |
Production and other taxes | | | (1,294 | ) | | | (2,110 | ) | | | (3,831 | ) | | | (5,699 | ) |
Transportation | | | (2,300 | ) | | | (2,224 | ) | | | (7,479 | ) | | | (6,480 | ) |
G&A - cash portion only | | | (5,263 | ) | | | (4,904 | ) | | | (15,830 | ) | | | (13,557 | ) |
Realized gain (loss) on derivatives not designated as hedges | | | 27,173 | | | | (1,854 | ) | | | 75,000 | | | | (3,436 | ) |
| | | | |
EBITDAX | | | 34,478 | | | | 41,119 | | | | 102,766 | | | | 119,799 | |
| | | | |
Reconciliation of EBITDAX to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
EBITDAX | | | 34,478 | | | | 41,119 | | | | 102,766 | | | | 119,799 | |
EBITDAX - Discontinued Operations | | | 14 | | | | 85 | | | | 79 | | | | 369 | |
Exploration | | | (1,625 | ) | | | (2,062 | ) | | | (6,804 | ) | | | (5,841 | ) |
Prospect amortization | | | 1,015 | | | | 1,720 | | | | 3,916 | | | | 4,169 | |
Dry hole | | | 59 | | | | - | | | | 160 | | | | - | |
Interest expense | | | (6,646 | ) | | | (5,524 | ) | | | (17,152 | ) | | | (16,971 | ) |
Interest income | | | 4 | | | | 1,260 | | | | 387 | | | | 1,260 | |
Current income taxes | | | 71 | | | | (12,679 | ) | | | 106 | | | | (12,679 | ) |
Amortization debt discount and finance cost | | | 2,982 | | | | 2,138 | | | | 7,603 | | | | 6,368 | |
Other non-cash items | | | - | | | | (91 | ) | | | - | | | | (91 | ) |
Net changes in working capital | | | (13,456 | ) | | | 15,159 | | | | (10,792 | ) | | | 1,838 | |
| | | | |
Net cash provided by operating activities (GAAP) | | | 16,896 | | | | 41,125 | | | | 80,269 | | | | 98,221 | |
| | | | |
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
Discretionary cash flow | | | 30,352 | | | | 25,966 | | | | 91,061 | | | | 96,383 | |
Net changes in working capital | | | (13,456 | ) | | | 15,159 | | | | (10,792 | ) | | | 1,838 | |
Net cash provided by operating activities (GAAP) | | | 16,896 | | | | 41,125 | | | | 80,269 | | | | 98,221 | |
| | | | |
Selected Operating Data: | | | | | | | | | | | | | | | | |
| | | | |
| | | Three Months Ended
September 30, | | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Production - Continuing Operations: | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | 7,386 | | | | 6,088 | | | | 21,153 | | | | 16,962 | |
Oil and condensate (MBbls) | | | 34 | | | | 40 | | | | 120 | | | | 123 | |
Total (Mmcfe) | | | 7,590 | | | | 6,328 | | | | 21,876 | | | | 17,700 | |
| | | | |
Average sales price per unit: | | | | | | | | | | | | | | | | |
Natural gas (per Mcf) | | $ | 2.89 | | | $ | 9.14 | | | $ | 3.42 | | | $ | 9.29 | |
Oil (per Bbl) | | | 64.43 | | | | 117.65 | | | | 48.87 | | | | 112.28 | |
Natural gas and oil (per Mcfe) | | | 3.11 | | | | 9.54 | | | | 3.58 | | | | 9.68 | |
| | | | |
Expenses per Mcfe: | | | | | | | | | | | | | | | | |
Lease operating expense | | $ | 0.97 | | | $ | 1.29 | | | $ | 1.07 | | | $ | 1.30 | |
Production and other taxes | | | 0.17 | | | | 0.33 | | | | 0.18 | | | | 0.32 | |
Transportation | | | 0.30 | | | | 0.35 | | | | 0.34 | | | | 0.37 | |
DD&A | | | 5.54 | | | | 4.17 | | | | 5.13 | | | | 4.55 | |
Exploration | | | 0.21 | | | | 0.33 | | | | 0.31 | | | | 0.33 | |
Impairment expense | | | - | | | | 0.17 | | | | 1.07 | | | | 0.06 | |
General and administrative | | | 0.90 | | | | 0.98 | | | | 0.94 | | | | 0.99 | |
Gain on sale of assets | | | (0.02 | ) | | | (23.05 | ) | | | (0.01 | ) | | | (8.24 | ) |
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