| News | UNIT CORPORATION |
| 7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136 | |
| Telephone 918 493-7700, Fax 918 493-7714 | |
| Contact: | Michael D. Earl |
| Vice President, Investor Relations | |
| (918) 493-7700 | |
| www.unitcorp.com | |
For Immediate Release…
May 5, 2016
UNIT CORPORATION REPORTS 2016 FIRST QUARTER RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the first quarter 2016. Highlights include:
| • | Realized net proceeds of $37.4 million from the sale of various non-core oil and natural gas segment asset packages. |
| • | Crude oil production per day increased 3% compared to the fourth quarter of 2015. |
| • | Midstream segment gas gathered volumes per day increased 15% compared to the first quarter of 2015. |
| • | Midstream segment connected additional well pads to its Pittsburgh Mills gathering line in Butler County, Pennsylvania, and commenced operations of its new fee-based Snow Shoe gathering system in Centre County, Pennsylvania. |
| • | Following the end of the quarter, Unit successfully amended its bank credit agreement. |
FIRST QUARTER 2016 FINANCIAL RESULTS
Adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) was $20.3 million, or $0.41 per share (see Non-GAAP financial measures below). Low commodity prices continued to negatively impact the company's financial results. For the quarter, Unit incurred a pre-tax non-cash ceiling test write-down of $37.8 million in the carrying value of its oil and natural gas properties. Although this write-down was a non-cash item, it resulted in Unit recording a net loss of $41.1 million, or $0.83 per share, compared to a net loss of $248.4 million, or $5.07 per share, for the first quarter of 2015. Total revenues were $136.2 million (43% oil and natural gas, 28% contract drilling, and 29% mid-stream), compared to $255.1 million (42% oil and natural gas, 37% contract drilling, and 21% mid-stream) for the first quarter of 2015. Adjusted EBITDA was $48.9 million, or $0.98 per diluted share (see Non-GAAP financial measures below).
Larry Pinkston, Unit’s Chief Executive Officer and President, said: "Recently, we successfully completed the amendment of our credit agreement. Our borrowing base was reset at $475 million, which provides ample liquidity to meet our needs during the present commodity cycle. We also modified our maximum leverage covenant from four times EBITDA to a maximum senior leverage covenant not to exceed 2.75 times EBITDA through the first quarter of 2019. We are pleased with this outcome and appreciate the continued support of our bank group."
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total equivalent production was 4.5 million barrels of oil equivalent (MMBoe), a decrease of 12% from the first quarter of 2015 and a 5% decrease from the fourth quarter of 2015. Liquids (oil and NGLs) production represented 46% of total equivalent production. Oil production was 8,821 barrels per day, a decrease of 28% from the first quarter of 2015 and an increase of 3% over the fourth quarter of 2015. NGLs production was 14,188 barrels per day, a decrease
of 1% from the first quarter of 2015 and a 1% decrease from the fourth quarter of 2015. Natural gas production was 159,585 thousand cubic feet (Mcf) per day, a decrease of 12% from the first quarter of 2015 and a decrease of 8% from the fourth quarter of 2015.
Unit’s average realized per barrel equivalent price was $13.67, a decrease of 38% from the first quarter of 2015 and a 26% decrease from the fourth quarter of 2015. Unit’s average natural gas price was $1.87 per Mcf, a decrease of 36% from the first quarter of 2015 and a decrease of 17% from the fourth quarter of 2015. Unit’s average oil price was $32.50 per barrel, a decrease of 33% from the first quarter of 2015 and a decrease of 33% from the fourth quarter of 2015. Unit’s average NGLs price was $6.59 per barrel, a 24% decrease from the first quarter of 2015 and a decrease of 40% from the fourth quarter of 2015. All prices in this paragraph include the effects of derivative contracts.
During the quarter, in the Wilcox play, Unit drilled and completed four horizontal wells, two in the Gilly field and two others in nearby fields. The results of the two Gilly field horizontal wells were strong with 30 day IP rates of approximately 12.7 and 5.6 million cubic feet equivalent (MMcfe) per day. The two Wilcox wells outside of the Gilly field currently have insufficient data to provide 30 day IP rates. Additionally, the company completed new behind pipe Wilcox intervals in three existing vertical wells. The new well production coupled with the behind pipe completion activities resulted in Wilcox production increasing 3% over the fourth quarter of 2015. In accordance with previously announced plans, the company ceased all drilling activity by the end of the first quarter.
In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), Unit drilled four wells and completed three wells during the quarter. For the three wells that had sufficient data, the average 30 day IP rate is approximately 800 barrels of oil equivalent (Boe) per day, which is in line with the company's current type curve. The fourth well was completed in late April and is currently in the early stages of flowing back. Per day oil production in the SOHOT increased 3% quarter over quarter, primarily as a result of the company's Marchand drilling activities. Overall, SOHOT equivalent production decreased 6% quarter over quarter, primarily as a result of no new Medrano gas completions.
This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:
| Three Months Ended | Three Months Ended | ||||||||||||||
Mar 31, 2016 | Mar 31, 2015 | Change | Mar 31, 2016 | Dec 31, 2015 | Change | ||||||||||
| Oil and NGLs Production, MBbl | 2,094 | 2,384 | (12)% | 2,094 | 2,108 | (1)% | |||||||||
| Natural Gas Production, Bcf | 14.5 | 16.4 | (11)% | 14.5 | 15.9 | (9)% | |||||||||
| Production, MBoe | 4,514 | 5,117 | (12)% | 4,514 | 4,757 | (5)% | |||||||||
| Production, MBoe/day | 49.6 | 56.9 | (13)% | 49.6 | 51.7 | (4)% | |||||||||
Avg. Realized Natural Gas Price, Mcf (1) | $ | 1.87 | $ | 2.94 | (36)% | $ | 1.87 | $ | 2.24 | (17)% | |||||
Avg. Realized NGL Price, Bbl (1) | $ | 6.59 | $ | 8.65 | (24)% | $ | 6.59 | $ | 11.05 | (40)% | |||||
Avg. Realized Oil Price, Bbl (1) | $ | 32.50 | $ | 48.47 | (33)% | $ | 32.50 | $ | 48.23 | (33)% | |||||
Realized Price / Boe (1) | $ | 13.67 | $ | 21.99 | (38)% | $ | 13.67 | $ | 18.54 | (26)% | |||||
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2) | $ | 24.9 | $ | 60.9 | (59)% | $ | 24.9 | $ | 39.7 | (37)% | |||||
| (1) | Realized price includes oil, NGLs, natural gas, and associated derivatives. |
| (2) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. |
Pinkston said: "We continue to work toward our objective to establish hedge positions for both crude oil and natural gas that is 50% to 70% of each year's anticipated production. For the balance of our 2016 natural gas production, we have achieved that objective. We will continue to add to these positions for the balance of 2016 and 2017 as conditions warrant."
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This table summarizes the outstanding derivative contracts.
| Crude | ||||||
| Period | Structure | Volume Bbl/Day | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Subfloor Price | Weighted Average Ceiling Price |
| Apr'16 - Jun'16 | Collar | 5,150 | $40.71 | $49.88 | ||
| Jul'16 - Sep'16 | Collar | 1,000 | $40.00 | $46.75 | ||
| Jul'16 - Dec'16 | Collar | 1,450 | $47.50 | $56.40 | ||
| Apr'16 - Dec'16 | 3-Way Collar | 700 | $46.50 | $35.00 | $57.00 | |
| Jul'16 - Dec'16 | 3-Way Collar (1) | 700 | $47.50 | $35.00 | $63.50 | |
| Jan'17 - Dec'17 | 3-Way Collar | 750 | $50.00 | $37.50 | $63.90 | |
| Natural Gas | ||||||
| Period | Structure | Volume MMBtu/Day | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Subfloor Price | Weighted Average Ceiling Price |
| Apr'16 - Dec'16 | Swap | 45,000 | $2.596 | |||
| Jan'17 - Dec'17 | Swap | 30,000 | $2.905 | |||
| Apr'16 - Dec'16 | Collar | 42,000 | $2.40 | $2.88 | ||
| Jan-17 - Oct'17 | Collar | 10,000 | $2.75 | $2.95 | ||
| Apr'16 - Dec'16 | 3-Way Collar | 13,500 | $2.70 | $2.20 | $3.26 | |
| Jan'17 - Dec'17 | 3-Way Collar | 15,000 | $2.50 | $2.00 | $3.32 | |
(1) Unit pays its counterparty a premium, which can be and is being deferred until settlement.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs working during the quarter was 20.6, a decrease of 59% from the first quarter of 2015, and a decrease of 24% from the fourth quarter of 2015. Per day drilling rig rates averaged $18,392, a decrease of 9% from the first quarter of 2015 and a 1% decrease from the fourth quarter of 2015. Average per day operating margin was $5,651. This compares to the first quarter of 2015 average operating margin of $10,253 (before elimination of intercompany drilling rig profit and bad debt expense of $2.9 million), a decrease of 45%, or $4,602. Compared to the fourth quarter of 2015 average operating margin of $7,258 (before elimination of intercompany drilling rig profit and bad debt expense of $0.3 million), first quarter 2016 operating margin decreased 22%, or $1,607 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP financial measures below). Average operating margins for the quarter included early termination fees of approximately $2.6 million, or $1,410 per day, from the cancellation of certain long-term contracts, compared to early termination fees of $12.7 million, or $2,807 per day, during the first quarter of 2015 and $3.3 million, or $1,327 per day, for the fourth quarter of 2015.
Pinkston said: “With the continued decline in commodity prices during the quarter, operators substantially reduced their capital expenditure budgets resulting in our utilization rate continuing to fall during the quarter. Currently, we have six of our eight BOSS drilling rigs under contract. Our current drilling rig fleet totals 94 drilling rigs, of which 13 are working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for six of our drilling rigs. Of the six long-term contracts, one is up for renewal during the third quarter of 2016, one during the fourth quarter, and four in 2017.”
This table illustrates certain comparative results for the periods indicated:
| Three Months Ended | Three Months Ended | ||||||||||||||
Mar 31, 2016 | Mar 31, 2015 | Change | Mar 31, 2016 | Dec 31, 2015 | Change | ||||||||||
| Rigs Utilized | 20.6 | 50.1 | (59)% | 20.6 | 27.2 | (24)% | |||||||||
Operating Profit Before Depreciation & Impairment (MM) (1) | $ | 10.6 | $ | 43.3 | (76)% | $ | 10.6 | $ | 17.9 | (41)% | |||||
| (1) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. |
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MID-STREAM SEGMENT INFORMATION
For the quarter, per day gas gathered volumes increased 15%, while gas processed and liquids sold volumes decreased 12% and 9%, respectively, as compared to the first quarter of 2015. Compared to the fourth quarter of 2015, gas gathered volumes per day increased 6% while gas processed and liquids sold volumes per day decreased 2% and 8%, respectively. Operating profit (as defined in the footnote below) for the quarter was $8.1 million, a decrease of 17% from the first quarter of 2015 and a decrease of 14% from the fourth quarter of 2015.
This table illustrates certain comparative results for the periods indicated:
| Three Months Ended | Three Months Ended | ||||||||||||||
Mar 31, 2016 | Mar 31, 2015 | Change | Mar 31, 2016 | Dec 31, 2015 | Change | ||||||||||
| Gas Gathering, Mcf/day | 383,405 | 334,278 | 15% | 383,405 | 360,159 | 6% | |||||||||
| Gas Processing, Mcf/day | 167,048 | 189,160 | (12)% | 167,048 | 170,087 | (2)% | |||||||||
| Liquids Sold, Gallons/day | 519,433 | 568,876 | (9)% | 519,433 | 561,941 | (8)% | |||||||||
Operating Profit Before Depreciation, Amortization & Impairment (MM) (1) | $ | 8.1 | $ | 9.8 | (17)% | $ | 8.1 | $ | 9.4 | (14)% | |||||
| (1) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. |
Pinkston said: “We continue to see gains in gas gathered volumes at our Segno system in the Wilcox in southeast Texas. In the Marcellus, we connected additional well pads to our Pittsburgh Mills system in Butler County, Pennsylvania and commenced operation of our new Snow Shoe system in Centre County, Pennsylvania. Due to low liquids prices, our midstream segment remained in full ethane rejection mode at our various gas processing facilities in the Mid-Continent.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $898.7 million (consisting of $638.5 million of senior subordinated notes net of unamortized discount and debt issuance costs and $260.2 million of borrowings under its credit agreement). Under the credit agreement, the amount Unit can borrow is the lesser of the amount it elects as the commitment amount ($475 million) or the value of its borrowing base as determined by the lenders ($475 million), but in either event not to exceed $875 million. The credit agreement was amended after the first quarter to provide, in part, for the $475 million redetermined borrowing base.
WEBCAST
Unit will webcast its first quarter earnings conference call live over the Internet on May 5, 2016 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.
_____________________________________________________
Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events, or developments that the Company expects, believes, or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including changes in commodity prices, the productive capabilities of the Company’s wells, future demand for oil and natural gas, future
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drilling rig utilization and dayrates, projected rate of the Company’s oil and natural gas production, the amount available to the Company for borrowings, its anticipated borrowing needs under its credit agreement, the number of wells to be drilled by the Company’s oil and natural gas segment, and other factors described from time to time in the Company’s publicly available SEC reports. The Company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.
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Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2016 | 2015 | |||||||
| Statement of Operations: | ||||||||
| Revenues: | ||||||||
| Oil and natural gas | $ | 58,274 | $ | 106,069 | ||||
| Contract drilling | 38,710 | 95,077 | ||||||
| Gas gathering and processing | 39,200 | 53,953 | ||||||
| Total revenues | 136,184 | 255,099 | ||||||
| Expenses: | ||||||||
| Oil and natural gas: | ||||||||
| Operating costs | 33,346 | 45,211 | ||||||
| Depreciation, depletion, and amortization | 31,832 | 77,118 | ||||||
| Impairment of oil and natural gas properties | 37,829 | 400,593 | ||||||
| Contract drilling: | ||||||||
| Operating costs | 28,098 | 51,746 | ||||||
| Depreciation | 12,195 | 15,013 | ||||||
| Gas gathering and processing: | ||||||||
| Operating costs | 31,066 | 44,175 | ||||||
| Depreciation and amortization | 11,459 | 10,694 | ||||||
| General and administrative | 8,715 | 9,370 | ||||||
| Gain on disposition of assets | (192 | ) | (545 | ) | ||||
| Total operating expenses | 194,348 | 653,375 | ||||||
| Loss from operations | (58,164 | ) | (398,276 | ) | ||||
| Other income (expense): | ||||||||
| Interest, net | (9,617 | ) | (7,240 | ) | ||||
| Gain on derivatives | 10,929 | 6,586 | ||||||
| Other | (15 | ) | (2 | ) | ||||
| Total other income (expense) | 1,297 | (656 | ) | |||||
| Loss before income taxes | (56,867 | ) | (398,932 | ) | ||||
| Income tax expense (benefit): | ||||||||
| Current | — | 65 | ||||||
| Deferred | (15,718 | ) | (150,643 | ) | ||||
| Total income taxes | (15,718 | ) | (150,578 | ) | ||||
| Net loss | $ | (41,149 | ) | $ | (248,354 | ) | ||
| Net loss per common share: | ||||||||
| Basic | $ | (0.83 | ) | $ | (5.07 | ) | ||
| Diluted | $ | (0.83 | ) | $ | (5.07 | ) | ||
| Weighted average shares outstanding: | ||||||||
| Basic | 49,880 | 48,977 | ||||||
| Diluted | 49,880 | 48,977 | ||||||
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| March 31, | December 31, | ||||||
| 2016 | 2015 | ||||||
Balance Sheet Data: | |||||||
| Current assets | $ | 124,092 | $ | 140,258 | |||
| Total assets | $ | 2,681,088 | $ | 2,799,842 | |||
| Current liabilities | $ | 139,411 | $ | 150,891 | |||
| Long-term debt, net of unamortized discount and debt issuance costs | $ | 898,722 | $ | 918,995 | |||
| Other long-term liabilities | $ | 106,930 | $ | 140,341 | |||
| Deferred income taxes | $ | 254,800 | $ | 275,750 | |||
| Shareholders’ equity | $ | 1,281,040 | $ | 1,313,580 | |||
| Three Months Ended March 31, | |||||||
| 2016 | 2015 | ||||||
| Statement of Cash Flows Data: | |||||||
| Cash flow from operations before changes in operating assets and liabilities | $ | 36,349 | $ | 116,304 | |||
| Net change in operating assets and liabilities | 34,364 | 44,005 | |||||
| Net cash provided by operating activities | $ | 70,713 | $ | 160,309 | |||
| Net cash used in investing activities | $ | (37,486 | ) | $ | (231,027 | ) | |
| Net cash (used in) provided by financing activities | $ | (33,323 | ) | $ | 70,533 | ||
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Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP performance measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the Company.
This press release includes net income (loss) and earnings (loss) per share including impairment adjustments and the effect of the cash settled commodity derivatives, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, its cash flow from operations before changes in operating assets and liabilities, and its reconciliation of net income (loss) to adjusted EBITDA.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2016 and 2015. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.
Unit Corporation
Reconciliation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) per Share
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands except earnings per share) | ||||||||
| Adjusted net income (loss): | ||||||||
| Net loss | $ | (41,149 | ) | $ | (248,354 | ) | ||
| Impairment adjustment (net of income tax) | 23,549 | 249,369 | ||||||
| Gain on derivatives (net of income tax) | (7,908 | ) | (4,024 | ) | ||||
| Settlements during the period of matured derivative contracts (net of income tax) | 5,167 | 6,728 | ||||||
| Adjusted net income (loss) | $ | (20,341 | ) | $ | 3,719 | |||
| Adjusted diluted earnings (loss) per share: | ||||||||
| Diluted loss per share | $ | (0.83 | ) | $ | (5.07 | ) | ||
| Diluted earnings per share from the impairments | 0.48 | 5.09 | ||||||
| Diluted earnings per share from the gain on derivatives | (0.16 | ) | (0.08 | ) | ||||
| Diluted earnings (loss) per share from the settlements of matured derivative contracts | 0.10 | 0.14 | ||||||
| Adjusted diluted earnings (loss) per share | $ | (0.41 | ) | $ | 0.08 | |||
________________
The Company has included the net income (loss) and diluted earnings (loss) per share including only the cash settled commodity derivatives because:
| • | It uses the adjusted net income (loss) to evaluate the operational performance of the Company. |
| • | The adjusted net income (loss) is more comparable to earnings estimates provided by securities analysts. |
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Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit
and Bad Debt Expense
| Three Months Ended | ||||||||||||
| December 31, | March 31, | |||||||||||
| 2015 | 2016 | 2015 | ||||||||||
| (In thousands except for operating days and operating margins) | ||||||||||||
| Contract drilling revenue | $ | 50,554 | $ | 38,710 | $ | 95,077 | ||||||
| Contract drilling operating cost | 32,691 | 28,098 | 51,746 | |||||||||
| Operating profit from contract drilling | 17,863 | 10,612 | 43,331 | |||||||||
| Add: | ||||||||||||
| Elimination of intercompany rig profit and bad debt expense | 325 | — | 2,910 | |||||||||
| Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense | 18,188 | 10,612 | 46,241 | |||||||||
| Contract drilling operating days | 2,506 | 1,878 | 4,510 | |||||||||
| Average daily operating margin before elimination of intercompany rig profit and bad debt expense | $ | 7,258 | $ | 5,651 | $ | 10,253 | ||||||
________________
The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
| • | Its management uses the measurement to evaluate the cash flow performance of its contract drilling segment and to evaluate the performance of contract drilling management. |
| • | It is used by investors and financial analysts to evaluate the performance of the Company. |
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Three Months Ended March 31, | |||||||
| 2016 | 2015 | ||||||
| (In thousands) | |||||||
| Net cash provided by operating activities | $ | 70,713 | $ | 160,309 | |||
| Net change in operating assets and liabilities | (34,364 | ) | (44,005 | ) | |||
| Cash flow from operations before changes in operating assets and liabilities | $ | 36,349 | $ | 116,304 | |||
________________
The Company has included the cash flow from operations before changes in operating assets and liabilities because:
| • | It is an accepted financial indicator used by its management and companies in the industry to measure the Company’s ability to generate cash which is used to internally fund its business activities. |
| • | It is used by investors and financial analysts to evaluate the performance of the Company. |
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Unit Corporation
Reconciliation of EBITDA and Adjusted EBITDA
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands except earnings per share) | ||||||||
| Net loss | $ | (41,149 | ) | $ | (248,354 | ) | ||
| Income taxes | (15,718 | ) | (150,578 | ) | ||||
| Depreciation, depletion and amortization | 56,116 | 103,590 | ||||||
| Impairment | 37,829 | 400,593 | ||||||
| Interest expense | 9,617 | 7,240 | ||||||
| Gain on derivatives | (10,929 | ) | (6,586 | ) | ||||
| Settlements during the period of matured derivative contracts | 7,140 | 11,012 | ||||||
| Stock compensation plans | 4,798 | 5,863 | ||||||
| Other non-cash items | 1,405 | 1,480 | ||||||
| Gain on disposition of assets | (192 | ) | (545 | ) | ||||
| Adjusted EBITDA | $ | 48,917 | $ | 123,715 | ||||
| Diluted loss per share | $ | (0.83 | ) | $ | (5.07 | ) | ||
| Diluted earnings per share from income taxes | (0.32 | ) | (3.07 | ) | ||||
| Diluted earnings per share from depreciation, depletion and amortization | 1.12 | 2.11 | ||||||
| Diluted earnings per share from impairments | 0.77 | 8.17 | ||||||
| Diluted earnings per share from interest expense | 0.19 | 0.15 | ||||||
| Diluted earnings per share from the gain on derivatives | (0.22 | ) | (0.13 | ) | ||||
| Diluted earnings per share from the settlements during the period of matured derivative contracts | 0.14 | 0.22 | ||||||
| Diluted earnings per share from stock compensation plans | 0.10 | 0.12 | ||||||
| Diluted earnings per share from other non-cash items | 0.03 | 0.03 | ||||||
| Diluted earnings per share from the gain on disposition of assets | — | (0.01 | ) | |||||
| Adjusted EBITDA per diluted share | $ | 0.98 | $ | 2.52 | ||||
________________
The Company has included the adjusted EBITDA excluding gain or loss on disposition of assets and including only the cash settled commodity derivatives because:
| • | It uses the adjusted EBITDA to evaluate the operational performance of the Company. |
| • | The adjusted EBITDA is more comparable to estimates provided by securities analysts. |
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