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Unit Corporation (NYSE: UNT) today reported its financial and operational results for the fourth quarter and year end 2014. For the year, Unit achieved a number of significant milestones:

  • Record consolidated revenues of $1.6 billion
  • Record proved reserves of 1.1 Tcfe (179.0 MMBoe), a 12% increase over 2013
  • Record annual production of 18.3 MMBoe, a 9% increase over 2013
  • Record annual average dayrate of $20,043
  • Successfully initiated the BOSS drilling program by placing three BOSS rigs into service and obtaining long-term contracts for an additional five
  • Record natural gas gathered, processed and natural gas liquids sold volumes per day with each increasing 3%, 15% and 35%, respectively, over 2013

FOURTH QUARTER AND YEAR END 2014 RESULTS

Despite its operational achievements for the year, Unit recorded a net loss for the quarter of $42.6 million, or $0.88 per diluted share, compared to net income of $51.3 million, or $1.05 per diluted share, for the fourth quarter of 2013. Because of the significantly lower commodity prices existing at year-end 2014, fourth quarter 2014 results included the following pre-tax non-cash write downs: $76.7 million ceiling test write down in the carrying value of Unit’s oil and natural gas properties; $74.3 million for the removal of 31 drillings rigs from the fleet along with some other equipment; and $7.1 million in the carrying value of three gas gathering systems. Adjusted net income for the quarter (which excludes the effect of non-cash commodity derivatives and the effects of the write-downs) was $39.7 million, or $0.80 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $378.6 million (43% oil and natural gas, 36% contract drilling, and 21% mid-stream), compared to $359.1 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream) for the fourth quarter of 2013.

For 2014, net income was $136.3 million, or $2.78 per diluted share, compared to 2013 net income of $184.7 million, or $3.80 per diluted share. Excluding the effect of the fourth quarter 2014 write downs discussed above and the effect of non-cash commodity derivatives, adjusted net income for 2014 was $212.6 million, or $4.33 per diluted share (see Non-GAAP Financial Measures below). Total revenues for 2014 were $1,572.9 million (47% oil and natural gas, 30% contract drilling, and 23% mid-stream), compared to $1,351.9 million (48% oil and natural gas, 31% contract drilling, and 21% mid-stream) for 2013.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production for the quarter was 4.9 million barrels of oil equivalent (MMBoe), an increase of 10% and 6% over the fourth quarter of 2013 and the third quarter of 2014, respectively. Liquids (oil and NGLs) production represented 47% of total equivalent production for the quarter. Oil production for the quarter was 11,340 barrels per day, an increase of 17% over the fourth quarter of 2013 and essentially unchanged from the third quarter of 2014. NGLs production for the quarter was 13,616 barrels per day, an increase of 8% over the fourth quarter of 2013 and an increase of 9% over the third quarter of 2014. Natural gas production for the quarter was 167,721 thousand cubic feet (Mcf) per day, an increase of 8% over the fourth quarter of 2013 and a 6% increase over the third quarter of 2014. Total production for 2014 was 18.3 MMBoe.

Unit’s average realized per barrel equivalent price for the fourth quarter was $35.73, a decrease of 7% from the fourth quarter of 2013 and a decrease of 10% from the third quarter of 2014. Unit’s average natural gas price for the fourth quarter of 2014 was $3.72 per Mcf, an increase of 16% over the fourth quarter of 2013 and a 1% increase over the third quarter of 2014. Unit’s average oil price for the quarter was $81.34 per barrel, a decrease of 14% from the fourth quarter of 2013 and a decrease of 11% from the third quarter of 2014. Unit’s average NGLs price for the quarter was $25.28 per barrel, a 26% decrease from the fourth quarter of 2013 and a decrease of 16% from the third quarter of 2014. For 2014, Unit’s average natural gas price increased 18% to $3.92 per Mcf as compared to $3.32 per Mcf for 2013. Unit’s average oil price for 2014 was $89.43 per barrel compared to $95.06 per barrel during 2013, a 6% decrease. Unit’s average NGLs price for 2014 was $30.95 per barrel compared to $31.79 per barrel during 2013, a 3% decrease. All prices in this paragraph include the effects of derivative contracts.

The following table summarizes this segment’s 2015 derivative contracts.

Crude
Weighted Average Price
Period Type Volume/Day Fixed Floor Ceiling
Jan 15 – Dec 15 Swaps 1,000 Bbls $95.00
Natural Gas
Weighted Average Price
Period Type Volume/Day Fixed Floor Ceiling
Jan 15 – Dec 15 Swaps 40,000 MMBtu $3.98
Jan 15 – Mar 15 Collars 30,000 MMBtu $4.20 $5.03
Apr 15 – Jun 15 Swaps 30,000 MMBtu $3.10
Apr 15 – Jun 15 Collars 30,000 MMBtu $2.92 $3.26
Jul 15 – Sep 15 Collars 30,000 MMBtu $2.58 $3.04

The following table illustrates this segment’s comparative production, realized prices, and operating profit for the periods indicated:

Three Months Ended Three Months Ended Twelve Months Ended
Dec. 31, 2014 Dec. 31, 2013 Change Dec. 31, 2014 Sept. 30, 2014 Change Dec. 31, 2014 Dec. 31, 2013 Change
Oil and NGLs Production, MBbl 2,296 2,047 12 % 2,296 2,188 5 % 8,472 7,274 16 %
Natural Gas Production, Bcf 15.4 14.3 8 % 15.4 14.5 6 % 58.9 56.8 4 %
Production, MBoe 4,868 4,438 10 % 4,868 4,612 6 % 18,281 16,734 9 %
Production, MBoe/day 52.9 48.2 10 % 52.9 50.1 6 % 50.1 45.8 9 %
Avg. Realized Natural Gas Price, Mcfe (1) $ 3.72 $ 3.21 16 % $ 3.72 $ 3.68 1 % $ 3.92 $ 3.32 18 %
Avg. Realized NGL Price, Bbl(1) $ 25.28 $ 33.94 (26 )% $ 25.28 $ 30.11 (16 )% $ 30.95 $ 31.79 (3 )%
Avg. Realized Oil Price, Bbl (1) $ 81.34 $ 94.70 (14 )% $ 81.34 $ 91.57 (11 )% $ 89.43 $ 95.06 (6 )%
Realized Price / Boe (1) $ 35.73 $ 38.24 (7 )% $ 35.73 $ 39.76 (10 )% $ 39.25 $ 37.77 4 %
Operating Profit Before Depreciation, Depletion, Amortization, &

Impairment (MM) (2)

$ 111.0 $ 128.2 (13 )% $ 111.0 $ 139.6 (21 )% $ 552.2 $ 465.7 19 %
(1) Realized price includes oil, natural gas liquids, 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.

At the end of 2014, ten Unit drilling rigs were operating for its exploration segment. Three were operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT), three in the Granite Wash (GW), two in the Wilcox, one in the Marmaton and one in the Mississippian. By the end of the first quarter and continuing through the second quarter of 2015, the plan is to have four Unit drilling rigs operating for its exploration segment. Two of the drilling rigs will be in the SOHOT and two in the Wilcox. Any adjustments to this level of activity will be dependent on commodity pricing and/or well results.

In the SOHOT area, production increased 45% during the quarter as compared to the third quarter of 2014. During the quarter, four new horizontal operated Hoxbar wells were completed. Three wells were completed in the Medrano member of the Hoxbar and one well in the Marchand member. The 30 day initial production rate for the three Medrano wells, fracture stimulated with larger fracs, averaged 13.8 MMcfe per day, which is approximately 78% higher compared to Unit’s prior Medrano completions. The average production mix of the three wells is 4% oil, 26% NGLs, and 70% natural gas. The completed Marchand well during the fourth quarter had a 30 day initial production rate of approximately 1,205 Boe per day, consisting of 82% oil, 9% NGLs, and 9% natural gas. The current plan for 2015 is to average one to two Unit rigs drilling in the prospect, which should equate to approximately 14 new horizontal Hoxbar completions, of which approximately 75% of the wells are anticipated to be in the Medrano. The estimated 2015 capital spending for drilling in the SOHOT is approximately $90 million.

In the Wilcox area, production increased 13% during the quarter as compared to the third quarter 2014 and increased 28% during 2014 compared to 2013. During the quarter, the BS O#2 (100% working interest), located on the east side of the Gilly field, was completed from approximately 91 net feet of Lower Wilcox sand flowing approximately 135 barrels of oil per day, 464 barrels of NGLs per day, and 6,500 Mcf per day (gross volumes) with 6,100 psi flowing tubing pressure. The well penetrated approximately 453 feet of additionalpotential pay sands and potentially extends the eastern extent of the Gilly field. At the end of 2014, the Gilly field is estimated to contain approximately 418 Bcfe gross and 302 Bcfe net of volumetric resource potential. To date, approximately 10% has been produced, and approximately 43% is booked as remaining proved reserves. The estimated 2015 capital spending for drilling in the Wilcox area is approximately $100 million. The current plan is to utilize one to two Unit drilling rigs in 2015, which should result in approximately eight vertical and six horizontal Wilcox completions.

YEAR END 2014 ESTIMATED PROVED RESERVES

The PV-10 value of Unit’s estimated year-end 2014 proved reserves increased 17% over 2013 to $2.1 billion. Unit’s estimated year-end 2014 proved oil and natural gas reserves were 179.0 MMBoe, or 1.1 trillion cubic feet of natural gas equivalents (Tcfe), as compared with 159.9 MMBoe, or 960 billion cubic feet of natural gas equivalents (Bcfe), at year-end 2013, a 12% increase in its estimated proved reserves. From all sources, Unit replaced approximately 204% of its 2014 production. Estimated reserves were 13% oil, 27% NGLs, and 60% natural gas. During 2014, Unit divested 1.4 MMBoe of non-core oil and natural gas reserves.

The following details the changes to Unit’s proved oil, NGLs, and natural gas reserves during 2014:

Oil
(MMbls)

NGLs
(MMbls)

Natural Gas
(Bcf)

Proved

Reserves

(MMBoe)

Proved Reserves, at December 31, 2013 21.8 41.2 581.8 159.9
Revisions of previous estimates (3.2 ) (2.3 ) (32.8 ) (10.9 )
Extensions, discoveries, and other
additions

8.1

14.4

160.7

49.3

Purchases of minerals in place 0.2 0.1 0.4 0.4
Production (3.8 ) (4.6 ) (58.8 ) (18.3 )
Sales (0.4 ) (0.3 ) (4.3 ) (1.4 )
Proved Reserves, at December 31, 2014 22.7 48.5 647.0 179.0

Estimated 2014 year-end proved reserves included proved developed reserves of 137 MMBoe, or 821 Bcfe, (13% oil, 26% NGLs, and 61% natural gas) and proved undeveloped reserves of 42 MMBoe, or 253 Bcfe, (12% oil, 30% NGLs, and 58% natural gas). Overall, 76% of Unit’s estimated proved reserves are proved developed.

The present value of the estimated future net cash flows from the 2014 estimated proved reserves (before income taxes and using a 10% discount rate (PV-10)), is approximately $2.1 billion. The present value was determined using the 12 month 2014 average prices received. The aggregate price used for all future reserves was $94.99 per barrel of oil, $45.25 per barrel of NGLs, and $4.36 per Mcf of natural gas. Unit’s 2014 year-end proved reserves were independently audited by Ryder Scott Company, L.P. Their audit covered properties which accounted for 85% of the discounted future net cash flow (PV-10). See below for the reconciliation of PV-10 to the standardized measure of discounted future net cash flows as defined by GAAP.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “For our oil and natural gas segment, fourth quarter production increased 10% over the comparable quarter of 2013 and increased 6% over the third quarter of 2014. Once again, we achieved our goal of replacing at least 150% of each year’s production with new reserves, achieving 204% production replacement in 2014. Our 2015 production guidance is approximately 18.6 to 19.0 MMBoe, an increase of 2% to 4% over 2014, although actual results will continue to be subject to industry conditions. Unit has a strong asset base, and we have a proven record of weathering the storms of these unfavorable pricing cycles.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 80.9, an increase of 24% over the fourth quarter of 2013, and an increase of 2% over the third quarter of 2014. Per day drilling rig rates for the quarter averaged $20,488, an increase of 4% over the fourth quarter of 2013 and 2% over the third quarter of 2014. Average per day operating margin for the quarter was $8,834 (before elimination of intercompany drilling rig profit and bad debt expense of $8.7 million). This compares to $8,132 (before elimination of intercompany drilling rig profit and bad debt expense of $5.7 million) for the fourth quarter of 2013, an increase of 9%, or $702. As compared to the third quarter of 2014 ($8,449 before elimination of intercompany drilling rig profit and bad debt expense of $7.6 million), fourth quarter 2014 operating margin increased 5% or $385 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense – see Non-GAAP Financial Measures below). Average operating margins for the fourth quarter of 2014 included early termination fees of approximately $27 per day from the cancellation of certain long-term contracts, compared to $161 per day for the fourth quarter of 2013.

For 2014, Unit averaged 75.4 drilling rigs working, an increase of 16% over 65.0 drilling rigs working during 2013. Average per day operating margin for 2014 was $8,392 (before elimination of intercompany drilling rig profit and bad debt expense of $29.3 million) as compared to $7,796 (before elimination of intercompany drilling rig profit of $17.4 million) for 2013, an increase of 8% (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For 2014, average operating margins included early termination fees of approximately $7 per day from the cancellation of certain long-term contracts, compared to $80 per day for 2013.

Larry Pinkston said: “Drilling rig demand declined during the latter part of the quarter because of the significant decrease in commodity prices. During the quarter, our third BOSS drilling rig began operating. At year end, we removed 31 drilling rigs from our fleet as well as some other equipment. With the addition of our fourth BOSS drilling rig that began operating in January 2015 and the reduction of the 31 drilling rigs at year end, our current drilling rig fleet now totals 90 drilling rigs, of which 47 are working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 21 of the 47 drilling rigs. To date, we have received early termination notices for eight of these contracts. Of the 21 long term contracts, four are up for renewal in the first quarter of 2015, five in the second quarter, four in the third quarter, two in the fourth quarter, and six are up for renewal in 2016. Currently we have four BOSS drilling rigs operating, and four additional BOSS drilling rigs have been contracted to be built for third party operators and are expected to be placed into service during 2015. We will delay fabrication of any additional BOSS drilling rigs until contracts are received.”

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

Three Months Ended Three Months Ended Twelve Months Ended
Dec. 31, 2014 Dec. 31, 2013 Change Dec. 31, 2014 Sept. 30, 2014 Change Dec. 31, 2014 Dec. 31, 2013 Change
Rigs Utilized 80.9 65.0 24% 80.9 79.1 2% 75.4 65.0 16%
Operating Profit Before Depreciation & Impairment (MM) (1) $ 57.1 $ 42.9 33% $ 57.1 $ 53.9 6% $ 201.6 $ 167.5 20%

(1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment.

MID-STREAM SEGMENT INFORMATION

For the quarter, per day liquids sold and gas gathered volumes both increased 5% while gas processed volumes increased 10% as compared to the fourth quarter of 2013. Compared to the third quarter of 2014, liquids sold and processed volumes per day decreased 11% and 3%, respectively, while gathered volumes per day increased 2%. Operating profit (as defined in the footnote below) for the quarter was $10.0 million, a decrease of 18% from the fourth quarter of 2013 and a decrease of 25% from the third quarter of 2014.

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

Three Months Ended Three Months Ended Twelve Months Ended
Dec. 31, 2014 Dec. 31, 2013 Change Dec. 31, 2014 Sept. 30, 2014 Change Dec. 31, 2014 Dec. 31, 2013 Change
Gas Gathering, Mcf/day 327,331 312,254 5 % 327,331 319,692 2 % 319,348 309,554 3 %
Gas Processing, Mcf/day 163,979 149,069 10 % 163,979 169,357 (3 )% 161,282 140,584 15 %
Liquids Sold, Gallons/day 687,713 656,415 5 % 687,713 771,334 (11 )% 733,406 543,602 35 %
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (1) $ 10.0 $ 12.2 (18 )% $ 10.0 $ 13.3 (25 )% $ 49.5 $ 43.9 13 %

(1) Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment.

Larry Pinkston said: “During 2014, we completed construction of a nine-mile pipeline that connects the Buffalo Wallow gathering system to our Hemphill processing system. Beginning January 1, 2015, this pipeline became fully operational, and we began processing Buffalo Wallow production at our Hemphill facility. We have several new wells to be connected to our Hemphill system in the next few months, and we are continuing to connect wells to the Buffalo Wallow system as they are completed. Our Snowshoe project in Centre County, Pennsylvania is in process. The project consists of a seven-mile, 16 inch and 24 inch trunkline to gather Marcellus production for delivery to an interstate pipeline. Construction of this project is expected to be completed in the third quarter of 2015.”

2015 CAPITAL EXPENDITURE BUDGET

Unit reduced its operating segment capital expenditures budget for 2015 by 52% compared to 2014, excluding acquisitions and asset retirement obligation liability, in order to focus on keeping its capital expenditures substantially within anticipated internally generated cash flow. The capital expenditures budget is allocated among Unit’s three business segments as follows: $308.5 million for its oil and natural gas segment; $99.7 million for its contract drilling segment; and $68.4 million for its midstream segment. This budget does not include costs for any possible acquisitions, and is based on realized prices for the year averaging $53.73 per barrel of oil, $17.03 per barrel of natural gas liquids, and $3.18 per Mcf of natural gas.

This budget is subject to possible periodic adjustments for various reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from internally generated cash flow, proceeds from additional non-core asset divestitures, and (if necessary) borrowings under Unit’s bank credit facility.

FINANCIAL INFORMATION

Unit ended the fourth quarter with long-term debt of $812.2 million (consisting of $646.2 million of senior subordinated notes net of unamortized discount and $166.0 million of borrowings under its credit agreement). Unit’s credit agreement provides that the amount Unit can borrow is the lesser of the amount it elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $900 million), but in either event not to exceed $900 million.

WEBCAST

Unit will webcast its fourth quarter and year-end earnings conference call live over the Internet on February 24, 2015 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 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 the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the company’s oil and natural gas production, oil and gas reserve information, and its ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the company’s inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company’s oil and natural gas segment, development, operational, implementation, and opportunity risks, possible delays caused by limited availability of third party services needed in its operations, unexpected delays or operational issues associated with the company’s new drilling rig design, possibility of future growth opportunities, 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.

Unit Corporation

Selected Financial Highlights

(In thousands except per share amounts)

Three Months Ended Twelve Months Ended
December 31, December 31,
2014 2013 2014 2013
Statement of Operations:
Revenues:
Oil and natural gas $ 164,903 $ 173,990 $ 740,079 $ 649,718
Contract drilling 134,987 101,598 476,517 414,778
Gas gathering and processing 78,661 83,533 356,348 287,354
Total revenues 378,551 359,121 1,572,944 1,351,850
Expenses:
Oil and natural gas:
Operating costs 53,937 45,830 187,916 184,001

Depreciation, depletion, and amortization

75,130 62,886 276,088 226,498
Impairment of oil & gas properties 76,683 76,683
Contract drilling:
Operating costs 77,908 58,700 274,933 247,280
Depreciation and impairment 98,494 18,624 159,688 71,194
Gas gathering and processing:
Operating costs 68,665 71,341 306,831 243,406

Depreciation, amortization and impairment

17,530 9,048 47,502 33,191
General and administrative 11,614 10,035 42,023 38,323
(Gain) loss on disposition of assets 139 (9,332 ) (8,953 ) (17,076 )
Total operating expenses 480,100 267,132 1,362,711 1,026,817
Income (loss) from operations (101,549 ) 91,989 210,233 325,033
Other income (expense):
Interest, net (5,170 ) (3,238 ) (17,371 ) (15,015 )
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net

39,381

(5,034

)

30,147

(8,374

)

Other (73 ) (4 ) (70 ) (175 )
Total other income (expense) 34,138 (8,276 ) 12,706 (23,564 )
Income (loss) before income taxes (67,411 ) 83,713 222,939 301,469
Income tax expense (benefit):
Current (14,343 ) 9,246 9,378 15,991
Deferred (10,517 ) 23,166 77,285 100,732
Total income taxes (24,860 ) 32,412 86,663 116,723
Net income (loss) $ (42,551 ) $ 51,301 $ 136,276 $ 184,746
Net income (loss) per common share:
Basic $ (0.88 ) $ 1.06 $ 2.80 $ 3.83
Diluted $ (0.88 ) $ 1.05 $ 2.78 $ 3.80
Weighted average shares outstanding:
Basic 48,656 48,292 48,611 48,218
Diluted 48,656 48,795 49,083 48,572
December 31, December 31,
2014 2013
Balance Sheet Data:
Current assets $ 252,491 $ 212,031
Total assets $ 4,473,728 $ 4,022,390
Current liabilities $ 304,171 $ 243,573
Long-term debt $ 812,163 $ 645,696
Other long-term liabilities $ 148,785 $ 158,331
Deferred income taxes $ 876,215 $ 801,398
Shareholders’ equity $ 2,332,394 $ 2,173,392
Twelve Months Ended December 31,
2014 2013
Statement of Cash Flows Data:

Cash flow from operations before changes in operating assets and liabilities

$ 764,984 $ 637,936
Net change in operating assets and liabilities (55,991) 36,395
Net cash provided by operating activities $ 708,993 $ 674,331
Net cash used in investing activities $ (920,597) $ (579,180)
Net cash provided by (used in) financing activities $ 194,060 $ (77,532)

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 and earnings per share including impairment adjustments and the effect of the cash settled commodity derivatives, unaudited oil and natural gas reserves reconciliation of PV-10 to standard measure, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, and its cash flow from operations before changes in operating assets and liabilities.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2014 and 2013. 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 and Adjusted Diluted Earnings per Share

Three Months Ended Twelve Months Ended
December 31, December 31,
2014 2013 2014 2013

(In thousands except earnings per share)

Adjusted net income:
Net income (loss) $ (42,551 ) $ 51,301 $ 136,276 $ 184,746
Impairment adjustment (net of income tax) 98,398 98,398

(Gain) loss on derivatives not designated as hedges and hedge ineffectiveness (net of income tax)

(24,088 ) 3,095 (18,429 ) 5,142

Settlements during the period of matured derivative contracts (net of income tax)

7,944 (116 ) (3,691 ) (1,081 )
Adjusted net income $ 39,703 $ 54,280 $ 212,554 $ 188,807
Adjusted diluted earnings per share:
Diluted earnings (loss) per share $ (0.88 ) $ 1.05 $ 2.78 $ 3.80
Diluted earnings per share from the impairments 2.02 2.01

Diluted earnings per share from the (gain) loss on derivatives

(0.51 ) 0.06 (0.38 ) 0.11

Diluted earnings (loss) per share from the settlements of matured derivative contracts

0.17 (0.08 ) (0.02 )
Adjusted diluted earnings per share $ 0.80 $ 1.11 $ 4.33 $ 3.89

________________

The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:

  • It uses the adjusted net income to evaluate the operational performance of the company.
  • The adjusted net income is more comparable to earnings estimates provided by securities analysts.

Unaudited Reconciliation of PV-10 to Standard Measure
December 31, 2014

PV-10 is the estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. Standardized Measure is the after-tax estimated future cash flows from proved reserves discounted at an annual rate of 10 percent, determined in accordance with GAAP. The company uses PV-10 as one measure of the value of its proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. The company believes that securities analysts and rating agencies use PV-10 in similar ways. The company’s management believes PV-10 is a useful measure for comparison of proved reserve values among companies because, unlike Standardized Measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. Below is a reconciliation of PV-10 to Standardized Measure:

2014
(In billions)
PV-10 at December 31, 2014 $ 2.1
Discounted effect of income taxes (0.7 )
Standardized Measure at December 31, 2014 $ 1.4

Unit Corporation

Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense

Three Months Ended Twelve Months Ended
September 30, December 31, December 31,
2014 2014 2013 2014 2013
(In thousands except operating days and operating margins)
Contract drilling revenue $ 120,652 $ 134,987 $ 101,598 $ 476,517 $ 414,778
Contract drilling operating cost 66,727 77,908 58,700 274,933 247,280
Operating profit from contract drilling 53,925 57,079 42,898 201,584 167,498

Add:
Elimination of intercompany rig profit and bad debt expense

7,553

8,669

5,741

29,343

17,416

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense

61,478 65,748 48,639 230,927 184,914
Contract drilling operating days 7,276 7,443 5,981 27,516 23,720

Average daily operating margin before elimination of intercompany rig profit and bad debt expense

$ 8,449 $ 8,834 $ 8,132 $ 8,392 $ 7,796

________________

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

Twelve Months Ended

December 31,

2014 2013
(In thousands)
Net cash provided by operating activities $ 708,993 $ 674,331
Net change in operating assets and liabilities 55,991 (36,395 )

Cash flow from operations before changes in operating assets and liabilities

$ 764,984 $ 637,936

________________

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.

Unit Corporation
Michael D. Earl, 918-493-7700
Vice President, Investor Relations
www.unitcorp.com