Unit Corporation Reports 2015 Fourth Quarter & Year End Results

Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the fourth quarter and year end 2015.
Operational highlights for the year include:

• Achieved year over year production growth of 9%
• Successful development of the company’s horizontal well program in its
  Wilcox play
• Placed into service five new BOSS drilling rigs
• Achieved the best safety performance in the history of the company
• Gas gathered and gas processed volumes per day increased 11% and 13%,
  respectively, over 2014
• Completed the expansion of the Pittsburgh Mills pipeline in Butler
  County, Pennsylvania, and completed construction of the new fee-based
  Snow Shoe gathering system in Centre County, Pennsylvania

FOURTH QUARTER 2015 FINANCIAL RESULTS

Adjusted net loss (which excludes the effect of non-cash commodity
derivatives and the effect of the non-cash write-downs) was $6.6
million, or $0.14 per share (see Non-GAAP Financial Measures below). Low
commodity prices continued to significantly affect Unit’s financial
results. Because of lower commodity prices, Unit incurred during the
quarter a pre-tax non-cash ceiling test write-down of $458.3 million in
the carrying value of its oil and natural gas properties and $27.0
million in the carrying value of three of its gas gathering systems.
Although these write-downs were non-cash items, they resulted in Unit
recording a net loss of $309.3 million, or $6.29 per share, compared to
a net loss of $42.6 million, or $0.88 per share, for the fourth quarter
of 2014. Total revenues were $172.3 million (44% oil and natural gas,
29% contract drilling, and 27% mid-stream), compared to $378.6 million
(43% oil and natural gas, 36% contract drilling, and 21% mid-stream) for
the fourth quarter of 2014. Adjusted EBITDA was $73.5 million, or $1.49
per diluted share (see Non-GAAP Financial Measures below).

YEAR END 2015 FINANCIAL RESULTS

Adjusted net loss (which excludes the effect of non-cash commodity
derivatives and the effects of the non-cash write-downs) was $7.2
million, or $0.15 per share (see Non-GAAP Financial Measures below). For
the full year, Unit recorded pre-tax non-cash ceiling test write-downs
of $1.6 billion in the carrying value of its oil and natural gas
properties, $8.3 million in the carrying value of certain drilling rigs
and other assets removed from service, and $27.0 million for the gas
gathering systems discussed above. Because of these write-downs, Unit
recorded a net loss of $1.0 billion, or $21.12 per share, compared to
net income of $136.3 million, or $2.78 per diluted share, for 2014.
Total revenues were $854.2 million (45% oil and natural gas, 31%
contract drilling, and 24% mid-stream), compared to $1.6 billion (47%
oil and natural gas, 30% contract drilling, and 23% mid-stream) for
2014. Adjusted EBITDA for the year was $384.6 million, or $7.80 per
diluted share (see Non-GAAP Financial Measures below).

Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“Without question 2015 has been a very challenging year, and 2016 is not
starting off any better. We have been through many of these cycles and
have survived to see the benefit of a return to better times. We intend
to do so again. In response to the current conditions, we have taken
several actions. First, in the normal course of our operations we have
continued to carry out our program of selling certain non-core
exploration and production assets. Early in 2016, we completed various
non-core asset sales with total proceeds of approximately $37.4 million.
We will continue to market non-core assets as opportunities arise.
Second, we have carried out several reductions in our workforce,
including both corporate and field staff. Third, in our drilling
segment, we are reorganizing our drilling divisions from five to two.
Fourth, we continue to manage our outstanding borrowings under our
credit agreement. At December 31, 2015, our bank borrowings totaled
$281.0 million, while currently our borrowings are $267.7 million. Last,
our 2016 budget shifts much of our exploration segment budget to the
latter part of the year to provide us time to assess future commodity
price movements before we expend those funds.”

OIL AND NATURAL GAS SEGMENT INFORMATION

Total production for 2015 was 20.0 million barrels of oil equivalent
(MMBoe), a 9% increase over 2014. For the quarter, total equivalent
production was 4.8 MMBoe, a decrease of 2% from the fourth quarter of
2014 and a 6% decrease from the third quarter of 2015. Liquids (oil and
NGLs) production represented 44% of total equivalent production for the
quarter. Oil production for the quarter was 8,562 barrels per day, a
decrease of 25% from the fourth quarter of 2014 and a decrease of 17%
from the third quarter of 2015. NGLs production for the quarter was
14,346 barrels per day, an increase of 5% over the fourth quarter of
2014 and a 1% decrease from the third quarter of 2015. Natural gas
production for the quarter was 172,783 thousand cubic feet (Mcf) per
day, an increase of 3% over the fourth quarter of 2014 and a decrease of
4% from the third quarter of 2015.

Unit’s average realized per barrel equivalent price for the quarter was
$18.54, a decrease of 48% from the fourth quarter of 2014 and a 10%
decrease from the third quarter of 2015. Unit’s average natural gas
price for the quarter was $2.24 per Mcf, a decrease of 40% from the
fourth quarter of 2014 and a decrease of 16% from the third quarter of
2015. Unit’s average oil price for the quarter was $48.23 per barrel, a
decrease of 41% from the fourth quarter of 2014 and a decrease of 5%
from the third quarter of 2015. Unit’s average NGLs price for the
quarter was $11.05 per barrel, a 56% decrease from the fourth quarter of
2014 and an increase of 26% over the third quarter of 2015. All prices
in this paragraph include the effects of derivative contracts.

Three Unit drilling rigs are operating for this segment. One is
operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT), one is
drilling in the Wilcox play, in Southeast Texas, and one is drilling in
the Granite Wash Buffalo Wallow field in the Texas Panhandle. The
current plan is to keep these three Unit drilling rigs operating during
the first quarter, at which time all three rigs will be released. The
budget for this segment contemplates that the rigs may be put back into
service during the year depending on commodity prices.

In the Wilcox play, production for the fourth quarter averaged 88
million cubic feet equivalent (MMcfe) per day (11% oil, 31% NGLs), which
is a 25% increase over the fourth quarter of 2014, and a 7% increase
over the third quarter 2015. Two new vertical Wilcox wells were
completed during the quarter, bringing the total for 2015 to 15 wells
(three horizontal) with a 100% completion success rate. Production from
Unit’s three horizontal Wilcox wells completed in the first half of 2015
continues to be encouraging. The Parker 5H (75% working interest) is
averaging approximately 13.9 MMcfe per day (3,457′ lateral) with 5,300
pounds of flowing tubing pressure after 330 days on line. The Epstein 7H
(100% working interest) is averaging approximately 10.8 MMcfe per day
(4,364′ lateral) with 2,700 pounds of flowing tubing pressure after 240
days on line. The BP America 2H (100% working interest) is averaging
approximately 1.6 MMcfe per day (1,413′ lateral) with 700 pounds of
flowing tubing pressure after 390 days on line. Three additional
horizontal Wilcox wells completed drilling operations during the fourth
quarter and early 2016. All three wells have been fracture stimulated
and are in the early stages of flow back. Two of the wells are in the
Gilly Field with lateral lengths of 5,484 feet and 5,654 feet. The other
well is in a nearby field and has a lateral length of 5,861 feet. The
average total well cost for these three wells decreased 61% to $1,110
per lateral foot as compared to an average cost of $2,839 per lateral
foot for the first three wells discussed above. The significant well
cost reduction is attributed to lower service costs and drilling and
completion efficiencies. Unit is drilling another horizontal Wilcox well
that is scheduled for completion in April.

In the SOHOT area, production for the quarter averaged 44 MMcfe per day
(28% oil, 21% NGLs) which is a 117% increase over the fourth quarter
2014, and a 6% increase over the third quarter 2015. Three horizontal
operated Hoxbar wells were completed during the quarter with two wells
in the Marchand bench and one well in the Medrano bench. The two
Marchand completions targeted a previously untested “Marchand Shale”
interval to evaluate the potential of this interval in connection with
an acquisition opportunity Unit was then reviewing in the SOHOT area.
Although both shale wells are productive, the initial production rates
are lower than the Marchand sand wells and appear uneconomic at current
oil prices. Unit’s Marchand well inventory of approximately 60 gross
operated and non-operated locations does not include any shale interval
locations. Drilling and completion cost for Marchand wells continue to
trend lower. The current AFE for a 4,500′ Marchand sand well is
approximately $4.9 million, which is a decrease of approximately 30% as
compared to 2014 AFE’s of $7.0 million. During the first quarter of
2016, Unit completed two new Marchand sand wells that are in the early
stages of flow back. A third well has been drilled and is scheduled to
be fracture stimulated in mid-March. A fourth well is drilling and will
be completed in April.

Pinkston said: “With a significantly reduced capital budget, our
exploration and production segment was able to exceed our annual
production growth guidance of 6%-8% year over year with growth of 9% for
2015. Our 2015 capital expenditures for the segment were 64% lower than
2014. During 2015, we reduced our operating expense by 12% year over
year (27% during the second half of 2015 compared to the second half of
2014.) We will continue to make adjustments as the current pricing cycle
dictates.”

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, 2015				Dec 31, 2014				Change					Dec 31, 2015				Sept 30, 2015				Change					Dec 31, 2015				Dec 31, 2014				Change
Oil and NGLs Production, MBbl						2,108				2,296			(8	)%					2,108				2,289			(8	)%					9,057				8,472			7	%
Natural Gas Production, Bcf						15.9				15.4			3	%					15.9				16.6			(4	)%					65.5				58.9			11	%
Production, MBoe						4,757				4,868			(2	)%					4,757				5,053			(6	)%					19,982				18,281			9	%
Production, MBoe/day						51.7				52.9			(2	)%					51.7				54.9			(6	)%					54.7				50.1			9	%
Avg. Realized Natural Gas Price, Mcf (1)					$	2.24			$	3.72			(40	)%				$	2.24			$	2.66			(16	)%				$	2.63			$	3.92			(33	)%
Avg. Realized NGL Price, Bbl (1)					$	11.05			$	25.28			(56	)%				$	11.05			$	8.74			26	%				$	10.12			$	30.95			(67	)%
Avg. Realized Oil Price, Bbl (1)					$	48.23			$	81.34			(41	)%				$	48.23			$	50.87			(5	)%				$	50.79			$	89.43			(43	)%
Realized Price / Boe (1)					$	18.54			$	35.73			(48	)%				$	18.54			$	20.61			(10	)%				$	20.92			$	39.25			(47	)%
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2)					$	39.7			$	111.0			(64	)%				$	39.7			$	57.9			(32	)%				$	219.7			$	552.2			(60	)%
(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 endeavor to go into each year with 50% – 70% of our
anticipated production volumes hedged. For 2016, we have achieved that
objective on our anticipated natural gas production. We currently have
not achieved that objective for our crude oil production, but we intend
to add to that position as circumstances allow.”

The following table summarizes this segment’s 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
Jan’16 – Dec’16			3-Way Collar			700						$46.50			$35.00			$57.00
Jan’16 – Jun’16			Collar			2,150						$46.36						$55.62
Jul’16 – Dec’16			3-Way Collar (1)			700						$47.50			$35.00			$63.50
Jul’16 – Dec’16			Collar			1,450						$47.50						$56.40
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
Jan’16 – Dec’16			Swap			35,000			$2.625
Feb’16 – Dec’16			Swap			10,000			$2.495
Jan’16 – Dec’16			3-Way Collar			13,500						$2.70			$2.20			$3.26
Jan’16 – Dec’16			Collar			42,000						$2.40						$2.88
Jan’17 – Dec’17			Swap			10,000			$2.795
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.

YEAR END 2015 ESTIMATED PROVED RESERVES

The PV-10 value of Unit’s estimated year-end 2015 proved reserves
decreased 67% from 2014 to $690.7 million. Unit’s estimated year-end
2015 proved oil and natural gas reserves were 135.2 MMBoe, or 811.4
billion cubic feet of natural gas equivalents (Bcfe), as compared with
179.0 MMBoe, or 1.1 trillion cubic feet of natural gas equivalents
(Tcfe), at year-end 2014, a 24% decrease. Estimated reserves were 12%
oil, 28% NGLs, and 60% natural gas. During 2015, Unit sold 0.2 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 2015:

			Oil (MMbls)				NGLs (MMbls)				Natural Gas (Bcf)				Proved Reserves (MMBoe)
Proved Reserves, at December 31, 2014			22.7				48.5				647.0				179.0
Revisions of previous estimates			(4.0	)			(9.3	)			(139.5	)			(36.6	)
Extensions, discoveries, and other additions			1.9				3.8				43.6				13.0
Purchases of minerals in place			–				–				–				–
Production			(3.8	)			(5.3	)			(65.5	)			(20.0	)
Sales			(0.1	)			–				(0.7	)			(0.2	)
Proved Reserves, at December 31, 2015			16.7				37.7				484.9				135.2

Estimated 2015 year-end proved reserves included proved developed
reserves of 115 MMBoe, or 692 Bcfe, (13% oil, 27% NGLs, and 60% natural
gas) and proved undeveloped reserves of 20 MMBoe, or 120 Bcfe, (10% oil,
33% NGLs, and 57% natural gas). Overall, 85% of Unit’s estimated proved
reserves are proved developed.

The present value of the estimated future net cash flows from the 2015
estimated proved reserves (before income taxes and using a 10% discount
rate (PV-10)), is approximately $690.7 million. The present value was
determined using the required SEC’s pricing methodology. The aggregate
price used for all future reserves was $50.28 per barrel of oil, $19.47
per barrel of NGLs, and $2.59 per Mcf of natural gas (then adjusted for
price differentials). Unit’s 2015 year-end proved reserves were
independently audited by Ryder Scott Company, L.P. Their audit covered
properties which accounted for 81% 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.

Pinkston said: “The reduced commodity prices for oil (47%), NGLs (57%),
and natural gas (41%) used to calculate our reserves as compared to year
end 2014 had a substantial impact on our reserves. Reserve revisions
were primarily due to pricing. Our proved undeveloped reserves have
decreased to 15% of total proved reserves at the end of 2015 as compared
to 24% at the end of the prior year. Although current pricing has
rendered a number of our oil and natural gas properties uneconomic, the
reserves remain in place to be developed in a more favorable pricing
environment.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 27.2, a
decrease of 66% from the fourth quarter of 2014, and a decrease of 13%
from the third quarter of 2015. Per day drilling rig rates for the
quarter averaged $18,604, a decrease of 9% from the fourth quarter of
2014 and a 1% decrease from the third quarter of 2015. Average per day
operating margin for the quarter was $7,258 (before elimination of
intercompany drilling rig profit and bad debt expense of $0.3 million).
This compares to $8,834 (before elimination of intercompany drilling rig
profit and bad debt expense of $8.7 million) for the fourth quarter of
2014, a decrease of 18%, or $1,576. As compared to $10,368 (before
elimination of intercompany drilling rig profit and bad debt expense of
$0.2 million) for the third quarter of 2015, fourth quarter 2015
operating margin decreased 30% or $3,110, principally due to lower early
termination fees (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 $3.3 million, or $1,327 per day,
from the cancellation of certain long-term contracts, compared to early
termination fees of $0.2 million, or $27 per day, during the fourth
quarter of 2014 and $11.4 million, or $3,958 per day, for the third
quarter of 2015.

Pinkston said: “During the first half of 2015, we completed the
construction of five BOSS drilling rigs that were contracted and placed
into service, bringing our total BOSS drilling rig count to eight. With
the decline in commodity prices, drilling rig demand also declined
throughout the year. During the fourth quarter, we were notified of a
customer’s intent to terminate early the contract on one of our BOSS
drilling rigs, which was subsequently laid down in January of 2016.
Currently, we have seven of our eight BOSS drilling rigs under contract.
Our current drilling rig fleet totals 94 drilling rigs, of which 20 are
working under contract. Long-term contracts (contracts with original
terms ranging from six months to two years in length) are in place for
nine of our drilling rigs. Of the nine long-term contracts, two are up
for renewal during the first quarter of 2016, three during the third
quarter, and four in 2017. Unit has focused on safety performance for
many years to keep our employees safe and to provide an efficient
operation. In 2015, we achieved our best safety performance in the
company’s history. The reduction of safety incidents also leads to
substantial savings in our daily costs.”

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, 2015				Dec 31, 2014				Change					Dec 31, 2015				Sept 30, 2015				Change					Dec 31, 2015				Dec 31, 2014				Change
Rigs Utilized						27.2				80.9			(66	)%					27.2				31.2			(13	)%					34.7				75.4			(54	)%
Operating Profit Before Depreciation & Impairment (MM) (1)					$	17.9			$	57.1			(69	)%				$	17.9			$	29.5			(39	)%				$	109.3			$	201.6			(46	)%
(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 gas gathered and gas processed volumes
increased 10% and 4%, respectively, while liquids sold volumes decreased
18% as compared to the fourth quarter of 2014. Compared to the third
quarter of 2015, gas gathered volumes per day increased 1% while gas
processed and liquids sold volumes per day decreased 8% and 3%,
respectively. Operating profit (as defined in the footnote below) for
the quarter was $9.4 million, a decrease of 6% from the fourth quarter
of 2014 and a decrease of 10% from the third quarter of 2015.

For 2015, per day gas gathered and gas processed volumes increased 11%
and 13%, respectively, while liquids sold volumes decreased 21% as
compared to 2014. Operating profit (as defined in the footnote below)
for 2015 was $41.2 million, a decrease of 15% from 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, 2015				Dec 31, 2014				Change					Dec 31, 2015				Sept 30, 2015				Change					Dec 31, 2015				Dec 31, 2014				Change
Gas Gathering, Mcf/day						360,159				327,331			10	%					360,159				357,427			1	%					353,771				319,348			11	%
Gas Processing, Mcf/day						170,087				163,979			4	%					170,087				185,625			(8	)%					182,684				161,282			13	%
Liquids Sold, Gallons/day						561,941				687,713			(18	)%					561,941				579,556			(3	)%					577,513				733,406			(21	)%
Operating Profit Before Depreciation, Amortization & Impairment (MM) (1)					$	9.4			$	10.0			6	%				$	9.4			$	10.4			(10	)%				$	41.2			$	49.5			(17	)%
(1)		Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment.

Pinkston said: “In the Appalachian area, we completed the expansion of
the Pittsburgh Mills pipeline in Butler County, Pennsylvania. That
system includes approximately seven miles of pipeline, the new Clinton
compressor station, and provides an additional outlet for the gas, all
of which became operational in the fourth quarter. We completed the
construction of our new fee-based Snow Shoe gathering system, located in
Centre County, Pennsylvania, and it became operational in January 2016.
At our various gas processing facilities in the Mid-Continent, we
continue to operate in full ethane rejection mode due to low liquids
prices, which continues to impact our liquids sold volumes.”

2016 CAPITAL BUDGET & PRODUCTION GUIDANCE

Pinkston said: “We have continued to see a great deal of commodity price
volatility during the last few months. Our focus has been and will
continue to be on maintaining a strong balance sheet. Our goal in 2016
is to keep our total corporate capital budget within anticipated cash
flow with the objective we end the year with lower bank debt than we
began the year. We have established our initial capital budget with that
goal in mind, recognizing we may need to adjust it as future conditions
may warrant.”

Unit’s overall capital budget is 59% to 65% less as compared to 2015,
excluding acquisitions and asset retirement obligation liability. The
reduction is designed to keep the budget below anticipated internally
generated cash flow plus proceeds from any non-core asset sales. The
range of capital expenditures will depend on prevailing conditions. The
capital budget is allocated as follows between Unit’s three business
segments: a range of $109.0 million to $131.0 million for its oil and
natural gas segment; $9.0 million to $11.0 million for its contract
drilling segment; and $22.0 million to $24.0 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
$35.00 per barrel of oil, $14.55 per barrel of natural gas liquids, and
$2.25 per Mcf of natural gas (all prices are before differentials and
hedges applied). Funding for the budget will come primarily from
internally generated cash flow, proceeds from possible additional
non-core asset divestitures, and (if necessary) borrowings under Unit’s
bank credit facility.

Unit’s oil and natural gas segment’s 2016 production is anticipated to
decline on a year over year basis by 13% to 16%. Approximately 3% of
this decline is attributable to two of the non-core asset packages sold
in early 2016. The balance of the decline is attributable to the
reduction in this segment’s capital budget. In view of current pricing,
it is anticipated that this segment will cease all drilling activity by
the end of the first quarter, pending the company’s evaluation of future
industry conditions.

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $927.7 million (consisting
of $646.7 million of senior subordinated notes net of unamortized
discount and $281.0 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 ($500 million) or the
value of its borrowing base as determined by the lenders ($550 million),
but in either event not to exceed $550 million. At February 12, 2016,
Unit had $262.9 million of borrowings under its credit agreement.

WEBCAST

Unit will webcast its fourth quarter earnings conference call live over
the Internet on February 25, 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 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 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.

Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
			Three Months Ended											Twelve Months Ended
			December 31,											December 31,
			2015					2014						2015					2014
Statement of Operations:
Revenues:
Oil and natural gas			$	75,830				$	164,903					$	385,774				$	740,079
Contract drilling				50,554					134,987						265,668					476,517
Gas gathering and processing				45,908					78,661						202,789					356,348
Total revenues				172,292					378,551						854,231					1,572,944
Expenses:
Oil and natural gas:
Operating costs				36,175					53,937						166,046					187,916
Depreciation, depletion, and amortization				49,566					75,130						251,944					276,088
Impairment of oil and natural gas properties				458,295					76,683						1,599,348					76,683
Contract drilling:
Operating costs				32,691					77,908						156,408					274,933
Depreciation				13,602					24,176						56,135					85,370
Impairment of contract drilling equipment				–					74,318						8,314					74,318
Gas gathering and processing:
Operating costs				36,475					68,665						161,556					306,831
Depreciation and amortization				11,158					10,462						43,676					40,434
Impairment of gas gathering and processing systems				26,966					7,068						26,966					7,068
General and administrative				8,708					11,614						35,345					42,023
(Gain) loss on disposition of assets				959					139						7,229					(8,953	)
Total operating expenses				674,595					480,100						2,512,967					1,362,711
Income (loss) from operations				(502,303	)				(101,549	)					(1,658,736	)				210,233
Other income (expense):
Interest, net				(8,481	)				(5,170	)					(31,963	)				(17,371	)
Gain (loss) on derivatives not designated as hedges				13,428					39,381						26,345					30,147
Other				7					(73	)					45					(70	)
Total other income (expense)				4,954					34,138						(5,573	)				12,706
Income (loss) before income taxes				(497,349	)				(67,411	)					(1,664,309	)				222,939
Income tax expense (benefit):
Current				(18,900	)				(14,343	)					(20,616	)				9,378
Deferred				(169,112	)				(10,517	)					(606,332	)				77,285
Total income taxes				(188,012	)				(24,860	)					(626,948	)				86,663
Net income (loss)			$	(309,337	)			$	(42,551	)				$	(1,037,361	)			$	136,276
Net income (loss) per common share:
Basic			$	(6.29	)			$	(0.88	)				$	(21.12	)			$	2.80
Diluted			$	(6.29	)			$	(0.88	)				$	(21.12	)			$	2.78
Weighted average shares outstanding:
Basic				49,157					48,656						49,110					48,611
Diluted				49,157					48,656						49,110					49,083

			December 31,					December 31,
			2015					2014
Balance Sheet Data:
Current assets			$	140,258				$	252,491
Total assets			$	2,808,509				$	4,473,728
Current liabilities			$	150,891				$	304,171
Long-term debt			$	927,662				$	812,163
Other long-term liabilities			$	140,626				$	148,785
Deferred income taxes			$	275,750				$	876,215
Shareholders’ equity			$	1,313,580				$	2,332,394
			Twelve Months Ended December 31,
			2015					2014
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities			$	397,859				$	764,984
Net change in operating assets and liabilities				49,085					(55,991	)
Net cash provided by operating activities			$	446,944				$	708,993
Net cash used in investing activities			$	(549,778	)			$	(920,597	)
Net cash provided by financing activities			$	102,620				$	194,060

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 exploration and production segment’s
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, 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 and twelve months ended December 31,
2015 and 2014. 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											Twelve Months Ended
			December 31,											December 31,
			2015					2014						2015					2014
			(In thousands except earnings per share)
Adjusted net income:
Net income (loss)			$	(309,337	)			$	(42,551	)				$	(1,037,361	)			$	136,276
Impairment adjustment (net of income tax)				302,075					98,398						1,017,556					98,398
(Gain) loss on derivatives not designated as hedges (net of income tax)				(8,363	)				(24,088	)					(16,421	)				(18,429	)
Settlements during the period of matured derivative contracts (net of income tax)				8,995					7,944						29,055					(3,691	)
Adjusted net income (loss)			$	(6,630	)			$	39,703					$	(7,171	)			$	212,554
Adjusted diluted earnings per share:
Diluted earnings (loss) per share			$	(6.29	)			$	(0.88	)				$	(21.12	)			$	2.78
Diluted earnings per share from the impairments				6.15					2.02						20.72					2.01
Diluted earnings per share from the (gain) loss on derivatives				(0.18	)				(0.51	)					(0.34	)				(0.38	)
Diluted earnings (loss) per share from the settlements of matured derivative contracts				0.18					0.17						0.59					(0.08	)
Adjusted diluted earnings (loss) per share			$	(0.14	)			$	0.80					$	(0.15	)			$	4.33

________________

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, 2015

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:

				2015
				(In millions)
PV-10 at December 31, 2015				$	690.7
Discounted effect of income taxes					(101.2	)
Standardized Measure at December 31, 2015				$	589.5

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,
			2015				2015				2014					2015				2014
			(In thousands except for operating days and operating margins)
Contract drilling revenue			$	65,022			$	50,554			$	134,987				$	265,668			$	476,517
Contract drilling operating cost				35,486				32,691				77,908					156,408				274,933
Operating profit from contract drilling				29,536				17,863				57,079					109,260				201,584
Add:
Elimination of intercompany rig profit and bad debt expense				219				325				8,669					3,991				29,343
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense				29,755				18,188				65,748					113,251				230,927
Contract drilling operating days				2,870				2,506				7,443					12,681				27,516
Average daily operating margin before elimination of intercompany rig profit and bad debt expense			$	10,368			$	7,258			$	8,834				$	8,931			$	8,392

________________

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,
			2015					2014
			(In thousands)
Net cash provided by operating activities			$	446,944				$	708,993
Net change in operating assets and liabilities				(49,085	)				55,991
Cash flow from operations before changes in operating assets and liabilities			$	397,859				$	764,984

________________

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
Reconciliation of EBITDA and Adjusted EBITDA
			Three Months Ended											Twelve Months Ended
			December 31,											December 31,
			2015					2014						2015					2014
			(In thousands except earnings per share)
Net income (loss)			$	(309,337	)			$	(42,551	)				$	(1,037,361	)			$	136,276
Income taxes				(188,012	)				(24,860	)					(626,948	)				86,663
Depreciation, depletion and amortization				75,091					110,531						354,830					404,943
Impairments				485,261					158,069						1,634,628					158,069
Interest expense				8,481					5,170						31,963					17,371
(Gain) loss on derivatives not designated as hedges				(13,428	)				(39,381	)					(26,345	)				(30,147	)
Settlements during the period of matured derivative contracts				14,459					12,946						46,615					(6,038	)
(Gain) loss on disposition of assets				959					139						7,229					(8,953	)
Adjusted EBITDA			$	73,474				$	180,063					$	384,611				$	758,184
Diluted earnings (loss) per share			$	(6.29	)			$	(0.88	)				$	(21.12	)			$	2.78
Diluted earnings per share from income taxes				(3.83	)				(0.50	)					(12.77	)				1.77
Diluted earnings per share from depreciation , depletion and amortization				1.50					2.25						7.20					8.25
Diluted earnings per share from impairments				9.90					3.22						33.28					3.22
Diluted earnings per share from interest expense				0.17					0.11						0.65					0.35
Diluted earnings per share from the (gain) loss on derivatives not designated as hedges				(0.27	)				(0.80	)					(0.53	)				(0.61	)
Diluted earnings per share from the settlements during the period of matured derivative contracts				0.29					0.25						0.94					(0.13	)
Diluted earnings per share (gain) loss on disposition of assets				0.02					0.01						0.15					(0.18	)
Adjusted EBITDA per diluted share			$	1.49				$	3.66					$	7.80				$	15.45

________________

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.

View source version on businesswire.com: http://www.businesswire.com/news/home/20160225005409/en/

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