Unit Corporation Reports 2017 Fourth Quarter and Year End Results

February 22, 2018

TULSA, Okla.–(BUSINESS WIRE)–Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the fourth quarter and year end 2017. Fourth
quarter and year end highlights include:

Fourth quarter net income of $89.2 million, which reflects an $81.3
million net tax benefit related to tax legislation enacted in the
quarter, and adjusted net income of $11.3 million.
Oil and natural gas segment production increased 6% over the third
quarter of 2017.
Total year-end 2017 proved oil and natural gas reserves increased 27%
over 2016.
Replaced 300% of 2017 production with new reserves.
Contract drilling segment placed its 10th BOSS rig into service in
2017; all ten BOSS rigs continuously operated under contract during
the year.
Average drilling rigs used in 2017 increased 72% over 2016.
Midstream segment increased liquids sold and gas processed volumes 10%
and 6%, respectively, over the third quarter.

FOURTH QUARTER AND YEAR END 2017 FINANCIAL RESULTS

Unit recorded net income of $89.2 million for the quarter, or $1.71 per
diluted share, compared to net income of $1.7 million, or $0.03 per
share, for the fourth quarter of 2016. Net income for the quarter
included an $81.3 million income tax benefit associated with the
revaluation of the net deferred tax liability due to the Tax Cuts and
Jobs Act (the Tax Act) enacted during the quarter by the U.S.
government. Adjusted net income (which excludes the effect of non-cash
commodity derivatives and the effect of the Tax Act) for the quarter was
$11.3 million, or $0.22 per diluted share (see Non-GAAP financial
measures below). Total revenues for the quarter were $204.8 million (49%
oil and natural gas, 23% contract drilling, and 28% midstream), compared
to $174.3 million (51% oil and natural gas, 19% contract drilling, and
30% midstream) for the fourth quarter of 2016. Adjusted EBITDA was $91.2
million, or $1.75 per diluted share (see Non-GAAP financial measures
below).

For 2017, Unit recorded net income of $117.8 million, or $2.28 per
diluted share, compared to a net loss of $135.6 million, or a loss of
$2.71 per share, for 2016. Net income for the year included the $81.3
million income tax benefit associated with the revaluation of the net
deferred tax liability due to the Tax Act. Unit recorded adjusted net
income (which excludes the effect of non-cash commodity derivatives and
the effect of the Tax Act) of $27.7 million, or $0.54 per diluted share
(see Non-GAAP financial measures below). Total revenues for the year
were $739.6 million (48% oil and natural gas, 24% contract drilling, and
28% midstream), compared to $602.2 million (49% oil and natural gas, 20%
contract drilling, and 31% midstream) for 2016. Adjusted EBITDA for 2017
was $315.7 million, or $6.10 per diluted share (see Non-GAAP financial
measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.3 million barrels of
oil equivalent (MMBoe), a 6% increase over the third quarter of 2017.
Oil and natural gas liquids (NGLs) production represented 46% of total
equivalent production. Oil production was 7,877 barrels per day. NGLs
production was 13,713 barrels per day. Natural gas production was 151.6
million cubic feet (MMcf) per day. Total production for 2017 was 16.0
MMBoe, a 7% decrease from 2016.

Unit’s average realized per barrel equivalent price for the quarter was
$23.25, a 13% increase over the third quarter of 2017. Unit’s average
natural gas price was $2.38 per Mcf, an increase of 1% over the third
quarter of 2017. Unit’s average oil price was $54.45 per barrel, an
increase of 15% over the third quarter of 2017. Unit’s average NGLs
price was $21.88 per barrel, an increase of 19% over the third quarter
of 2017. All prices in this paragraph include the effects of derivative
contracts.

In the Wilcox area, Unit continued its exploration and recompletion
programs during the quarter. In the Cherry Creek prospect, production
from the Trinity #1 well was brought online with an initial 30-day
production (IP30) rate of 6 MMcfe per day. The Trinity is a discovery
well with several additional zones to be developed. Unit is planning to
drill the second well in the prospect later in 2018. In the Brandt
prospect, Unit successfully drilled and completed a new discovery well,
the Engel #1, with an IP30 rate of 8.3 MMcfe per day. In addition, there
were 10 new behind pipe recompletions, increasing combined production
for those wells 16 MMcf per day and 500 barrels of oil per day at a cost
of $3 million. Unit's plan for 2018 is for 13-15 recompletions and 10
new wells (8 vertical and 2 horizontal).

In the Texas Panhandle Granite Wash area, during the quarter, Unit
completed the Dixon 5554 CXL #5H well and the Dixon 5554 CXL #6H well.
The Dixon 5554 CXL #6H is Unit's first extended length lateral well
targeting the B interval of the Granite Wash and had an IP30 rate of 9.4
MMcfe per day, which is above type curve expectations. Unit also drilled
three of its longest laterals to date, which range from 8,700 feet to
9,700 feet, targeting the C1 interval of the Granite Wash. The three
wells were completed in January and are in the early stages of flowing
back. Unit's plan is to continuously operate at least one drilling rig
in the Granite Wash during 2018, which is planned to result in 11 new
extended length lateral wells.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, during the
quarter, Unit completed two new Marchand horizontal wells. Production
for both wells was brought online in late November. The Nina #1-22H had
an IP30 rate of 1,114 Boe per day and the Schmidt #1-10H had an IP30
rate of 691 Boe per day, both of which are above type curve
expectations. Unit began drilling its first extended lateral Marchand
well, the Schenk Trust 1-17HXL, in late November. Production from this
well was brought online in late January with strong results at an IP20
rate of 2,468 Boe per day. During 2018, Unit plans to continue with a
one rig drilling program, which should result in nine new wells, with
six being extended lateral wells.

In western Oklahoma, Unit owns approximately 17,000 net acres in the
STACK play. Unit continues its effort to acquire and concentrate its
acreage position to facilitate horizontal well development, and Unit
plans to initiate drilling in this area during the first quarter of 2018.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Our
oil and natural gas segment had its third consecutive quarter of
production growth. We are very pleased to be on a solid production
growth trajectory. We continue to be encouraged by the results in each
of our three core areas. All three have provided rates of return that
compare favorably with other active basins."

This table illustrates certain comparative production, realized prices,
and operating profit for the periods indicated:

Three Months Ended	Three Months Ended	Twelve Months Ended
Dec 31, 2017	Dec 31, 2016	Change	Dec 31, 2017	Sept 30, 2017	Change	Dec 31, 2017	Dec 31, 2016	Change
Oil and NGLs Production, MBbl	1,986	1,983	—	%	1,986	1,876	6	%	7,453	7,988	(7	)%
Natural Gas Production, Bcf	13.9	13.4	4	%	13.9	13.1	7	%	51.3	55.7	(8	)%
Production, MBoe	4,310	4,209	2	%	4,310	4,057	6	%	15,996	17,277	(7	)%
Production, MBoe/day	46.8	45.8	2	%	46.8	44.1	6	%	43.8	47.2	(7	)%
Avg. Realized Natural Gas Price, Mcf (1)	$	2.38	$	2.37	—	%	$	2.38	$	2.36	1	%	$	2.46	$	2.07	19	%
Avg. Realized NGL Price, Bbl (1)	$	21.88	$	14.57	50	%	$	21.88	$	18.35	19	%	$	18.35	$	11.26	63	%
Avg. Realized Oil Price, Bbl (1)	$	54.45	$	46.14	18	%	$	54.45	$	47.29	15	%	$	49.44	$	40.50	22	%
Realized Price / Boe (1)	$	23.25	$	19.73	18	%	$	23.25	$	20.63	13	%	$	21.72	$	16.92	28	%
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2)	$	66.6	$	60.4	10	%	$	66.6	$	51.6	29	%	$	227.0	$	174.0	30	%

(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. (See Non-GAAP financial measures below.)

YEAR END 2017 ESTIMATED PROVED RESERVES

The discount rate (PV-10) value of Unit’s estimated year end 2017 proved
reserves increased 56% over 2016 to $897.5 million. Estimated year end
2017 proved oil and natural gas reserves were 149.8 MMBoe, or 898.6
billion cubic feet of natural gas equivalents (Bcfe), as compared with
117.8 MMBoe, or 706.6 Bcfe, at year end 2016, a 27% increase. Estimated
reserves were 13% oil, 30% NGLs, and 57% natural gas.

The following details the changes to Unit’s proved oil, NGLs, and
natural gas reserves during 2017:

Oil (MMbls)	NGLs (MMbls)	Natural Gas (Bcf)	Proved Reserves (MMBoe)
Proved Reserves, at December 31, 2016	15.7	34.5	405.6	117.8
Revisions of previous estimates	0.7	4.3	38.4	11.4
Extensions, discoveries, and other additions	3.9	10.3	101.6	31.1
Purchases of minerals in place	2.0	1.2	15.3	5.8
Production	(2.7	)	(4.7	)	(51.3	)	(16.0	)
Sales	(0.1	)	(0.1	)	(0.9	)	(0.3	)
Proved Reserves, at December 31, 2017	19.5	45.5	508.7	149.8

Estimated 2017 year-end proved reserves included proved developed
reserves of 113.0 MMBoe, or 677.8 Bcfe, (13% oil, 30% NGLs, and 57%
natural gas) and proved undeveloped reserves of 36.8 MMBoe, or 220.9
Bcfe, (13% oil, 33% NGLs, and 54% natural gas). Overall, 75% of the
estimated proved reserves are proved developed.

The present value of the estimated future net cash flows from 2017
estimated proved reserves (before income taxes and using a PV-10), is
approximately $897.5 million. The present value was determined using the
required SEC's pricing methodology. The aggregate price used for all
future reserves was $51.34 per barrel of oil, $31.83 per barrel of NGLs,
and $2.98 per Mcf of natural gas (then adjusted for price
differentials). Unit’s 2017 year-end proved reserves were independently
audited by Ryder Scott Company, L.P. Their audit covered properties
accounting for 86% 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: "Our goal is to replace at least 150% of each year's
production with new reserves. In 2017, we achieved our goal by replacing
300% of production with new reserves, our second highest production
replacement percentage in the last 15 years. We achieved this growth
while maintaining a capital expenditure program in line with cash flow."

CONTRACT DRILLING SEGMENT INFORMATION

Unit's average number of drilling rigs working during the quarter was
31.2, a decrease of 10% from the third quarter of 2017. Per day drilling
rig rates averaged $16,645, a 1% increase over the third quarter of
2017. Average per day operating margin for the quarter was $5,550
(before elimination of intercompany drilling rig profit of $0.6
million). This compares to third quarter 2017 average operating margin
of $5,495 (before elimination of intercompany drilling rig profit of
$0.6 million), an increase of 1%, or $55.

Pinkston said: “Our contract drilling segment's level of utilization
grew through the third quarter to a high of 36 operating rigs.
Utilization pared back in the fourth quarter as operators approached the
limits of their 2017 capital budgets. We have 95 drilling rigs in our
fleet after adding our tenth BOSS rig during the second quarter. All 10
of our BOSS rigs are under contract, and we currently have a total of 32
drilling rigs operating. 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 contracts, four are up for
renewal in the first quarter of 2018, three in the second quarter, one
in the fourth quarter and one in 2019.”

This table illustrates certain comparative results for the periods
indicated:

Three Months Ended	Three Months Ended	Twelve Months Ended
Dec 31, 2017	Dec 31, 2016	Change	Dec 31, 2017	Sept 30, 2017	Change	Dec 31, 2017	Dec 31, 2016	Change
Rigs Utilized	31.2	19.5	60	%	31.2	34.6	(10	)%	30.0	17.4	72	%
Operating Profit Before Depreciation (MM) (1)	$	15.3	$	11.6	31	%	$	15.3	$	16.9	(9	)%	$	52.1	$	33.9	54	%

(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation. (See Non-GAAP financial measures below.)

MIDSTREAM SEGMENT INFORMATION

For the quarter, gas processed and liquids sold volumes per day
increased 6% and 10%, respectively, while gas gathered volumes per day
remained relatively unchanged, as compared to the third quarter of 2017.
Operating profit (as defined in the footnote below) for the quarter was
$13.1 million, a decrease of 2% from the third quarter of 2017.

For 2017, per day gas gathered and gas processed volumes decreased 8%
and 11%, respectively, while liquids sold volumes remained relatively
unchanged as compared to 2016. Operating profit (as defined in the
footnote below) for 2017 was $51.7 million, an increase of 7% over 2016.

This table illustrates certain comparative results for the periods
indicated:

Three Months Ended	Three Months Ended	Twelve Months Ended
Dec 31, 2017	Dec 31, 2016	Change	Dec 31, 2017	Sept 30, 2017	Change	Dec 31, 2017	Dec 31, 2016	Change
Gas Gathering, Mcf/day	383,319	423,669	(10	)%	383,319	383,787	—	%	385,209	419,217	(8	)%
Gas Processing, Mcf/day	148,422	140,719	5	%	148,422	140,246	6	%	137,625	155,461	(11	)%
Liquids Sold, Gallons/day	581,874	535,253	9	%	581,874	530,028	10	%	534,140	536,494	—	%
Operating Profit Before Depreciation and Amortization (MM) (1)	$	13.1	$	14.7	(11	)%	$	13.1	$	13.3	(2	)%	$	51.7	$	48.3	7	%

(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and amortization. (See Non-GAAP financial measures below.)

Pinkston said: “Our midstream segment operated in ethane rejection mode
during the quarter at all processing facilities except Bellmon and
Cashion, where it is more beneficial to recover under the existing
contracts. Processing and liquids sold volumes reflected quarter over
quarter improvement due to increasing processing volumes at the Hemphill
and Cashion facilities. Overall, our midstream segment continues to post
solid results as operator activity levels increase; in fact, we set a
new record operating profit before depreciation and amortization for the
year.”

2018 CAPITAL BUDGET AND PRODUCTION GUIDANCE

Pinkston said: "The outlook for commodity prices continues to be
volatile. We continue to be diligent with our capital expenditure plans
to maintain our spending in line with anticipated cash flow plus any
proceeds derived from non-core asset sales. Our focus is to continue to
grow all three business segments while retaining the financial
discipline our shareholders have grown to expect."

Unit's 2018 capital expenditures budget is $352 million, which
represents a 27% increase over 2017, excluding acquisitions. The capital
expenditures plan by segment is: $272 million for the oil and natural
gas segment, $47 million for the contract drilling segment, and $32
million for the midstream segment, representing an increase of 26%, 30%
and 44%, respectively, over 2017. The budget for the year includes no
costs for potential acquisitions and is based on prices, after applying
differentials and hedges, averaging $53.19 per barrel for oil, $22.18
per barrel for NGLs, and $2.16 per Mcf for natural gas. As always,
Unit's capital budget is subject to periodic review based on prevailing
conditions.

In 2017, year over year production in Unit's oil and natural gas segment
declined 7%; however, in each of the last three quarters of 2017
production grew sequentially. It is anticipated that 2018 production
should grow to 17.1 to 17.4 MMBoe, or 7% to 9% year over year from 2017.

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $820.3 million, consisting
of $642.3 million of senior subordinated notes (net of unamortized
discount and debt issuance costs) and $178.0 million of borrowings under
the company's credit agreement. During October, Unit's borrowing base
was re-determined with no resulting change. 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).

WEBCAST

Unit uses its website to disclose material nonpublic information and for
complying with its disclosure obligations under Regulation FD. Those
disclosures will be included on its website in the 'Investor
Information' sections. Accordingly, investors should monitor that
portion of the website, besides following the press releases, SEC
filings, and public conference calls and webcasts.

Unit will webcast its fourth quarter earnings conference call live over
the Internet on February 22, 2018 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 before 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 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, the
potential productive capability of its prospective plays including the
STACK play, the number of additional shares (if any) it may sell under
its "at the market" offering, and other factors described occasionally
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,
2017	2016	2017	2016
Statement of Operations:
Revenues:
Oil and natural gas	$	101,503	$	87,903	$	357,744	$	294,221
Contract drilling	46,661	33,300	174,720	122,086
Gas gathering and processing	56,683	53,077	207,176	185,870
Total revenues	204,847	174,280	739,640	602,177
Expenses:
Operating costs:
Oil and natural gas	34,916	27,493	130,789	120,184
Contract drilling	31,387	21,665	122,600	88,154
Gas gathering and processing	43,621	38,424	155,483	137,609
Total operating costs	109,924	87,582	408,872	345,947
Depreciation, depletion, and amortization	57,712	48,925	209,257	208,353
Impairments	—	—	—	161,563
General and administrative	11,185	8,517	38,087	33,337
(Gain) loss on disposition of assets	826	(1,717	)	(327	)	(2,540	)
Total expenses	179,647	143,307	655,889	746,660
Income (loss) from operations	25,200	30,973	83,751	(144,483	)
Other income (expense):
Interest, net	(9,527	)	(9,604	)	(38,334	)	(39,829	)
Gain (loss) on derivatives not designated as hedges	(6,287	)	(18,039	)	14,732	(22,813	)
Other	7	318	21	307
Total other income (expense)	(15,807	)	(27,325	)	(23,581	)	(62,335	)
Income (loss) before income taxes	9,393	3,648	60,170	(206,818	)
Income tax expense (benefit):
Current	5	15	5	15
Deferred	(79,767	)	1,950	(57,683	)	(71,209	)
Total income taxes	(79,762	)	1,965	(57,678	)	(71,194	)
Net income (loss)	$	89,155	$	1,683	$	117,848	$	(135,624	)
Net income (loss) per common share:
Basic	$	1.74	$	0.03	$	2.31	$	(2.71	)
Diluted	$	1.71	$	0.03	$	2.28	$	(2.71	)
Weighted average shares outstanding:
Basic	51,394	50,081	51,113	50,029
Diluted	52,201	50,949	51,748	50,029

December 31,	December 31,
2017	2016
Balance Sheet Data:
Current assets	$	119,672	$	121,196
Total assets	$	2,581,452	$	2,479,303
Current liabilities	$	181,936	$	164,915
Long-term debt	$	820,276	$	800,917
Other long-term liabilities	$	100,203	$	103,479
Deferred income taxes	$	133,477	$	215,922
Shareholders’ equity	$	1,345,560	$	1,194,070
Twelve Months Ended December 31,
2017	2016
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	276,811	$	205,888
Net change in operating assets and liabilities	2,777	34,242
Net cash provided by operating activities	$	279,588	$	240,130
Net cash used in investing activities	$	(306,998	)	$	(110,971	)
Net cash provided by (used in) financing activities	$	27,218	$	(129,101	)

Non-GAAP Financial Measures

Unit Corporation reports its financial results under 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 excluding impairment adjustments, the effect of the cash settled
commodity derivatives and the effect of the tax benefit from the Tax
Act, its exploration and production segment’s reconciliation of PV-10 to
Standard Measure, its reconciliation of segment operating profit, 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,
2017 and 2016. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported under GAAP. This
Non-GAAP information should be considered by the reader besides, but not
instead of, the financial statements prepared under GAAP. The Non-GAAP
financial information presented may be determined or calculated
differently by other companies and may not be comparable to similarly
titled measures.

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,
2017	2016	2017	2016
(In thousands except earnings per share)
Adjusted net income:
Net income (loss)	$	89,155	$	1,683	$	117,848	$	(135,624	)
Impairment adjustment (net of income tax)	—	—	—	100,573
(Gain) loss on derivatives (net of income tax)	2,930	11,845	(8,949	)	14,960
Settlements during the period of matured derivative contracts (net of income tax)	517	(1,322	)	105	6,333
Tax Act income tax benefit	(81,307	)	—	(81,307	)	—
Adjusted net income (loss)	$	11,295	$	12,206	$	27,697	$	(13,758	)
Adjusted diluted earnings per share:
Diluted earnings (loss) per share	$	1.71	$	0.03	$	2.28	$	(2.71	)
Diluted earnings per share from the impairments	—	—	—	2.01
Diluted earnings per share from the (gain) loss on derivatives	0.06	0.23	(0.17	)	0.30
Diluted earnings (loss) per share from the settlements of matured derivative contracts	0.01	(0.03	)	—	0.12
Diluted earnings (loss) per share from the Tax Act income tax benefit	(1.56	)	—	(1.57	)	—
Adjusted diluted earnings (loss) per share	$	0.22	$	0.23	$	0.54	$	(0.28	)