Unit Corporation Reports 2016 First Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the first quarter 2016. Highlights include:

Realized net proceeds of $37.4 million from the sale of various
non-core oil and natural gas segment asset packages.
Crude oil production per day increased 3% compared to the fourth
quarter of 2015.
Midstream segment gas gathered volumes per day increased 15% compared
to the first quarter of 2015.
Midstream segment connected additional well pads to its Pittsburgh
Mills gathering line in Butler County, Pennsylvania, and commenced
operations of its new fee-based Snow Shoe gathering system in Centre
County, Pennsylvania.
Following the end of the quarter, Unit successfully amended its bank
credit agreement.

FIRST QUARTER 2016 FINANCIAL RESULTS

Adjusted net loss (which excludes the effect of non-cash commodity
derivatives and the effect of the non-cash write-down) was $20.3
million, or $0.41 per share (see Non-GAAP financial measures below). Low
commodity prices continued to negatively impact the company’s financial
results. For the quarter, Unit incurred a pre-tax non-cash ceiling test
write-down of $37.8 million in the carrying value of its oil and natural
gas properties. Although this write-down was a non-cash item, it
resulted in Unit recording a net loss of $41.1 million, or $0.83 per
share, compared to a net loss of $248.4 million, or $5.07 per share, for
the first quarter of 2015. Total revenues were $136.2 million (43% oil
and natural gas, 28% contract drilling, and 29% mid-stream), compared to
$255.1 million (42% oil and natural gas, 37% contract drilling, and 21%
mid-stream) for the first quarter of 2015. Adjusted EBITDA was $48.9
million, or $0.98 per diluted share (see Non-GAAP financial measures
below).

Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“Recently, we successfully completed the amendment of our credit
agreement. Our borrowing base was reset at $475 million, which provides
ample liquidity to meet our needs during the present commodity cycle. We
also modified our maximum leverage covenant from four times EBITDA to a
maximum senior leverage covenant not to exceed 2.75 times EBITDA through
the first quarter of 2019. We are pleased with this outcome and
appreciate the continued support of our bank group.”

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total equivalent production was 4.5 million barrels of
oil equivalent (MMBoe), a decrease of 12% from the first quarter of 2015
and a 5% decrease from the fourth quarter of 2015. Liquids (oil and
NGLs) production represented 46% of total equivalent production. Oil
production was 8,821 barrels per day, a decrease of 28% from the first
quarter of 2015 and an increase of 3% over the fourth quarter of 2015.
NGLs production was 14,188 barrels per day, a decrease of 1% from the
first quarter of 2015 and a 1% decrease from the fourth quarter of 2015.
Natural gas production was 159,585 thousand cubic feet (Mcf) per day, a
decrease of 12% from the first quarter of 2015 and a decrease of 8% from
the fourth quarter of 2015.

Unit’s average realized per barrel equivalent price was $13.67, a
decrease of 38% from the first quarter of 2015 and a 26% decrease from
the fourth quarter of 2015. Unit’s average natural gas price was $1.87
per Mcf, a decrease of 36% from the first quarter of 2015 and a decrease
of 17% from the fourth quarter of 2015. Unit’s average oil price was
$32.50 per barrel, a decrease of 33% from the first quarter of 2015 and
a decrease of 33% from the fourth quarter of 2015. Unit’s average NGLs
price was $6.59 per barrel, a 24% decrease from the first quarter of
2015 and a decrease of 40% from the fourth quarter of 2015. All prices
in this paragraph include the effects of derivative contracts.

During the quarter, in the Wilcox play, Unit drilled and completed four
horizontal wells, two in the Gilly field and two others in nearby
fields. The results of the two Gilly field horizontal wells were strong
with 30 day IP rates of approximately 12.7 and 5.6 million cubic feet
equivalent (MMcfe) per day. The two Wilcox wells outside of the Gilly
field currently have insufficient data to provide 30 day IP rates.
Additionally, the company completed new behind pipe Wilcox intervals in
three existing vertical wells. The new well production coupled with the
behind pipe completion activities resulted in Wilcox production
increasing 3% over the fourth quarter of 2015. In accordance with
previously announced plans, the company ceased all drilling activity by
the end of the first quarter.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), Unit drilled four
wells and completed three wells during the quarter. For the three wells
that had sufficient data, the average 30 day IP rate is approximately
800 barrels of oil equivalent (Boe) per day, which is in line with the
company’s current type curve. The fourth well was completed in late
April and is currently in the early stages of flowing back. Per day oil
production in the SOHOT increased 3% quarter over quarter, primarily as
a result of the company’s Marchand drilling activities. Overall, SOHOT
equivalent production decreased 6% quarter over quarter, primarily as a
result of no new Medrano gas completions.

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


	Three Months Ended						Three Months Ended
	Mar 31, 2016		Mar 31, 2015		Change		Mar 31, 2016		Dec 31, 2015		Change
Oil and NGLs Production, MBbl		2,094		2,384	(12	)%		2,094		2,108	(1	)%
Natural Gas Production, Bcf		14.5		16.4	(11	)%		14.5		15.9	(9	)%
Production, MBoe		4,514		5,117	(12	)%		4,514		4,757	(5	)%
Production, MBoe/day		49.6		56.9	(13	)%		49.6		51.7	(4	)%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	1.87	$	2.94	(36	)%	$	1.87	$	2.24	(17	)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	6.59	$	8.65	(24	)%	$	6.59	$	11.05	(40	)%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	32.50	$	48.47	(33	)%	$	32.50	$	48.23	(33	)%
Realized Price / Boe ⁽¹⁾	$	13.67	$	21.99	(38	)%	$	13.67	$	18.54	(26	)%
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) ⁽²⁾	$	24.9	$	60.9	(59	)%	$	24.9	$	39.7	(37	)%

(1)		Realized price includes oil, NGLs, natural gas, and associated derivatives.
(2)		Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment.

Pinkston said: “We continue to work toward our objective to establish
hedge positions for both crude oil and natural gas that is 50% to 70% of
each year’s anticipated production. For the balance of our 2016 natural
gas production, we have achieved that objective. We will continue to add
to these positions for the balance of 2016 and 2017 as conditions
warrant.”

This table summarizes the outstanding derivative contracts.


	Crude
Period	Structure	Volume Bbl/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Apr’16 – Jun’16	Collar	5,150		$40.71		$49.88
Jul’16 – Sep’16	Collar	1,000		$40.00		$46.75
Jul’16 – Dec’16	Collar	1,450		$47.50		$56.40
Apr’16 – Dec’16	3-Way Collar	700		$46.50	$35.00	$57.00
Jul’16 – Dec’16	3-Way Collar ⁽¹⁾	700		$47.50	$35.00	$63.50
Jan’17 – Dec’17	3-Way Collar	750		$50.00	$37.50	$63.90
	Natural Gas
Period	Structure	Volume MMBtu/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Apr’16 – Dec’16	Swap	45,000	$2.596
Jan’17 – Dec’17	Swap	30,000	$2.905
Apr’16 – Dec’16	Collar	42,000		$2.40		$2.88
Jan-17 – Oct’17	Collar	10,000		$2.75		$2.95
Apr’16 – Dec’16	3-Way Collar	13,500		$2.70	$2.20	$3.26
Jan’17 – Dec’17	3-Way Collar	15,000		$2.50	$2.00	$3.32

(1)		Unit pays its counterparty a premium, which can be and is being deferred until settlement.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs working during the quarter was 20.6,
a decrease of 59% from the first quarter of 2015, and a decrease of 24%
from the fourth quarter of 2015. Per day drilling rig rates averaged
$18,392, a decrease of 9% from the first quarter of 2015 and a 1%
decrease from the fourth quarter of 2015. Average per day operating
margin was $5,651. This compares to the first quarter of 2015 average
operating margin of $10,253 (before elimination of intercompany drilling
rig profit and bad debt expense of $2.9 million), a decrease of 45%, or
$4,602. Compared to the fourth quarter of 2015 average operating margin
of $7,258 (before elimination of intercompany drilling rig profit and
bad debt expense of $0.3 million), first quarter 2016 operating margin
decreased 22%, or $1,607 (in each case regarding eliminating
intercompany drilling rig profit and bad debt expense – see Non-GAAP
financial measures below). Average operating margins for the quarter
included early termination fees of approximately $2.6 million, or $1,410
per day, from the cancellation of certain long-term contracts, compared
to early termination fees of $12.7 million, or $2,807 per day, during
the first quarter of 2015 and $3.3 million, or $1,327 per day, for the
fourth quarter of 2015.

Pinkston said: “With the continued decline in commodity prices during
the quarter, operators substantially reduced their capital expenditure
budgets resulting in our utilization rate continuing to fall during the
quarter. Currently, we have six of our eight BOSS drilling rigs under
contract. Our current drilling rig fleet totals 94 drilling rigs, of
which 13 are working under contract. Long-term contracts (contracts with
original terms ranging from six months to two years in length) are in
place for six of our drilling rigs. Of the six long-term contracts, one
is up for renewal during the third quarter of 2016, one during the
fourth quarter, and four in 2017.”

This table illustrates certain comparative results for the periods
indicated:


	Three Months Ended						Three Months Ended
	Mar 31, 2016		Mar 31, 2015		Change		Mar 31, 2016		Dec 31, 2015		Change
Rigs Utilized		20.6		50.1	(59	)%		20.6		27.2	(24	)%
Operating Profit Before Depreciation & Impairment (MM) ⁽¹⁾	$	10.6	$	43.3	(76	)%	$	10.6	$	17.9	(41	)%

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

MID-STREAM SEGMENT INFORMATION

For the quarter, per day gas gathered volumes increased 15%, while gas
processed and liquids sold volumes decreased 12% and 9%, respectively,
as compared to the first quarter of 2015. Compared to the fourth quarter
of 2015, gas gathered volumes per day increased 6% while gas processed
and liquids sold volumes per day decreased 2% and 8%, respectively.
Operating profit (as defined in the footnote below) for the quarter was
$8.1 million, a decrease of 17% from the first quarter of 2015 and a
decrease of 14% from the fourth quarter of 2015.

This table illustrates certain comparative results for the periods
indicated:


	Three Months Ended						Three Months Ended
	Mar 31, 2016		Mar 31, 2015		Change		Mar 31, 2016		Dec 31, 2015		Change
Gas Gathering, Mcf/day		383,405		334,278	15	%		383,405		360,159	6	%
Gas Processing, Mcf/day		167,048		189,160	(12	)%		167,048		170,087	(2	)%
Liquids Sold, Gallons/day		519,433		568,876	(9	)%		519,433		561,941	(8	)%
Operating Profit Before Depreciation, Amortization & Impairment (MM) ⁽¹⁾	$	8.1	$	9.8	(17	)%	$	8.1	$	9.4	(14	)%

(1)

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

Pinkston said: “We continue to see gains in gas gathered volumes at our
Segno system in the Wilcox in southeast Texas. In the Marcellus, we
connected additional well pads to our Pittsburgh Mills system in Butler
County, Pennsylvania and commenced operation of our new Snow Shoe system
in Centre County, Pennsylvania. Due to low liquids prices, our midstream
segment remained in full ethane rejection mode at our various gas
processing facilities in the Mid-Continent.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $898.7 million (consisting
of $638.5 million of senior subordinated notes net of unamortized
discount and debt issuance costs and $260.2 million of borrowings under
its credit agreement). Under the credit agreement, the amount Unit can
borrow is the lesser of the amount it elects as the commitment amount
($475 million) or the value of its borrowing base as determined by the
lenders ($475 million), but in either event not to exceed $875 million.
The credit agreement was amended after the first quarter to provide, in
part, for the $475 million redetermined borrowing base.

WEBCAST

Unit will webcast its first quarter earnings conference call live over
the Internet on May 5, 2016 at 10:00 a.m. Central Time (11:00 a.m.
Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm
at least fifteen minutes prior to the start of the call to download and
install any necessary audio software. For those who are not available to
listen to the live webcast, a replay will be available shortly after the
call and will remain on the site for 90 days.

Unit Corporation is a Tulsa-based, publicly held energy company engaged
through its subsidiaries in oil and gas exploration, production,
contract drilling, and gas gathering and processing. Unit’s Common Stock
is on the New York Stock Exchange under the symbol UNT. For more
information about Unit Corporation, visit its website at http://www.unitcorp.com.

FORWARD-LOOKING STATEMENT

This news release contains forward-looking statements within the meaning
of the private Securities Litigation Reform Act. All statements, other
than statements of historical facts, included in this release that
address activities, events, or developments that the Company expects,
believes, or anticipates will or may occur in the future are
forward-looking statements. Several risks and uncertainties could cause
actual results to differ materially from these statements, including
changes in commodity prices, the productive capabilities of the
Company’s wells, future demand for oil and natural gas, future 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
	March 31,
	2016			2015
Statement of Operations:
Revenues:
Oil and natural gas	$	58,274		$	106,069
Contract drilling		38,710			95,077
Gas gathering and processing		39,200			53,953
Total revenues		136,184			255,099
Expenses:
Oil and natural gas:
Operating costs		33,346			45,211
Depreciation, depletion, and amortization		31,832			77,118
Impairment of oil and natural gas properties		37,829			400,593
Contract drilling:
Operating costs		28,098			51,746
Depreciation		12,195			15,013
Gas gathering and processing:
Operating costs		31,066			44,175
Depreciation and amortization		11,459			10,694
General and administrative		8,715			9,370
Gain on disposition of assets		(192	)		(545	)
Total operating expenses		194,348			653,375

Loss from operations		(58,164	)		(398,276	)

Other income (expense):
Interest, net		(9,617	)		(7,240	)
Gain on derivatives		10,929			6,586
Other		(15	)		(2	)
Total other income (expense)		1,297			(656	)

Loss before income taxes		(56,867	)		(398,932	)

Income tax expense (benefit):
Current		–			65
Deferred		(15,718	)		(150,643	)
Total income taxes		(15,718	)		(150,578	)

Net loss	$	(41,149	)	$	(248,354	)

Net loss per common share:
Basic	$	(0.83	)	$	(5.07	)
Diluted	$	(0.83	)	$	(5.07	)

Weighted average shares outstanding:
Basic		49,880			48,977
Diluted		49,880			48,977


	March 31,		December 31,
	2016		2015
Balance Sheet Data:
Current assets	$	124,092	$	140,258
Total assets	$	2,681,088	$	2,799,842
Current liabilities	$	139,411	$	150,891
Long-term debt, net of unamortized discount and debt issuance costs	$	898,722	$	918,995
Other long-term liabilities	$	106,930	$	140,341
Deferred income taxes	$	254,800	$	275,750
Shareholders’ equity	$	1,281,040	$	1,313,580


	Three Months Ended March 31,
	2016			2015
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	36,349		$	116,304
Net change in operating assets and liabilities		34,364			44,005
Net cash provided by operating activities	$	70,713		$	160,309
Net cash used in investing activities	$	(37,486	)	$	(231,027	)
Net cash (used in) provided by financing activities	$	(33,323	)	$	70,533

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with
generally accepted accounting principles (“GAAP”). The Company believes
certain non-GAAP performance measures provide users of its financial
information and its management additional meaningful information to
evaluate the performance of the Company.

This press release includes net income (loss) and earnings (loss) per
share including impairment adjustments and the effect of the cash
settled commodity derivatives, its drilling segment’s average daily
operating margin before elimination of intercompany drilling rig profit
and bad debt expense, its cash flow from operations before changes in
operating assets and liabilities, and its reconciliation of net income
(loss) to adjusted EBITDA.

Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three months ended March 31, 2016 and 2015.
Non-GAAP financial measures should not be considered by themselves or a
substitute for results reported in accordance with GAAP.


Unit Corporation
Reconciliation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) per Share

	Three Months Ended
	March 31,
	2016			2015
	(In thousands except earnings per share)
Adjusted net income (loss):
Net loss	$	(41,149	)	$	(248,354	)
Impairment adjustment (net of income tax)		23,549			249,369
Gain on derivatives (net of income tax)		(7,908	)		(4,024	)
Settlements during the period of matured derivative contracts (net of income tax)		5,167			6,728
Adjusted net income (loss)	$	(20,341	)	$	3,719

Adjusted diluted earnings (loss) per share:
Diluted loss per share	$	(0.83	)	$	(5.07	)
Diluted earnings per share from the impairments		0.48			5.09
Diluted earnings per share from the gain on derivatives		(0.16	)		(0.08	)
Diluted earnings (loss) per share from the settlements of matured derivative contracts		0.10			0.14
Adjusted diluted earnings (loss) per share	$	(0.41	)	$	0.08

________________

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

It uses the adjusted net income (loss) to evaluate the operational
performance of the Company.
The adjusted net income (loss) is more comparable to earnings
estimates provided by securities analysts.


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

	Three Months Ended
	December 31,		March 31,
	2015		2016		2015
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	50,554	$	38,710	$	95,077
Contract drilling operating cost		32,691		28,098		51,746
Operating profit from contract drilling		17,863		10,612		43,331
Add:
Elimination of intercompany rig profit and bad debt expense		325		–		2,910
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense		18,188		10,612		46,241
Contract drilling operating days		2,506		1,878		4,510
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	7,258	$	5,651	$	10,253

________________

The Company has included the average daily operating margin before
elimination of intercompany rig profit and bad debt expense because:

Its management uses the measurement to evaluate the cash flow
performance of its contract drilling segment and to evaluate the
performance of contract drilling management.
It is used by investors and financial analysts to evaluate the
performance of the Company.


Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities

	Three Months Ended March 31,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	70,713		$	160,309
Net change in operating assets and liabilities		(34,364	)		(44,005	)
Cash flow from operations before changes in operating assets and liabilities	$	36,349		$	116,304

________________

The Company has included the cash flow from operations before changes in
operating assets and liabilities because:

It is an accepted financial indicator used by its management and
companies in the industry to measure the Company’s ability to generate
cash which is used to internally fund its business activities.
It is used by investors and financial analysts to evaluate the
performance of the Company.


Unit Corporation
Reconciliation of EBITDA and Adjusted EBITDA

	Three Months Ended
	March 31,
	2016			2015
	(In thousands except earnings per share)

Net loss	$	(41,149	)	$	(248,354	)
Income taxes		(15,718	)		(150,578	)
Depreciation, depletion and amortization		56,116			103,590
Impairment		37,829			400,593
Interest expense		9,617			7,240
Gain on derivatives		(10,929	)		(6,586	)
Settlements during the period of matured derivative contracts		7,140			11,012
Stock compensation plans		4,798			5,863
Other non-cash items		1,405			1,480
Gain on disposition of assets		(192	)		(545	)
Adjusted EBITDA	$	48,917		$	123,715

Diluted loss per share	$	(0.83	)	$	(5.07	)
Diluted earnings per share from income taxes		(0.32	)		(3.07	)
Diluted earnings per share from depreciation, depletion and amortization		1.12			2.11
Diluted earnings per share from impairments		0.77			8.17
Diluted earnings per share from interest expense		0.19			0.15
Diluted earnings per share from the gain on derivatives		(0.22	)		(0.13	)
Diluted earnings per share from the settlements during the period of matured derivative contracts		0.14			0.22
Diluted earnings per share from stock compensation plans		0.10			0.12
Diluted earnings per share from other non-cash items		0.03			0.03
Diluted earnings per share from the gain on disposition of assets		–			(0.01	)
Adjusted EBITDA per diluted share	$	0.98		$	2.52

________________

The Company has included the adjusted EBITDA excluding gain or loss on
disposition of assets and including only the cash settled commodity
derivatives because:

It uses the adjusted EBITDA to evaluate the operational performance of
the Company.
The adjusted EBITDA is more comparable to estimates provided by
securities analysts.

View source version on businesswire.com: http://www.businesswire.com/news/home/20160505005273/en/

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

Unit Corporation Reports 2016 First Quarter Results

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