Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the fourth quarter and year end 2016. Fourth
quarter and recent highlights include:

  • Net income of $1.7 million for the quarter.
  • To date, the contract drilling segment increased the number of
    drilling rigs in service from a low of 13 in the second quarter to 26,
    a 100% increase.
  • Contract drilling segment placed into service its ninth BOSS drilling
    rig.
  • Oil and natural gas segment resumed drilling activities in the fourth
    quarter with a drilling rig being placed into service in October in
    the Southern Oklahoma Hoxbar Oil Trend (SOHOT) play and a second
    drilling rig placed into service in December in the Granite Wash play.
  • Midstream segment started preliminary construction activities to
    connect the next well pad to its Pittsburgh Mills gathering system.
  • Reduced long-term debt by $53.7 million from the end of the third
    quarter, bringing the total 2016 reduction to $118.1 million.

FOURTH QUARTER AND YEAR END 2016 FINANCIAL RESULTS

Unit recorded net income of $1.7 million for the quarter, or $0.03 per
diluted share, compared to a net loss of $309.3 million, or $6.29 per
share, for the fourth quarter of 2015. During the fourth quarter of
2015, Unit incurred 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. Those non-cash ceiling test write-downs resulted from lower
commodity prices. Adjusted net income for the fourth quarter of 2016
(which excludes the effect of non-cash commodity derivatives) was $12.2
million, or $0.23 per diluted share (see Non-GAAP financial measures
below). Total revenues for the quarter were $174.3 million (51% oil and
natural gas, 19% contract drilling, and 30% midstream), compared to
$172.3 million (44% oil and natural gas, 29% contract drilling, and 27%
midstream) for the fourth quarter of 2015. Adjusted EBITDA for the
quarter was $80.7 million, or $1.58 per diluted share (see Non-GAAP
financial measures below).

For 2016, Unit recorded a net loss of $135.6 million, or $2.71 per
share, compared to a net loss of $1.0 billion, or $21.12 per share, for
2015. For the full year, Unit incurred pre-tax non-cash ceiling test
write-downs of $161.6 million in the carrying value of its oil and
natural gas properties, compared to Unit’s 2015 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. Unit recorded an adjusted
net loss (which excludes the effect of non-cash commodity derivatives
and the effect of the non-cash write-downs) of $13.8 million, or $0.28
per share, for 2016 (see Non-GAAP financial measures below). Total
revenues for the year were $602.2 million (49% oil and natural gas, 20%
contract drilling, and 31% midstream), compared to $854.2 million (45%
oil and natural gas, 31% contract drilling, and 24% midstream) for 2015.
Adjusted EBITDA for 2016 was $251.6 million, or $4.98 per diluted share
(see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

Total production for 2016 was 17.3 million barrels of oil equivalent
(MMBoe), a 14% decrease from 2015. For the quarter, total equivalent
production was 4.2 MMBoe, a decrease of 12% from the fourth quarter of
2015 and essentially unchanged from the third quarter of 2016. Liquids
(oil and NGLs) production represented 47% of total equivalent production
for the quarter. Oil production for the quarter was 7,762 barrels per
day, a decrease of 9% from the fourth quarter of 2015 and an increase of
2% over the third quarter of 2016. NGLs production for the quarter was
13,790 barrels per day, a decrease of 4% from the fourth quarter of 2015
and a 1% increase over the third quarter of 2016. Natural gas production
for the quarter was 145,202 thousand cubic feet (Mcf) per day, a
decrease of 16% from the fourth quarter of 2015 and essentially
unchanged from the third quarter of 2016.

Unit’s average realized per barrel equivalent price for the quarter was
$19.73, an increase of 6% over the fourth quarter of 2015 and an 8%
increase over the third quarter of 2016. Unit’s average natural gas
price for the quarter was $2.37 per Mcf, an increase of 6% over the
fourth quarter of 2015 and an increase of 3% over the third quarter of
2016. Unit’s average oil price for the quarter was $46.14 per barrel, a
decrease of 4% from the fourth quarter of 2015 and an increase of 8%
over the third quarter of 2016. Unit’s average NGLs price for the
quarter was $14.57 per barrel, a 32% increase over the fourth quarter of
2015 and an increase of 15% over the third quarter of 2016. All prices
in this paragraph include the effects of derivative contracts.

During the quarter, Unit continued its Wilcox recompletion and workover
program. There were 10 new behind pipe re-completions during the
quarter, which increased combined production on those wells by 9.8 MMcf
per day and 300 barrels of oil per day at a total capital cost of $3.0
million. During 2016, total production from the Wilcox play increased
22% over 2015. Unit’s plan for 2017 is for 10 – 15 Wilcox re-completions
and seven new wells (4 vertical and 3 horizontal).

In the SOHOT area, Unit resumed its drilling program in October drilling
and completing two Marchand horizontal wells. Production is being
monitored for a few months with plans to begin drilling additional wells
in the second quarter. Unit is planning a seven well program for the
balance of 2017.

Unit resumed drilling in the Granite Wash play in December drilling an
extended length lateral in the A2 interval of Buffalo Wallow that is
anticipated to be completed in late February. The Dixon 5554 XL #1H,
which was completed in the C1 interval, continues to perform at a rate
over 50% better than its type curve forecast. Unit’s plan is to
continuously operate at least one drilling rig in the Granite Wash
during 2017, which is planned to result in nine new extended length
lateral wells.

In all three core areas, Unit continues to look for opportunities to add
additional leasehold. Historically, Unit has generally succeeded in
replacing acreage developed in any year with additional new locations.

Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“During 2016, we saw the continued strong performance of our Wilcox
behind pipe recompletion and workover program. Wilcox production grew
during 2016, helping to partially offset our corporate decline during
the suspension of our drilling activities. All three of our core areas
have provided rates of return that compete very favorably with other
active basins.”

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,
2016

 

Dec 31,
2015

  Change

Dec 31,
2016

 

Sept 30,
2016

  Change

Dec 31,
2016

 

Dec 31,
2015

  Change
Oil and NGLs Production, MBbl       1,983     2,108   (6 )%   1,983     1,961   1 %   7,988     9,057   (12 )%
Natural Gas Production, Bcf       13.4     15.9   (16 )%   13.4     13.4   %   55.7     65.5   (15 )%
Production, MBoe       4,209     4,757   (12 )%   4,209     4,194   %   17,277     19,982   (14 )%
Production, MBoe/day       45.8     51.7   (12 )%   45.8     45.6   %   47.2     54.7   (14 )%
Avg. Realized Natural Gas Price, Mcf (1)     $ 2.37   $ 2.24   6 % $ 2.37   $ 2.29   3 % $ 2.07   $ 2.63   (21 )%
Avg. Realized NGL Price, Bbl (1)     $ 14.57   $ 11.05   32 % $ 14.57   $ 12.68   15 % $ 11.26   $ 10.12   11 %
Avg. Realized Oil Price, Bbl (1)     $ 46.14   $ 48.23   (4 )% $ 46.14   $ 42.79   8 % $ 40.5   $ 50.79   (20 )%
Realized Price / Boe (1)     $ 19.73   $ 18.54   6 % $ 19.73   $ 18.29   8 % $ 16.92   $ 20.92   (19 )%
Operating Profit Before Depreciation, Depletion, Amortization &
Impairment (MM) (2)
    $ 60.4   $ 39.7   52 %       $ 60.4   $ 52.8   14 %       $ 174.0   $ 219.7   (21 )%
(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.)
 

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’17 – Dec’17     3-Way Collar     3,750           $49.79     $39.58     $60.98
      Natural Gas
Period     Structure     Volume

MMBtu/Day

    Weighted
Average
Fixed Price
    Weighted
Average
Floor Price
    Weighted
Average
Subfloor Price
    Weighted
Average
Ceiling Price
Jan’17 – Mar’17     Swap     70,000     $3.044                  
Apr’17 – Oct’17     Swap     10,000     $3.505                  
Apr’17 – Dec’17     Swap     60,000     $2.960                  
Jan’18 – Dec’18     Swap     10,000     $3.025                  
Jan’17 – Dec’17     Basis Swap (1)     20,000     $(0.215)                  
Jan’18 – Dec’18     Basis Swap (1)     10,000     $(0.208)                  
Jan’17 – Oct’17     Collar     20,000           $2.88           $3.10
Jan’17 – Dec’17     3-Way Collar     15,000           $2.50     $2.00     $3.32
Nov’17 – Dec’17     3-Way Collar     10,000           $3.50     $2.75     $4.00
Jan’18 – Mar’18     3-Way Collar     50,000           $3.35     $2.65     $4.22
Apr’18 – Dec’18     3-Way Collar     10,000           $3.00     $2.50     $3.66
(1)   After December 31, 2016, the basis swaps for February through
October 2017 and April through October 2018 were liquidated for $0.6
million and $0.5 million, respectively.
 

YEAR END 2016 ESTIMATED PROVED RESERVES

The discount rate (PV-10) value of Unit’s estimated year-end 2016 proved
reserves decreased 17% from 2015 to $575.2 million. Estimated year-end
2016 proved oil and natural gas reserves were 117.8 MMBoe, or 706.6
billion cubic feet of natural gas equivalents (Bcfe), as compared with
135.2 MMBoe, or 811.4 Bcfe, at year-end 2015, a 13% decrease. Estimated
reserves were 13% oil, 29% NGLs, and 58% natural gas.

The following details the changes to Unit’s proved oil, NGLs, and
natural gas reserves during 2016:

   

 

Oil
(MMbls)

   

 

NGLs
(MMbls)

   

 

Natural Gas
(Bcf)

   

Proved
Reserves
(MMBoe)

           
Proved Reserves, at December 31, 2015 16.7 37.7 484.9 135.2
Revisions of previous estimates (0.5 ) (2.5 ) (31.7 ) (8.3 )

Extensions, discoveries, and other additions

2.5 4.3 38.4 13.2
Purchases of minerals in place 0.1 0.6 0.3
Production (3.0 ) (5.0 ) (55.7 ) (17.3 )
Sales (0.1 )           (30.9 )     (5.3 )
Proved Reserves, at December 31, 2016 15.7       34.5       405.6       117.8  
 

Estimated 2016 year-end proved reserves included proved developed
reserves of 99.1 MMBoe, or 594.4 Bcfe, (13% oil, 29% NGLs, and 58%
natural gas) and proved undeveloped reserves of 18.7 MMBoe, or 112.2
Bcfe, (16% oil, 32% NGLs, and 52% natural gas). Overall, 84% of the
estimated proved reserves are proved developed.

The present value of the estimated future net cash flows from the 2016
estimated proved reserves (before income taxes and using a PV-10), is
approximately $575.2 million. The present value was determined using the
required SEC’s pricing methodology. The aggregate price used for all
future reserves was $42.75 per barrel of oil, $19.74 per barrel of NGLs,
and $2.48 per Mcf of natural gas (then adjusted for price
differentials). Unit’s 2016 year-end proved reserves were independently
audited by Ryder Scott Company, L.P. Their audit covered properties
which accounted for 83% 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 suspension of drilling activities at the end of the
first quarter 2016, lower commodity prices, and divestitures during the
year resulted in the reduction of 2016’s total proved reserves as
compared to 2015. Lower pricing requirements caused the revisions to our
reserves. Our non-core asset divestitures also reduced our reserves by
approximately 5.3 MMBoe. Our proved undeveloped reserves were 16% of
total proved reserves at the end of 2016.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of Unit’s drilling rigs working during the quarter
was 19.5, a decrease of 28% from the fourth quarter of 2015 and an
increase of 22% over the third quarter of 2016. Per day drilling rig
rates for the quarter averaged $16,866, a decrease of 9% from the fourth
quarter of 2015 and a 4% decrease from the third quarter of 2016. For
2016, per day drilling rig rates averaged $17,784, a 9% decrease from
2015. Average per day operating margin for the quarter was $6,478 (with
no elimination of intercompany drilling rig profit and bad debt
expense). This compares to fourth quarter 2015 average operating margin
of $7,258 (before elimination of intercompany drilling rig profit and
bad debt expense of $0.3 million), a decrease of 11%, or $780. Fourth
quarter 2016 average per day operating margin increased 42%, or $1,932,
as compared to $4,546 for the third quarter of 2016 (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 2016 did not include early termination
fees from the cancellation of long-term contracts, compared to early
termination fees of $3.3 million, or $1,327 per day, during the fourth
quarter of 2015. There were no early termination fees for the third
quarter of 2016.

Pinkston said: “Construction for our ninth BOSS drilling rig was
completed, and currently all nine of our BOSS drilling rigs are
operating under contract. Commodity prices continued to increase during
the quarter, and the uptick in operator inquiries has led to more
contracts for our drilling rigs. Our fleet totals 94 drilling rigs, of
which 26 are working under contract after rebounding from a low of 13
drilling rigs during the second quarter of 2016. We also have contracts
for four additional drilling rigs to return to service during the first
quarter of 2017. Long-term contracts (contracts with original terms
ranging from six months to two years in length) are in place for 10 of
our drilling rigs. Of the 10, eight are up for renewal during 2017 and
two in 2018.”

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,
2016

 

Dec 31,
2015

  Change

Dec 31,
2016

 

Sept 30,
2016

  Change

Dec 31,
2016

 

Dec 31,
2015

  Change
Rigs Utilized       19.5     27.2   (28 )%   19.5     16.0   22 %   17.4     34.7   (50 )%
Operating Profit Before Depreciation & Impairment (MM) (1)     $ 11.6   $ 17.9   (35 )%       $ 11.6   $ 6.7   74 %       $ 33.9   $ 109.3   (69 )%
(1)   Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation and impairment. (See non-GAAP financial
measures below.)
 

MIDSTREAM SEGMENT INFORMATION

For the quarter, per day gas gathered volumes increased 18%, while gas
processed and liquids sold volumes decreased 17% and 5%, respectively,
as compared to the fourth quarter of 2015. Compared to the third quarter
of 2016, gas gathered, gas processed, and liquids sold volumes per day
decreased 1%, 8% and 4%, respectively. Operating profit (as defined in
the footnote below) for the quarter was $14.7 million, an increase of
55% over the fourth quarter of 2015 and an increase of 13% over the
third quarter of 2016.

For 2016, per day gas gathered volumes increased 18%, while gas
processed and liquids sold volumes per day decreased 15% and 7%,
respectively, as compared to 2015. Operating profit (as defined in the
footnote below) for 2016 was $48.3 million, an increase of 17% over 2015.

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,
2016

 

Dec 31,
2015

  Change

Dec 31,
2016

 

Sept 30,
2016

  Change

Dec 31,
2016

 

Dec 31,
2015

  Change
Gas Gathering, Mcf/day       423,669     360,159   18 %   423,669     429,693   (1 )%   419,217     353,771   18 %
Gas Processing, Mcf/day       140,719     170,087   (17 )%   140,719     152,651   (8 )%   155,461     182,684   (15 )%
Liquids Sold, Gallons/day       535,253     561,941   (5 )%   535,253     558,843   (4 )%   536,494     577,513   (7 )%
Operating Profit Before Depreciation, Amortization & Impairment (MM) (1)     $ 14.7   $ 9.4   55 %       $ 14.7   $ 13.0   13 %       $ 48.3   $ 41.2   17 %
(1)   Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation, amortization, and impairment. (See non-GAAP
financial measures below.)
 

Pinkston said: “Our midstream segment saw throughput volumes continue to
grow at both our Pittsburgh Mills and Segno (Wilcox) gathering systems
which partially offset declines on other gathering systems resulting
from reduced well drilling activity levels. Due to low liquids prices,
our midstream segment processing facilities in the Mid-Continent area
largely operated in ethane rejection mode during the quarter. Midstream
operating profit remained strong in 2016.”

2017 CAPITAL BUDGET & PRODUCTION GUIDANCE

Pinkston said: “The commodity price outlook appears to show signs of
improvement. While our balance sheet has improved over last year, we
continue to be cautious in developing our capital expenditures plan for
2017. It is our intention to match expected anticipated cash flow with
our capital expenditures for the year.”

During 2017, Unit’s capital expenditures budget is anticipated to be
$227 million, which represents a 32% increase over 2016. The capital
expenditures plan by segment is: $188 million for the oil and natural
gas segment, $24 million for the contract drilling segment, and $13
million for the midstream segment, representing an increase of 57%, 25%,
and a decrease of 23%, respectively, from 2016. The budget includes no
costs for potential acquisitions and is based on realized prices for the
year averaging $53.37 per barrel for oil, $21.35 per barrel for natural
gas liquids, and $3.00 per Mcf of natural gas (all prices are before
differentials and hedges are applied). As always, Unit’s capital budget
is subject to periodic review based on prevailing conditions.

With the curtailment of drilling activity during 2016, production
declined and ended the year down 13.5% year over year, at the low end of
guidance. Unit resumed drilling activities in the fourth quarter of
2016. Unit’s oil and natural gas segment’s 2017 production is
anticipated to trough in the first quarter of 2017 and begin growing
sequentially in subsequent quarters. Unit’s 2017 production is expected
to decline 5% to 8% year over year from 2016.

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $800.9 million (a
reduction of $53.7 million from the end of the third quarter and $118.1
million from the end of 2015). Long-term debt is comprised of $640.1
million of senior subordinated notes (net of unamortized discount and
debt issuance costs) and $160.8 million of bank credit facility
borrowings. During October, Unit’s borrowing base was redetermined with
no change to availability. 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.

RETIREMENT OF EXECUTIVE OFFICER

On February 21, 2017, Mr. Brad Guidry, Executive Vice President –
Exploration & Production, of the company’s wholly owned subsidiary Unit
Petroleum Company, announced his intention to retire effective March 31,
2017. Mr. Frank Young, Unit Petroleum’s current Senior Vice President –
Exploration & Production, is expected to replace Mr. Guidry on the
effective date of his retirement. Mr. Young joined Unit Petroleum in
June 2007 as Vice President over the Central Division. Since 2012, Mr.
Young has served as the Senior Vice President, Operations for Unit
Petroleum. Before joining Unit Petroleum, Mr. Young worked for Anadarko
Petroleum for 16 years where he served in various operating and
leadership capacities. Mr. Young holds a Bachelor of Science degree in
Petroleum Engineering from Texas Tech University and a Master of
Business Administration degree from Texas A&M University.

Pinkston said: “Brad has been a tremendous asset for the almost 30 years
he has been with us. His knowledge and leadership skills allowed him to
move quickly from a staff geologist to manager and finally to executive
vice president. He has had an incredible career here, and we will
greatly miss him. We believe that Mr. Young is a highly qualified
replacement for Mr. Guidry, and we look forward to his leadership for
our oil and natural gas segment.”

MANAGEMENT COMMENTS

Pinkston said: “We are pleased with our fourth quarter improved results.
We entered 2016 with an uncertain outlook for the direction of commodity
prices. As a result, we implemented a strategy of closely managing costs
and being careful with our balance sheet. We believe recent modest
commodity price improvements and the resulting positive impact on
industry sentiment has positioned our company for an improved 2017. Our
oil and natural gas segment is excited about having restarted its
drilling program after a period of inactivity. Our intention is to
increase our capital allocation to this segment and return to sequential
production growth, although it will take time to overcome the results of
that inactivity. Our Granite Wash drilling activities will not only
benefit our production profile but will also benefit our midstream
throughput volumes at our Buffalo Wallow facility. Our contract drilling
segment had seen a dramatic improvement in utilization from a low of 13
drilling rigs operating in the second quarter to current levels. We are
pleased with the pace of getting drilling rigs redeployed. Surprisingly,
we have seen spotty opportunities to increase dayrates very modestly.
Finally, the increased activity levels around our Buffalo Wallow, Segno
and Pittsburgh Mills midstream facilities bode well for that segment’s
ability to increase its gathering volumes in 2017. Additionally,
continued NGL price improvement should position the midstream segment to
increase its cash flow with minimal incremental capital cost.”

WEBCAST

Unit will webcast its fourth quarter earnings conference call live over
the Internet on February 23, 2017 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 Twelve Months Ended
December 31, December 31,
      2016     2015 2016     2015
Statement of Operations:    
Revenues:
Oil and natural gas $ 87,903 $ 75,830 $ 294,221 $ 385,774
Contract drilling 33,300 50,554 122,086 265,668
Gas gathering and processing   53,077     45,908     185,870     202,789  
Total revenues   174,280     172,292     602,177     854,231  
Expenses:
Operating costs:
Oil and natural gas 27,493 36,175 120,184 166,046
Contract drilling 21,665 32,691 88,154 156,408
Gas gathering and processing   38,424     36,475     137,609     161,556  
Total operating costs 87,582 105,341 345,947 484,010
 
Depreciation, depletion, and amortization 48,925 74,567 208,353 352,742
Impairments 485,261 161,563 1,634,628
General and administrative 8,517 8,467 33,337 34,358
(Gain) loss on disposition of assets   (1,717 )   959     (2,540 )   7,229  
Total expenses   143,307     674,595     746,660     2,512,967  
 
Income (loss) from operations   30,973     (502,303 )   (144,483 )   (1,658,736 )
 
Other income (expense):
Interest, net (9,604 ) (8,481 ) (39,829 ) (31,963 )
Gain (loss) on derivatives not designated as hedges (18,039 ) 13,428 (22,813 ) 26,345
Other   318     7     307     45  
Total other income (expense)   (27,325 )   4,954     (62,335 )   (5,573 )
 
Income (loss) before income taxes   3,648     (497,349 )   (206,818 )   (1,664,309 )
 
Income tax expense (benefit):
Current 15 (18,900 ) 15 (20,616 )
Deferred   1,950     (169,112 )   (71,209 )   (606,332 )
Total income taxes   1,965     (188,012 )   (71,194 )   (626,948 )
 
Net income (loss) $ 1,683   $ (309,337 ) $ (135,624 ) $ (1,037,361 )
 
Net income (loss) per common share:
Basic $ 0.03 $ (6.29 ) $ (2.71 ) $ (21.12 )
Diluted $ 0.03 $ (6.29 ) $ (2.71 ) $ (21.12 )
 
Weighted average shares outstanding:
Basic 50,081 49,157 50,029 49,110
Diluted 50,949 49,157 50,029 49,110
 
       
December 31, December 31,
      2016     2015
Balance Sheet Data:
Current assets $ 121,196 $ 140,258
Total assets $ 2,479,303 $ 2,799,842
Current liabilities $ 164,915 $ 150,891
Long-term debt $ 800,917 $ 918,995
Other long-term liabilities $ 103,479 $ 140,626
Deferred income taxes $ 215,922 $ 275,750
Shareholders’ equity $ 1,194,070 $ 1,313,580
 
 
Twelve Months Ended December 31,
      2016     2015
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and
liabilities
$ 205,888 $ 397,859
Net change in operating assets and liabilities   34,242     49,085  
Net cash provided by operating activities $ 240,130   $ 446,944  
Net cash used in investing activities $ (110,971 ) $ (549,778 )
Net cash provided by (used in) financing activities $ (129,101 ) $ 102,620  
 
 

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 excluding 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 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,
2016 and 2015. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported in accordance with GAAP.
This non-GAAP information should be considered by the reader in addition
to, but not instead of, the financial statements prepared in accordance
with 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,
2016     2015 2016     2015
(In thousands except earnings per share)
Adjusted net income:  
Net income (loss) $ 1,683 $ (309,337 ) $ (135,624 ) $ (1,037,361 )
Impairment adjustment (net of income tax) 302,075 100,573 1,017,556
(Gain) loss on derivatives (net of income tax) 11,845 (8,363 ) 14,960 (16,421 )
Settlements during the period of matured derivative contracts (net
of income tax)
  (1,322 )   8,995     6,333     29,055  
Adjusted net income (loss) $ 12,206   $ (6,630 ) $ (13,758 ) $ (7,171 )
 
Adjusted diluted earnings per share:
Diluted earnings (loss) per share $ 0.03 $ (6.29 ) $ (2.71 ) $ (21.12 )
Diluted earnings per share from the impairments 6.15 2.01 20.72
Diluted earnings per share from the (gain) loss on derivatives 0.23 (0.18 ) 0.30 (0.34 )
Diluted earnings (loss) per share from the settlements of matured
derivative contracts
  (0.03 )   0.18     0.12     0.59  
Adjusted diluted earnings (loss) per share $ 0.23   $ (0.14 ) $ (0.28 ) $ (0.15 )

________________

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, 2016

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:

    2016
(In millions)
PV-10 at December 31, 2016 $ 575.2
Discounted effect of income taxes   (57.0 )
Standardized Measure at December 31, 2016 $ 518.2  
 
         
Unit Corporation
Reconciliation of Segment Operating Profit
 
Three Months Ended Twelve Months Ended
September 30,     December 31, December 31,
2016 2016     2015 2016     2015
(In thousands)
Oil and natural gas $ 52,840 $ 60,410 $ 39,655 $ 174,037 $ 219,728
Contract drilling 6,682 11,635 17,863 33,932 109,260
Gas gathering and processing   12,997     14,653     9,433     48,261     41,233  
Total operating profit 72,519 86,698 66,951 256,230 370,221
Depreciation, depletion and amortization (50,441 ) (48,925 ) (74,567 ) (208,353 ) (352,742 )
Impairments   (49,443 )       (485,261 )   (161,563 )   (1,634,628 )
Total operating income (loss) (27,365 ) 37,773 (492,877 ) (113,686 ) (1,617,149 )
General and administrative (8,380 ) (8,517 ) (8,467 ) (33,337 ) (34,358 )
Gain (loss) on disposition of assets 154 1,717 (959 ) 2,540 (7,229 )
Interest, net (10,002 ) (9,604 ) (8,481 ) (39,829 ) (31,963 )
Gain (loss) on derivatives 6,969 (18,039 ) 13,428 (22,813 ) 26,345
Other   3     318     7     307     45  
Income (loss) before income taxes $ (38,621 ) $ 3,648   $ (497,349 ) $ (206,818 ) $ (1,664,309 )

________________

The Company has included segment operating profit because:

  • It considers segment operating profit to be an important supplemental
    measure of operating performance for presenting trends in its core
    businesses.
  • Segment operating profit is useful to investors because it provides a
    means to evaluate the operating performance of the segments and
    Company on an ongoing basis using criteria that is used by management.
         
 
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,
2016 2016     2015 2016     2015
(In thousands except for operating days and operating margins)
Contract drilling revenue $ 25,819 $ 33,300 $ 50,554 $ 122,086 $ 265,668
Contract drilling operating cost   19,137   21,665   32,691   88,154   156,408
Operating profit from contract drilling 6,682 11,635 17,863 33,932 109,260
Add:
Elimination of intercompany rig profit and bad debt expense       325   235   3,991
Operating profit from contract drilling before elimination of
intercompany rig profit and bad debt expense
6,682 11,635 18,188 34,167 113,251
Contract drilling operating days   1,470   1,796   2,506   6,374   12,681
Average daily operating margin before elimination of intercompany
rig profit and bad debt expense
$ 4,546 $ 6,478 $ 7,258 $ 5,360 $ 8,931

________________

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,

2016     2015
(In thousands)
Net cash provided by operating activities $ 240,130 $ 446,944
Net change in operating assets and liabilities   (34,242 )   (49,085 )
Cash flow from operations before changes in operating assets and
liabilities
$ 205,888   $ 397,859  

________________

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 Adjusted EBITDA
 
Three Months Ended Twelve Months Ended
December 31, December 31,
2016     2015 2016     2015
(In thousands except earnings per share)
 
Net income (loss) $ 1,683 $ (309,337 ) $ (135,624 ) $ (1,037,361 )
Income taxes 1,965 (188,012 ) (71,194 ) (626,948 )
Depreciation, depletion and amortization 48,925 74,567 208,353 352,742
Amortization of debt issuance costs and debt discounts 536 524 2,122 2,088
Impairments 485,261 161,563 1,634,628
Interest expense 9,604 8,481 39,829 31,963
(Gain) loss on derivatives 18,039 (13,428 ) 22,813 (26,345 )
Settlements during the period of matured derivative contracts (2,077 ) 14,459 9,658 46,615
Stock compensation plans 3,148 8,954 13,812 21,468
Other non-cash items 632 824 2,779 3,453
(Gain) loss on disposition of assets   (1,717 )   959     (2,540 )   7,229  
Adjusted EBITDA $ 80,738   $ 83,252   $ 251,571   $ 409,532  
 
Diluted earnings (loss) per share $ 0.03 $ (6.29 ) $ (2.71 ) $ (21.12 )
Diluted earnings per share from income taxes 0.04 (3.82 ) (1.42 ) (12.77 )

Diluted earnings per share from depreciation, depletion and
amortization

0.96 1.52 4.12 7.16
Diluted earnings per share from amortization of debt issuance costs
and debt discounts
0.01 0.01 0.04 0.04
Diluted earnings per share from impairments 9.86 3.24 33.28
Diluted earnings per share from interest expense 0.19 0.17 0.79 0.65
Diluted earnings per share from the (gain) loss on derivatives 0.35 (0.27 ) 0.45 (0.53 )
Diluted earnings per share from the settlements during the period of
matured derivative contracts
(0.04 ) 0.29 0.20 0.94
Diluted earnings per share from stock compensation plans 0.06 0.18 0.27 0.44
Diluted earnings per share from other non-cash items 0.01 0.02 0.05 0.07
Diluted earnings per share (gain) loss on disposition of assets   (0.03 )   0.02     (0.05 )   0.15  
Adjusted EBITDA per diluted share $ 1.58   $ 1.69   $ 4.98   $ 8.31  

________________

The Company has included the adjusted EBITDA, which excludes gain or
loss on disposition of assets and includes 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.

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