PIPELINE
ANNUAL
REPORT
2018
PRODUCTION
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CORPORATE PROFILE
Unit Corporation is a diversifi ed energy company engaged
through its subsidiaries in the exploration for and production of
oil and natural gas, the acquisition of producing oil and natural
gas properties, the contract drilling of onshore oil and natural
gas wells, and the gathering and processing of natural gas. Unit’s
common stock is traded on the New York Stock Exchange under
the symbol “UNT”.
CASPER OFFICE
PITTSBURGH OFFICE
DENVER OFFICE
Mississippian Basin
Anadarko Basin
TULSA HEADQUARTERS
Arkoma Basin
OKLAHOMA CITY OFFICE
CONTRACT DRILLING
Gulf Coast Basin
Permian Basin
OIL & NATURAL GAS
MIDSTREAM
HOUSTON OFFICE
FINANCIAL INFORMATION
Year Ended December 31, ($ in thousands)
2018
2017
Total Revenues
Capital Expenditures 1
$
$
843,281
476,252
Total Assets
$ 2,698,053
Long-Term Debt
$
644,475
$
$
$
$
Shareholders’ Equity
$
1,593,444
$
1,345,560
739,640
313,579
$
$
2016
602,177
186,713
$
$
2015
854,231
561,632
2014
$
$
1,572,944
987,097
2,581,452
$
2,479,303
$
2,799,842
$ 4,463,473
820,276
$
$
800,917
1,194,070
$
$
918,995
$
801,908
1,313,580
$
2,332,394
Total Capitalization
$
2,237,919
$
2,165,836
$
1,994,987
$
2,232,575
$
3,134,302
1Capital expenditures (cash basis) including acquisitions.
4
take advantage of growth opportunities it might not
otherwise have been able to, which will beneficially
reflect on our remaining interest in that segment.
In 2018, our exploration and production segment
reestablished its year-over-year oil and gas production
growth. Perhaps none of our segments more vividly
demonstrates our commitment to limit our spending
to cash flow than this one. Spending money does not
equate to cash flow any more than buying high priced
leasehold acreage in “hot plays” result in economic
production. We do not chase the latest highly sought-
after exploration plays with their high acreage costs,
much of which must be drilled or lost regardless of
the then prevailing commodity prices. Instead, we
focus on developing new prospective plays in areas
not necessarily within the “play of the moment.” This
long-term commitment provides us with many legacy
properties throughout the mid-continent. Our SOHOT
in the Hoxbar interval in western Oklahoma was
developed over several years. While developing that
area, we determined that other Penn sand intervals,
including the Red Fork, would likely be prospective. We
drilled our first horizontal Red Fork well in Oklahoma.
That test well was a huge success. During the fourth
quarter, we acquired approximately 2.6 MMBoe proved
reserves and approximately 30 potential horizontal
drilling locations in this play for just under $30 million.
The acquisition includes approximately 8,667 net acres
of which 82% is held by production.
Our contract drilling segment ended 2017 with 10
BOSS rigs in its fleet. Our 11th BOSS rig was placed into
service under a long-term contract in the third quarter
of 2018. During the year, we also obtained long-term
contracts for our 12th and 13th BOSS rigs placed into
service during the first quarter of 2019. Late in 2018, we
restructured the makeup of our rig fleet towards our
BOSS rigs, our already upgraded SCR electric rigs, and
some of our other existing SCR electric rigs that are
good candidates for upgrade. We removed 41 rigs from
our fleet at 2018 year-end and plan to sell those rigs in
2019. Our rig fleet now stands at 57 rigs.
We begin 2019 with the confidence sharpened by our
long history. Our current 2019 capital budget once
again falls within our anticipated cash flow for the year,
but is subject to change with a re-evaluation planned
at mid-year upon further analysis of current market
conditions. Our objective is to guide our company to
build value for you, our shareholders, our customers,
and our employees.
We are looking forward to a great 2019.
2 018 was our 55th anniversary year. Fifty-five years
in a tumultuous industry proves our built-for-the-
long-haul structure, a structure we take pride in.
Over those years, we have operated through more up
and down commodity price cycles than some of us can
even remember. But we learned something from each
experience. We learned that to succeed you need to stay
focused, not only during the difficult times, but just as
importantly during the good times. Our goal is to maintain
a strong balance sheet, and we primarily accomplish that
goal through our long-standing approach of working to
keep our capital spending in-line with our anticipated
cash flow— year in and year out. This approach is one
many of our industry partners have more recently come
to adopt.
Unit is comprised of three primary business segments:
contract drilling, mid-stream, and exploration and
production. Each has the singular objective to grow
successfully. But doing so brings increasing demands
for capital. That is where our tri-segment structure is
helpful as not all three segments are equally and timely
affected by the swings in our industry. At times, one
segment is able to generate excess cash flows, which
we can then re-allocate to fund the opportunities of the
others. At this time, our oil and natural gas segment can
best finance its own growth opportunities with existing
cash flow. Since we have elected to not build spec rigs in
the current industry environment, to grow our contract
drilling segment, beyond working our existing rigs, we
look to third-party operators to contract with us to build
or refurbish a non-working rig in order to grow our fleet.
Likewise, our mid-stream segment is to a certain extent
dependent on other parties to drill new wells that can
be added to existing systems or require new systems
to be built. Our mid-stream segment also grows with
the addition of new wells drilled by our oil and natural
gas segment, and we are looking for additional growth
opportunities with our new capital partners.
To balance growth opportunities within anticipated cash
flow is a goal, but one that requires some flexibility. It is
not always possible to fund growth solely from our cash
flow. When we rebounded from the last commodity
cycle, our cash flows grew but not within the capital
needs of our three segments. We could easily foresee
the possibility where we could not supply the capital
needed to meet our growth potential. Again, our tri-
segment structure proves beneficial by giving us the
flexibility to meet that challenge. For example, in 2017,
our mid-stream segment generated record operating
profit (revenues less operating expenses), but we
foresaw growth opportunities for that segment beyond
the capital we could provide. In response, we sold a
50% non-operating equity interest in that segment for
$300 million in 2018. In doing so, we accomplished three
things: first, we brought in two additional capital partners
to accelerate the growth of that segment; second, we
acquired additional capital to grow our exploration
and development segment; and finally, we reduced
our corporate debt and improved our balance sheet.
We are pleased this segment is now better situated to
TO
OUR
SHAREHOLDERS
Larry D. Pinkston
CHIEF EXECUTIVE OFFICER & PRESIDENT
David T. Merrill
CHIEF OPERATING OFFICER
FEBRUARY 26, 2019
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D uring the year, we produced 17.1 MMBoe, a 7% increase over 2017.
Liquids (oil and NGLs) production represented 46% of our total
equivalent production. Our production, while within the lower
range of our 2018 forecast, was restricted because of unanticipated
delays in our production in the Texas Panhandle. Those delays resulted
from certain post frack equipment issues and because we had to re-drill
two laterals after a completion hardware failure. Our production was also
curtailed by an unanticipated requirement to shut-in wells during the
commissioning of a third-party interstate pipeline in western Oklahoma.
Our year-end 2018 total estimated proved reserves were 159.7 MMBoe,
or 958.1 Bcfe, an increase of 7% over 2017. Of our total proved reserves,
70% are proved developed. Estimated proved reserves were 14% oil, 30%
NGLs, and 56% natural gas. This increase in reserves represents a 158%
replacement of our 2018 annual production with new reserves, achieving
our goal of replacing at least 150% of each year’s production.
2018 oil and natural gas revenues increased 18% to $423.1 million. Our
average realized commodity prices for the year were $2.46 for natural
gas, $55.78 for oil and $22.18 for NGLs, reflecting an increase over 2017
of 0%, 13%, and 21%, respectively.
In our Wilcox play, in southeast Texas, we completed as gas/condensate
producers seven vertical wells and one horizontal well. Our 2018 annual
production from our Wilcox play averaged 89 MMcfe per day (9% oil,
27% NGLs, 64% natural gas). We anticipate completing approximately
13 vertical wells during 2019 in this play. Also, we plan to complete
approximately ten behind pipe gas and liquids zones.
In our Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, in western
Oklahoma, we completed seven horizontal oil wells in the Marchand zone
of the Hoxbar interval. In our western STACK area, we completed two
horizontal wells, and in our Thomas Field (Red Fork), we completed two
horizontal wells. After drilling these two successful Red Fork wells, we
acquired offsetting oil and natural gas assets in December for just under
$30 million. The acquired properties added approximately 8,667 net
acres largely held by production to the Penn sands area, 44 wells, and
approximately 2.6 MMBoe of proved reserves. This acquisition provides
us with approximately 30 future horizontal Red Fork drilling locations,
which we currently believe will have a significant percentage of oil in
their total production stream. Our annual production from all of western
Oklahoma averaged 76.4 MMcfe per day (33% oil, 21% NGLs, 46% natural
gas). We anticipate completing approximately eight horizontal Marchand
wells in our SOHOT play, and eight horizontal wells in our Red Fork play
in the Thomas Field during 2019.
In our Texas Panhandle Granite Wash play, we completed 12 extended
lateral horizontal gas/condensate wells in our Buffalo Wallow field.
Annual production from the Texas Panhandle averaged 96.3 MMcfe per
day (10% oil, 39% NGLs, 51% natural gas). We anticipate completing
approximately four extended lateral Granite Wash horizontal wells
in our Buffalo Wallow field during 2019.
6
service. After the year-end, we placed our 12th
and 13th BOSS rigs into service. The BOSS rig is a
proprietary rig design we started building in 2013. It is a 1,500
horsepower, high-spec AC rig that combines the best technological
innovations from high-tech rig designs into a single unique rig that meets
the increasing technical demands of our customers. The BOSS rig meets
all definitions of a super-spec or pad-optimal rig by industry standards.
One feature that separates our BOSS rig from our competitors’ rigs is
our 2,200 HP quintuplex mud pumps. Using two quintuplex pumps on
each BOSS rig exceeds the operating capability and performance of rigs
equipped with three conventional triplex mud pumps. The BOSS rig also
allows for a quick assembly substructure, which means the rig can be
moved to a new location using fewer truck loads. Both features provide
our customers with increased efficiency and reduce their overall costs
on a well.
T D uring 2018, we placed our 11th BOSS rig into
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We reached 36 operating rigs during the third quarter following which
our utilization pared back slightly as operators made adjustments
because of decreases in commodity prices. We exited 2018 with 32
active rigs. Currently, 32 of our rigs are operating. As of year-end, we had
24 long-term contracts with original terms ranging from six months to
three years. Included in these 24 term contracts are the two new BOSS
rigs that began working after the end of the year. Two of those long-term
contracts rolled over in the first quarter of 2019, both to two-year terms.
Of the remaining 20 long-term contracts, seven are up for renewal in the
first quarter of 2019, seven in the second quarter, one in the third quarter,
two in the fourth quarter, and three in 2020 and thereafter.
During the fourth quarter of 2018, we removed 41 rigs from our fleet
as well as some other drilling equipment. Those rigs included our 29
mechanical rigs and 12 SCR rigs we determined were not candidates for
upgrading to meet market demands. Our fleet now totals 57 rigs and
includes 13 BOSS AC rigs with the remainder being upgraded SCR rigs.
Our rigs are located in varying geographic areas with 19 rigs in our Rocky
Mountain division and 38 in our Mid-Continent division. The maximum
depth capacities of our rigs range from 15,000 to 40,000 feet.
For the year, our drilling revenues increased 12% over 2017 to $196.5
million. Our average dayrates for the year were $17,510, an 8%
increase over 2017. Our average number of rigs working during
2018 was 32.8 compared to 30.0 for 2017.
7
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O n April 3, 2018, we sold 50% of the ownership
interest in our mid-stream segment to SP
Investor Holdings, LLC for $300 million. SP
Investor Holdings, LLC is a holding company jointly owned by
OPTrust and funds managed and/or advised by Partners Group, a
global private markets investment manager. The transaction, which
implied a value for the mid-stream segment of $600 million, not only
recognizes the significant value Unit created with Superior but gives
our partners and us the opportunity to continue to expand Superior.
The structure of the sale allows Unit to retain day-to-day operational
control, a feature that provides economic and technical support to Unit’s
ongoing exploration and production segment. Through this transaction,
we now have significant capital partners invested with us in our mid-
stream business to accelerate Superior’s growth.
Revenues for this segment for 2018 increased 8% over 2017 to $223.7
million. Liquids sold and gas processed volumes increased by 24%
and 15%, respectively, over 2017. Our customer base consists of mainly
independent producers in Oklahoma, Texas, Kansas, Pennsylvania, and
West Virginia. We operate three gas treatment plants, 14 natural gas
processing plants, 22 active gathering systems, and approximately 1,475
miles of pipeline.
In the Appalachian region at our Pittsburgh Mills gathering system, the
annual average gathered volume was 123.9 MMcf per day, and seven
new infill wells were added late in the second quarter of 2018. We have
completed construction of a new pipeline to connect the next scheduled
well pad to this system. We have also completed the upgrade to the
compressor station and dehydration facilities. Production from this new
pad came online during January 2019.
At the Cashion processing facility in central Oklahoma, the annual
average throughput volume was 46.0 MMcf per day, and the annual
average natural gas liquids production was 234,316 gallons per day.
This system is now operating at full capacity. However, we are adding
additional capacity to allow us to gather and process production from
a new producer with a significant acreage dedication. We are relocating
a 60 MMcf per day processing plant from our Bellmon facility to the
Cashion area. This processing plant will be installed at the Reeding site
on the Cashion system and is expected to be operational by the end of
the first quarter of 2019. It will increase our total processing capacity on
the Cashion system to approximately 105 MMcf per day. Twenty-two new
wells were connected to the Cashion system in 2018.
At the Hemphill Texas system, the average annual throughput volume was
72.6 MMcf per day while the total annual production of natural gas liquids
averaged 264,971 gallons per day. We connected 13 wells to this processing
facility and completed a construction project to upgrade compression
facilities in the Buffalo Wallow area to handle additional volume.
8
OPERATIONAL HIGHLIGHTS
Year Ended December 31 ($ in thousands except average price amounts)
Proved Oil and Natural Gas Reserves
Discounted at 10% (Before Income
Taxes)
Proved Oil and Natural Gas Reserves
Discounted at 10% (After Income Taxes)
Total Estimated Proved Reserves:
2018
2017
2016
2015
2014
$
1,105,707
$
897,525
$
575,176
$
690,693
$ 2,099,789
$
983,678
$
807,170
$
518,210
$
589,486
$
1,435,744
Natural Gas (MMcf)
535,963
508,650
405,579
484,868
Oil (MBbl)
Natural Gas Liquids (MBbl)
Equivalent (MBoe)
Production:
Natural Gas (MMcf)
Oil (MBbl)
Natural Gas Liquids (MBbl)
Equivalent (MBoe)
Average Price:
Natural Gas (Per Mcf)
Oil (Per Bbl)
Natural Gas Liquids (Per Bbl)
Equivalent (Boe)
Well Data:
Wells Drilled
Wells Completed
Success Rate
22,558
47,796
159,681
55,626
2,874
4,925
17,070
2.46
55.78
22.18
23.80
117
115
98%
$
$
$
$
19,513
45,486
149,774
51,260
2,715
4,737
15,996
2.46
49.44
18.35
21.72
70
68
97%
$
$
$
$
15,696
34,482
117,774
55,735
2,974
5,014
17,277
2.07
40.50
11.26
16.92
21
21
100%
$
$
$
$
16,735
37,687
135,233
65,546
3,783
5,274
19,982
2.63
50.79
10.12
20.92
58
56
97%
$
$
$
$
646,961
22,667
48,529
179,023
58,854
3,844
4,628
18,281
3.92
89.43
30.95
39.25
186
181
97%
$
$
$
$
2018
2017
2016
2015
2014
Producing Well Count:
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Natural Gas
4,775
1,735
4,887
1,798
4,944
1,770
6,234
2,169
6,369
2,184
Oil
Total
1,533
599
1,554
633
1,574
635
1,627
650
1,752
663
6,308
2,334
6,441
2,431
6,518
2,405
7,861
2,819
8,121
2,847
Contract Drilling Operations Data:
Number of Drilling Rigs Available for Use at Year-End
Wells Drilled
Total Footage Drilled (Feet in 1,000’s)
Average Number of Drilling Rigs Utilized
Midstream Operations Data:
2018
2017
2016
2015
2014
55
539
8,386
32.8
95
468
6,864
30.0
94
358
5,112
17.4
94
516
7,237
34.7
89
894
12,551
75.4
Natural Gas Gathered (Mcf/Day)
393,613
385,209
419,217
353,771
319,348
Natural Gas Processed (Mcf/Day)
158,189
137,625
155,461
182,684
161,282
Liquids Sold (Gallons/Day)
663,367
534,140
536,494
577,513
733,406
9
FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number: 1-9260
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
73-1283193
(I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, Oklahoma
(Address of principal executive offices)
74132
(Zip Code)
(Registrant’s telephone number, including area code) (918) 493-7700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $.20 per share
Name of each exchange on which registered
NYSE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [x] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes [ ] No [x]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [x] No [ ]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of
Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes [x] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ x ]
Smaller reporting company [ ]
Accelerated filer [ ]
Emerging growth company [ ]
Non-accelerated filer [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new
or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
[ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)
Yes [ ] No [x]
As of June 30, 2018, the aggregate market value of the voting and non-voting common equity (based on the closing price of the stock on the NYSE on
June 30, 2018) held by non-affiliates was approximately $1,322,944,221. Determination of stock ownership by non-affiliates was made solely for the purpose
of this requirement, and the registrant is not bound by these determinations for any other purpose.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common Stock, $0.20 par value per share................................................
Class
Outstanding at February 12, 2019
54,366,397 shares
DOCUMENTS INCORPORATED BY REFERENCE
Document
Portions of the registrant’s definitive proxy statement (the Proxy Statement) with respect to its annual meeting of
shareholders scheduled to be held on May 1, 2019. The Proxy Statement will be filed within 120 days after the
end of the fiscal year to which this report relates.
Parts Into Which Incorporated
Part III
Exhibit Index—See Page 135
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Business.........................................................................................................................................................................
Risk Factors...................................................................................................................................................................
Unresolved Staff Comments..........................................................................................................................................
Properties.......................................................................................................................................................................
Legal Proceedings..........................................................................................................................................................
Mine Safety Disclosures................................................................................................................................................
PART II
Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer
Purchases of Equity Securities.......................................................................................................................................
Selected Financial Data..................................................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operation..........................................
Quantitative and Qualitative Disclosures about Market Risk........................................................................................
Financial Statements and Supplementary Data..............................................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.........................................
Controls and Procedures.................................................................................................................................................
Other Information...........................................................................................................................................................
PART III
Directors, Executive Officers, and Corporate Governance............................................................................................
Executive Compensation................................................................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters......................
Certain Relationships and Related Transactions, and Director Independence...............................................................
Principal Accountant Fees and Services.........................................................................................................................
PART IV
Exhibits and Financial Statement Schedules..................................................................................................................
Form 10-K Summary......................................................................................................................................................
Signatures..................................................................................................................................................................................................
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DEFINITIONS
The following are explanations of some terms used in this report.
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
FF
ASU – Accounting Standards Update.
Bcf – Billion cubic feet of natural gas.
Bcfe – Billion cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six Mcf
of natural gas.
Bbl – Barrel, or 42 U.S. gallons liquid volume.
Boe – Barrel of oil equivalent. Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.
BOKF – Bank of Oklahoma Financial Corporation.
Btu – British thermal unit, used in gas volumes. Btu is used to refer to the natural gas required to raise the temperature of one
pound of water by one-degree Fahrenheit at one atmospheric pressure.
Development drilling – The drilling of a well within the proved area of an oil or gas reservoir to the depth of a stratigraphic
horizon known to be productive.
DD&A – Depreciation, depletion, and amortization.
FASB – Financial and Accounting Standards Board.
Finding and development costs – Costs associated with acquiring and developing proved natural gas and oil reserves
capitalized under generally accepted accounting principles, including any capitalized general and administrative expenses.
Gross acres or gross wells – The total acres or wells in which a working interest is owned.
IF – Inside FERC (U.S. Federal Energy Regulatory Commission).
LIBOR – London Interbank Offered Rate.
MBbls – Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf – Thousand cubic feet of natural gas.
Mcfe – Thousand cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six
Mcf of natural gas.
MMBbls – Million barrels of crude oil or other liquid hydrocarbons.
MMBoe – Million barrels of oil equivalents.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six
Mcf of natural gas.
Net acres or net wells – The total fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NYMEX – The New York Mercantile Exchange.
Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.
Producing property – A natural gas or oil property with existing production.
DEFINITIONS — (Continued)
Proved developed reserves – Reserves expected to be recovered through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through
installed extraction equipment and infrastructure operational at the time of the reserves estimate. For additional information, see
the SEC’s definition in Rule 4-10(a)(3) of Regulation S-X.
Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and
engineering data, can be estimated with reasonable certainty to be economically producible – fromff
known reservoirs and under existing economic conditions, operating methods, and government regulations – before the time
when the contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless
of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For
additional information, see the SEC’s definition in Rule 4-10(a)(2)(i) through (iii) of Regulation S-X.
a given date forward, from
Proved undeveloped reserves – Proved reserves expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. For additional information, see the SEC’s definition in
Rule 4-10(a)(4) of Regulation S-X.
Reasonable certainty (regarding reserves) – If deterministic methods are used, reasonable certainty means high confidence that
the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities
recovered will equal or exceed the estimate.
Reliable technology – A grouping of one or more technologies (including computational methods) that has been field tested and
has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation.
SARs – Stock appreciation rights.
Unconventional play – Plays targeting tight sand, carbonates, coal bed, or oil and gas shale reservoirs. The reservoirs tend to
cover large areas and lack the readily apparent traps, seals, and discrete hydrocarbon-water boundaries that typically define
conventional reservoirs. These reservoirs generally require horizontal wells and fracture stimulation treatments or other special
recovery processes to produce economically.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to the point that would permit the
production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.
Well spacing – The regulation of the number and location of wells over an oil or gas reservoir, as a c
spacing is normally accomplished by order of the appropriate regulatory conservation commission.
rr
onservation measure. Well
Workovers – Operations on a producing well to restore or increase production.
WTI – WestWW Texas Intermediate, the benchmark crude oil in the United States.
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2018
PART I
Item 1. Business
Unless otherwise indicated or required by the context, the terms “Company,” “Unit,” “us,” “our,” “we,” and “its” refer to
Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refer to Superior
Pipeline Company, Lyy
.L.C. (and its subsidiaries) of which we own 50%.
a
Our executive offices are at 8200 South Unit Drive, Tulsa, Oklahoma 74132; our telephone number is (918) 493-7700.
Information regarding our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,
and any amendments to these reports, will be provided free in print to any shareholders who request them. They are also
available on our internet website at www.unitcorp.com, as soon as reasonably practicable after we electronically file these
reports with or furnish them to the Securities and Exchange Commission (SEC). The SEC maintains an Internet website at
www.sec.gov that contains reports, proxy and information statements, and other information about us that we file electronically
with the SEC.
Also, we post on our Internet website, www.unitcorp.com, copies of our corporate governance documents. Our corporate
governance guidelines and code of ethics, and the charters of our Board’s Audit, Compensation, and Nominating and
Governance Committees, are available for free on our website or in print to any shareholder who requests them. We may
occasionally provide important disclosures to investors by posting them in the investor information section of our website, as
allowed by SEC rules.
GENERAL
We were founded in 1963 as an oil and natural gas contract drilling company. Tyy oday
TT
, byy esides our drilling operations, we
have operations in the exploration and production and mid-stream areas. We operate, manage, and analyze our results of
operations through our three principal business segments:
•
•
Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. Tyy
acquires, and produces oil and natural gas properties for our account.
his segment explores, develops,
CC
Contract Drilling
and natural gas wells for others and our account.
– carried out by our subsidiary Unit Drilling Company. Tyy
his segment contracts to drill onshore oil
• Mid-Stream – carried out by our subsidiary Superior Pipeline Company, Lyy
.L.C., and its subsidiaries (Superior). This
segment buys, sells, gathers, processes, and treats natural gas for third parties and our account.
Each company may conduct operations through subsidiaries of its own.
This table provides certain information about us as of February 12, 2019:
Oil and Natural Gas
Total number of wells in which we own an interest..................................................................................................................
6,326
Contract Drilling
Total number of drilling rigs available for use..........................................................................................................................
Mid-Stream
Number of natural gas treatment plants we own.......................................................................................................................
Number of processing plants we own.......................................................................................................................................
Number of natural gas gathering systems we own (1)................................................................................................................
56
3
14
22
_________________________
1.
In 2018, two gathering systems were transferred to our oil and natural gas segment.
1
Oil and Natural Gas
2018 SEGMENT OPERATIONS HIGHLIGHTS
•
•
•
•
i d
Acquired certain oil and natural gas assets located primarily in Custer County, Oyy
illimillion.
il
il
d
d
l
i
l
i
i
klahoma for approximatel $y $29.6
kl h
f
l
i
To l
tal year-end 2018 proved oil and natural gas reserves increased 7% over 2017.
l
d il
d
d
d
i
Replaced 158% of 2018 production with new reserves.
i h
d
d
f
i
l
Sold non-core assets with proceeds of $22.5 million.
illi
f $
i h
ld
d
Contract Drilling
•
Utilization cycle during 2018:
◦
◦
◦
Started the year with 31 drilling rigs operating;
Placed one new BOSS drilling rig into service in the third quarter and made modifications to nine SCR
drilling rigs; and
Gradual increase in utilization through mid-year for a high of 36 drilling rigs operating at the end of July and
we exited the year with 32 drilling rigs operating, following weaker commodity prices in the fourth quarter.
•
•
All 11 BOSS drilling rigs were operating during the year.
AA
Average drilling rig dayrates increased 8% during the year.
Mid-Stream
•
•
•
•
•
•
•
Sold 50% of the ownership interests for $300.0 million.
Increased average processed gas volumes up to 158 MMcf per day during 2018 which represents approximately a
15% increase over 2017.
Increased average gas liquids sold up to approximately 663,000 gallons per day during 2018 which is a 24% increase
over 2017.
Connected seven infill wells to our Pittsburgh Mills gathering system which increased gathered volume
approximately 50 MMcf per day.
Continued to expand the Cashion gathering and processing system in order to allow us to gather and process
production from a new producer with a significant acreage dedication in the area.
Connected 22 new wells to the Cashion system and started construction of a new plant and compressor station in
order to increase our processing capacity up to 105 MMcf per day.
Connected 13 new wells to our Hemphill processing facility and completed the construction project to upgraded
compression facilities in the Buffalo Wallow area in order to handle additional volume.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 18 of our Notes to Consolidated Financial Statements in Item 8 of this report for information regarding each of
our segment’s revenues, profits or losses, and total assets.
2
OIL AND NATURAL GAS
General. All our oil and natural gas properties are in the United States. Our producing oil and natural gas properties,
unproved properties, and related assets are in Oklahoma, Texas, Kansas, Arkansas, Colorado, Wyoming, Montana, North
Dakota, and Utah.
When we are the operator of a property, we try to drill wells using a drilling rig owned by our contract drilling segment,
and we use our mid-stream segment to gather our gas if it is economical to do so.
This table presents certain information regarding our oil and natural gas operations as of December 31, 2018:
Number
of
Gross
Wells
Number
of Net
Wells
Number
of Gross
Wells in
Process
Number
of Net
Wells in
Process
Natural
Gas
(Mcf)
2018 Average
Net Daily Production
Oil
(Bbls)
NGLs
(Bbls)
Total...................................................
6,322
2,337.98
49
6.00
152,398
7,874
13,494
As of December 31, 2018, we had no significant water floods, pressure maintenance operations, or any other material
related activities in process.
Acquisitions. On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady
and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1,
2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million
barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core
Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition
included 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired,
approximately 71% was held by production. We also received one gathering system as part of the transaction.
In December 2018, we closed on an acquisition of certain oil and natural gas assets located primarily in Custer County,
Oklahoma. The total preliminary adjusted value of consideration was $29.6 million. As of November 1, 2018, the effective date
of the acquisition, the estimated proved oil and gas reserves for the acquired properties was 2.6 MMBoe net to us. The
acquisition added approximately 8,667 net oil and gas leasehold acres to our Penn Sands area in Oklahoma including
approximately 44 wells. The acquisitions included approximately 30 potential horizontal drilling locations which are anticipated
to have a high percentage of oil relative to the total production stream. Of the acreage acquired, approximately 82% was held by
production.
Dispositions. We had non-core asset sales, net of related expenses, of $22.5 million, $18.6 million, and $67.2 million, in
2018, 2017, and 2016, respectively. Proceeds from these sales reduced the net book value of the full cost pool with no gain or
loss recognized.
During prior years, we determined the value of some of our unproved oil and gas properties were diminished (in part or
whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $7.6
million and $10.5 million in 2016 and 2017, respectively, of costs being added to the total of our capitalized costs being
amortized. We incurred a $161.6 million pre-tax ($100.6 million net of tax) non-cash ceiling test write-down of our oil and
natural gas properties in 2016 primarily due to the reduction of the 12-month average commodity prices during the first three
quarters of the year. We had no ceiling test write-downs for 2017 or 2018.
3
Well and Leasehold Data. These tables identify certain information regarding our oil and natural gas exploratory and
development drilling operations:
Year Ended December 31,
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
Wells drilled:
Development:
Oil........................................
Natural Gas..........................
Dry.......................................
Total development..........
Exploratory:
Oil........................................
Natural gas..........................
Dry.......................................
Total exploratory............
Total wells drilled.....
Wells producing or capable of
producing:
Oil................................................
Natural gas..................................
Total.......................................
52
63
2
117
—
—
—
—
117
9.18
22.96
1.02
33.16
—
—
—
—
33.16
45
23
2
70
—
—
—
—
70
10.98
13.90
0.83
25.71
—
—
—
—
25.71
9
11
—
20
1
—
—
1
21
3.57
5.10
—
8.67
1.00
—
—
1.00
9.67
Year Ended December 31,
2018 (1)
2017
2016 (2)
Gross
Net
Gross
Net
Gross
Net
1,533
4,775
6,308
598.50
1,734.96
2,333.46
1,554
4,887
6,441
632.85
1,797.66
2,430.51
1,574
4,944
6,518
634.56
1,770.43
2,404.99
_________________________
1.
There were 56 gross wells with multiple completions.
2.
During 2016, we divested 1,300 gross (407.70 net) wells. There were no significant divestitures in 2017 or 2018.
As of February 12, 2019, we were involved in drilling nine gross (4.54 net) wells started during 2019.
Cost for development drilling includes $76.3 million, $41.6 million, and $2.5 million in 2018, 2017, and 2016,
respectively, to develop previously booked proved undeveloped oil and natural gas reserves.
This table summarizes our leasehold acreage at December 31, 2018:
Developed
Year Ended December 31, 2018
Undeveloped
Total
Gross
Net
Gross
Net (1)
Gross
Net
Total............................
561,687
387,176
127,834
81,139
689,521
468,315
_________________________
1.
Approximately 76% of the net undeveloped acres are covered by leases that will expire in the years 2019—2021 unless drilling or production extends the
terms of those leases. Currently, we do not have any material proved undeveloped (PUD) reserves attributable to acreage where the expiration date
precedes the scheduled PUD reserve development plan.
4
Price and Production Data. The following tables identify the average sales price, production volumes, and average
production cost per equivalent barrel for our oil, NGLs, and natural gas production for the years indicated:
Year Ended December 31,
2018
2017
2016
Average sales price per barrel of oil produced:
Price before derivatives.......................................................................................... $
63.78
$
48.98
$
Effect of derivatives................................................................................................
Price including derivatives...................................................................................... $
Average sales price per barrel of NGLs produced:
Price before derivatives.......................................................................................... $
Effect of derivatives................................................................................................
Price including derivatives...................................................................................... $
Average sales price per Mcf of natural gas produced:
Price before derivatives.......................................................................................... $
Effect of derivatives................................................................................................
(8.00)
55.78
22.58
(0.40)
22.18
2.42
0.04
$
$
$
$
0.46
49.44
18.35
—
18.35
2.49
(0.03)
$
$
$
$
Price including derivatives...................................................................................... $
2.46
$
2.46
$
39.05
1.45
40.50
11.26
—
11.26
1.98
0.09
2.07
5
Year Ended December 31,
2018
2017
2016
Oil production (MBbls):
Jazz Wilcox field.............................................................................................
Buffalo Wallow field.......................................................................................
All other fields................................................................................................
Total oil production......................................................................
NGLs production (MBbls):
Jazz Wilcox field.............................................................................................
Buffalo Wallow field.......................................................................................
All other fields................................................................................................
Total NGLs production................................................................
Natural gas production (MMcf):
Jazz Wilcox field.............................................................................................
Buffalo Wallow field.......................................................................................
All other fields................................................................................................
Total natural gas production.........................................................
Total production (MBoe):
Jazz Wilcox field.............................................................................................
Buffalo Wallow field.......................................................................................
All other fields................................................................................................
Total production...........................................................................
418
258
2,198
2,874
1,370
1,235
2,320
4,925
17,494
9,428
28,704
55,626
4,703
3,065
9,302
17,070
533
127
2,055
2,715
1,567
728
2,442
4,737
16,799
6,228
28,233
51,260
4,900
1,893
9,203
15,996
Average production cost per equivalent Bbl (1)............................................................ $
6.50
$
6.24
$
_______________________
1.
Excludes ad valorem taxes and gross production taxes.
589
120
2,265
2,974
1,671
592
2,751
5,014
18,145
5,506
32,084
55,735
5,284
1,629
10,364
17,277
5.31
Our Buffalo Wallow field in Hemphill County, Texas, contained 29%, 24%, and 13% of our total proved reserves in 2018,
2017, and 2016, respectively, expressed on an oil-equivalent barrels basis. Our Jazz Wilcox field in South Texas, which includes
our Gilly, Segno, and Wildwood prospects and several smaller prospects, contained 14%, 18%, and 26% of our total proved
reserves for those same years also expressed on an oil-equivalent barrels basis. There are no other fields that accounted for more
than 15% of our proved reserves.
Oil, NGLs, and Natural Gas Reserves. The following table identifies our estimated proved developed and undeveloped
oil, NGLs, and natural gas reserves:
Year Ended December 31, 2018
Total proved developed..................................................................
Total proved undeveloped..............................................................
Total proved......................................................................
15,192
7,366
22,558
33,515
14,281
47,796
Oil
(MBbls)
NGLs (MBbls)
Natural
Gas
(MMcf)
377,216
158,747
535,963
Total
Proved
Reserves
(MBoe)
111,576
48,105
159,681
Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of those reserves require extensive judgments
of reservoir engineering data and are generally less precise than other estimates made in financial disclosures. We use Ryder
Scott Company, L.P., (Ryder Scott), independent petroleum consultants, to audit the reserves prepared by our reservoir
engineers. Ryder Scott has been providing petroleum consulting services throughout the world since 1937. Their summary
report is attached as Exhibit 99.1 to this Form 10-K. The wells or locations for which reserve estimates were audited were taken
from our reserve and income projections as of December 31, 2018, and comprised 83% of the total proved developed future net
income discounted at 10% and 82% of the total proved discounted future net income (based on the SEC's unescalated pricing
policy).
Our Reservoir Engineering department is responsible for reserve determination for the wells in which we have an interest.
Their primary objective is to estimate the wells' future reserves and future net value to us. Data is incorporated from multiple
6
sources including geological, production engineering, marketing, production, land, and accounting departments. The engineers
review this information for accuracy as it is incorporated into the reservoir engineering database. Our internal audit group
reviews our internal controls to help provide assurance all the data has been provided. New well reserve estimates are provided
to management and the respective operational divisions for additional scrutiny. Myy
reviewed regularly with the operational divisions to confirm completeness and accuracy. Ayy
completed by Ryder Scott, the reservoir department reviews all properties for accuracy of forecasting.
ajor reserve changes on existing wells are
s the external audit is being
Technical Qualifications
Ryder Scott – Mr. Robert J. Paradiso was the primary technical person responsible for overseeing the estimate of the
reserves, future production and income prepared by Ryder Scott.
Mr. Paradiso, an employee of Ryder Scott since 2008, is a Vice President and serves as Project Coordinator
VV
, rrr esponsible
for coordinating and supervising staff aff nd consulting engineers in ongoing reservoir evaluation studies worldwide. Before
joining Ryder Scott, Mr. Paradiso served in several engineering positions with Getty Oil Company, Tyy exaco, Union
Petroleum, Amax Oil and Gas, Inc., Norcen Explorer, Irr nc., Amerac Energy Corporation, Halliburton Energy Services, Santa Fe
Snyder Corp., and Devon Energy Corporation.
Texas
TT
Mr. Paradiso earned a Bachelor of Science degree in Petroleum Engineering from Texas Tech University in 1979 and is a
registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE).
Besides gaining experience and competency through prior work experience, the Texas Board of Professional Engineers
requires at least fifteen hours of continuing education annually, iyy ncluding at least one hour in professional ethics, which Mr.
Paradiso fulfills. As part of his 2018 continuing education hours, Mr. Prr
the 2018 RSC Reserves Conference relating to the definitions and disclosure guidelines in the United States Securities and
Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released
January 14, 2009 in the Federal Register. Mrr
2018 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering,
geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.
r. Paradiso attended an additional 20.8 hours of formalized in-house training during
aradiso attended 6 hours of formalized training during
Based on his educational background, professional training and over 39 years of practical experience in the estimation
and evaluation of petroleum reserves, Mr. Prr
Reserves Auditor in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information” promulgated by the SPE as of February 19, 2007. For more information regarding Mr. Prr
aradiso’s geographic and
job-specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/Employees.
aradiso has attained the professional qualifications as a Reserves Estimator and
The Company – Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers
Trenton Mitchell and Derek Smith.
Mr. Mitchell earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1994. He has
been an employee of Unit since 2002. Initially, he w
capacity of Reservoir Engineer and in 2010 he was promoted to Manager of Reservoir Engineering. Before joining Unit, he
served in several engineering field and technical support positions with Schlumberger Well Services in their pumping services
segment (formerly Dowell Schlumberger). He obtained his Professional Engineer registration from the State of Oklahoma in
2004. He has been a member of SPE since 1991 and joined the Society of Petroleum Evaluation Engineers (SPEE) in 2017.
as the Outside Operated Engineer and since 2003 he has served in the
yy
Mr. Smith received a Bachelor of Science in Petroleum Engineering with a Minor in Business from the University of
Tulsa in 2005. He worked for Apache Corporation immediately after in Production Engineering, then Reservoir Engineering,
followed by Drilling Engineering for approximately one year each before moving to Corporate Reserves in 2008. He joined
Unit in 2009 as a Corporate Reserves Engineer involved in reserve evaluation, acquisition appraisals, and prospect reviews with
increasing levels of responsibility. He h
as been a member of SPE since 2000 and joined the SPEE in 2018.
y
As part of their continuing education Mr. Mrr
itchell and Mr. Smith have attended various seminars and forums to enhance
their understanding of current standards and issues for reserves presentation. These forums have included those sponsored by
various professional societies and professional service firms including Ryder Scott.
Definitions and Other. Proved oil, NGLs, and natural gas reserves, as defined in SEC Rule 4-10(a), are those quantities
of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be
7
a given date forward, from known reservoirs and under existing economic conditions,
economically producible – fromff
operating methods and government regulations – before the time the contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for
estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will
commence the project within a reasonable time.
The area of the reservoir considered as "proved" includes:
•
•
The area identified by drilling and limited by any fluid contacts, and
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be j
reservoir and to contain economically producible oil or gas based on available geosciences and engineering data.
udged to be continuous with the
yy
Absent data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as incurred
in a well penetration unless geosciences, engineering, or performance data and reliable technology establish a lower contact
with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when:
•
•
•
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than the reservoir as
a whole;
The operation of an installed program in the reservoir or other evidence using reliable technology establishes
reasonable certainty of the engineering analysis on which the project or program was based; and
The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price used is the average of the prices over the 12 months before the ending date of the period covered by the
report and is an unweighted arithmetic average of the first day of the month price for each month within the period, unless
prices are defined by contractual arrangements, excluding escalations based on future conditions.
"Proved developed" oil, NGLs, and natural gas reserves are proved reserves expected to be recovered through existing
wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor to the
cost of a new well. It can also be recovered through installed extraction equipment and infrastructure operational at the time of
the reserves estimate if the extraction is by means not involving a well.
"Proved undeveloped" oil, NGLs, and natural gas reserves are proved reserves expected to be recovered from new wells
on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on
undrilled acreage are limited to those directly offsetting development spacing areas reasonably certain of production when
drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at
greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been
adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer
time. Under no circumstances can estimates for proved undeveloped reserves be attributable to acreage for which an application
of fluid injection or other improved recovery technique is contemplated, unless those techniques have been proved effective by
actual projects in the same reservoir or an analogous reservoir, or by o
reasonable certainty.
ther evidence using reliable technology establishing
rr
8
Proved Undeveloped Reserves. As of December 31, 2018, we had 158 gross proved undeveloped wells all of which we
plan to develop within five years of initial disclosure at a net estimated cost of approximately $397.4 million. The future
estimated development costs to develop our proved undeveloped oil and natural gas reserves for the years 2019-2023, as
disclosed in our December 31, 2018 oil and natural gas reserve report, are shown below:
Year
2019..................................................................................
2020..................................................................................
2021..................................................................................
2022..................................................................................
2023..................................................................................
Number of Gross Wells Planned
Estimated Net Development Cost
(In millions)
$
73
47
26
10
2
158
$
104.2
135.8
97.6
48.8
11.0
397.4
Our proved undeveloped reserves reported at December 31, 2018 did not include reserves we did not expect to develop
within five years of initial disclosure of those reserves. Below, we summarize changes to our proved undeveloped reserves
during 2018:
Oil
(MMBbls)
NGLs
(MMBbls)
Natural Gas
(Bcf)
Total
(MMBoe)
Proved undeveloped reserves, January 1, 2018................................................
Extensions and discoveries...............................................................................
Converted to developed....................................................................................
Revisions of previous estimates........................................................................
Purchases of reserves........................................................................................
Proved undeveloped reserves, December 31, 2018..........................................
4.7
3.3
(1.6)
0.4
0.6
7.4
12.1
4.6
(2.3)
(0.5)
0.4
14.3
120.2
59.4
(17.3)
(6.2)
2.6
158.7
36.8
17.8
(6.8)
(1.1)
1.4
48.1
During 2018, we converted 18 proved undeveloped well locations into proved developed wells at a cost of approximately
$76.3 million. The increase in the table above to our extensions and discoveries were due to several factors including increased
drilling activity, higher commodity prices resulting in an increased budget for future capital expenditures, all contributing to
more wells being economical to develop in the next five years.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at
December 31, 2018, 2017, and 2016, the changes in quantities, and standardized measure of those reserves for the three years
then ended, are shown in the Supplemental Oil and Gas Disclosures in Item 8 of this report.
Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices under
arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines and
independent marketing firms under contracts with terms generally ranging from one month to a year. Few of these contracts
contain provisions for readjustment of price as most are market sensitive.
Customers. During 2018, sales to CVR Refining, LP and Valero Energy Corporation accounted for 14% and 10% of our
oil and natural gas revenues, respectively. Besides our mid-stream segment, no other company accounted for over 10% of our
oil and natural gas revenues. During 2018, our mid-stream segment purchased $81.4 million of our natural gas and NGLs
production and provided gathering and transportation services of $7.3 million. Intercompany revenue from services and
purchases of production between our mid-stream segment and our oil and natural gas segment has been eliminated in our
consolidated financial statements. In 2017 and 2016, we eliminated intercompany revenues of $69.9 million and $51.9 million,
respectively, attributable to the intercompany purchase of our production of natural gas and NGLs and gathering and
transportation services.
CONTRACT DRILLING
General. Our contract drilling business is conducted through Unit Drilling Company. Through this company we drill
onshore oil and natural gas wells for our account and others. Our drilling operations are in Oklahoma, Texas, Colorado,
Wyoming, Utah, and North Dakota.
9
This table identifies certain information about our contract drilling segment:
Number of drilling rigs available for use at year end (1)...............................................
Average number of drilling rigs owned during the year...............................................
Average number of drilling rigs utilized......................................................................
Utilization rate (2)..........................................................................................................
Average revenue per day (3).......................................................................................... $
Total footage drilled (feet in 1,000’s)...........................................................................
Number of wells drilled...............................................................................................
Year Ended December 31,
2017
2016
2018
55.0
95.5
32.8
34 %
95.0
94.5
30.0
32 %
16,429
$
15,934
$
8,386
539
6,864
468
94.0
93.9
17.4
19 %
19,154
5,112
358
_________________________
1.
In December 2018, we removed from service 41 drilling rigs, tubulars, hydraulic top drives, mud pumps, and other drilling equipment.
2.
3.
Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs owned during the year.
Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year.
Description and Location of Our Drilling Rigs. An on-shore drilling rig is composed of major equipment components
like engines, drawworks or hoists, derrick or mast, substructure, mud pumps, blowout preventers, top drives, and drill pipe.
Because of the normal wear and tear from operating 24 hours a day, several of the major components, like engines, mud pumps,
top drives, and drill pipe, must be replaced or rebuilt periodically. Other major components, like the substructure, mast, and
drawworks, can be used for extended periods with proper maintenance. We also own additional equipment used in operating our
drilling rigs, including iron roughnecks, automated catwalks, skidding systems, large air compressors, trucks, and other support
equipment. Our drilling rigs can be transferred between divisions.
The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet allowing us to cover a wide
range of our customers drilling requirements. In 2018, 38 of our 55 drilling rigs were used in drilling services.
This table shows certain information about our drilling rigs as of February 12, 2019:
Contracted
Rigs
Non-
Contracted
Rigs
Total
Rigs
Average
Rated
Drilling
Depth
(ft)
Drilling Rigs..................................................................................
30
26
56
20,196
Fluctuating commodity prices directly affect drilling rig utilization rates, both positively and negatively. We saw this
during 2018 as commodity prices improved from the fourth quarter of 2017 through the middle of 2018, so did drilling rig
utilization. Commodity prices then declined in the fourth quarter of 2018 and rig utilization followed.
At any given time the number of drilling rigs we can work depends on several conditions besides demand, including the
availability of qualified labor and the availability of needed drilling supplies and equipment. The impact of these conditions
affects the demand for our drilling rigs. Our average utilization rate for 2018, 2017, and 2016 was 34%, 32%, and 19%,
respectively.
The following table shows the average number of our drilling rigs working by quarter for the years indicated:
2018
2017
2016
First quarter..................................................................................................................
Second quarter..............................................................................................................
Third quarter.................................................................................................................
Fourth quarter...............................................................................................................
31.7
32.2
34.2
33.1
25.5
28.8
34.6
31.2
20.6
13.5
16.0
19.5
10
Drilling Rig Fleet. The following table summarizes the changes to our drilling rig fleet in 2018. A more complete
discussion of changes over the last three years follows the table:
Drilling rigs available for use on January 1, 2018.....................................................................................................................
Drilling rigs removed from service (1).......................................................................................................................................
Drilling rigs constructed............................................................................................................................................................
Total drilling rigs available for use on December 31, 2018......................................................................................................
95
(41)
1
55
_______________________
1.
In December 2018, we removed from service 41 drilling rigs, tubulars, hydraulic top drives, mud pumps, and other drilling equipment.
Dispositions, Acquisitions, and Construction. During December 2016, we sold an idle 1,500 horsepower SCR drilling rig
to an unaffiliated third party. We also built and placed into service for a third party operator our ninth BOSS drilling rig.
During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term
contract.
During 2018, we built our eleventh BOSS drilling rig and placed it into service for a third party operator under a long
term contract.
In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR
diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9.
Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on
our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that
we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the
estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these
estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax).
Drilling Contracts. Our drilling contracts are generally obtained through competitive bidding on a well by well basis.
Contract terms and payment rates vary depending on the type of contract used, the duration of the work, the equipment and
services supplied, and other matters. We pay certain operating expenses, including the wages of our drilling rig personnel,
maintenance expenses, and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination
by the customer subject to the payment of a fee. Our contracts also contain provisions regarding indemnification against certain
types of claims involving injury to persons, property, and for acts of pollution. The specific terms of these indemnifications are
negotiable on a contract by contract basis.
The type of contract used determines our compensation. All of our contracts in 2018, 2017, and 2016 were daywork
contracts. Under a daywork contract, we provide the drilling rig with the required personnel and the operator supervises the
drilling of the well. Our compensation is based on a negotiated rate to be paid for each day the drilling rig is used.
The majority of our contracts are on a well-to-well basis, with the rest under term contracts. Term contracts range from
six months to three years and the rates can either be fixed throughout the term or allow for periodic adjustments.
Customers. During 2018, QEP Resources, Inc. and Slawson Exploration Company, Inc. were our largest third-party
drilling customers accounting for approximately 16% and 10% of our total contract drilling revenues, respectively. Our work
for this customer was under multiple contracts and our business was not substantially dependent on a single contract. None of
these individual contracts were considered material. No other third-party customer accounted for 10% or more of our contract
drilling revenues.
Our contract drilling segment also provides drilling services for our oil and natural gas segment. During 2018, 2017, and
2016, our contract drilling segment drilled 45, 27, and ten wells, respectively, for our oil and natural gas segment, or 8%, 6%,
and 3%, respectively, of the total wells drilled by our contract drilling segment. Depending on the timing of the drilling services
performed on our properties those services may be deemed, for financial reporting purposes, to be associated with acquiring an
ownership interest in the property. Revenues and expenses for these services are eliminated in our statement of operations, with
any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued
under similar terms and rates as the contracts signed with unrelated third parties. By providing drilling services for the oil and
natural gas segment, we eliminated revenue of $22.5 million and $13.4 million during 2018 and 2017, respectively, from our
contract drilling segment and eliminated the associated operating expense of $19.5 million and $11.8 million during 2018 and
11
2017, respectively, yielding $3.0 million and $1.6 million during 2018 and 2017, respectively, as a reduction to the carrying
value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
MID-STREAM
General. Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries. Its
operations consist of buying, selling, gathering, processing, and treating natural gas. It operates three natural gas treatment
plants, 14 processing plants, 22 active gathering systems, and approximately 1,475 miles of pipeline. Superior and its
subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. We own 50% of Superior.
This table presents certain information regarding our mid-stream segment for the years indicated:
Year Ended December 31,
2018
2017
2016
Gas gathered—Mcf/day...............................................................................................
Gas processed—Mcf/day.............................................................................................
NGLs sold—gallons/day..............................................................................................
393,613
158,189
663,367
385,209
137,625
534,140
419,217
155,461
536,494
Dispositions and Acquisitions. This segment had no significant dispositions or acquisitions during 2016 or 2017.
On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior. The purchaser is SP
Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a
global private markets investment manager. We received $300.0 million from this sale. A portion of the proceeds were used to
pay down our bank debt and the remainder were used to accelerate the drilling program of our upstream subsidiary, Unit
Petroleum Company and build additional BOSS drilling rigs. In connection with the sale of the interest in Superior, we took the
necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale
and have Superior released from the Indenture.
Superior will be governed and managed under its Amended and Restated Limited Liability Company Agreement and the
Master Services and Operating Agreement (MSA) signed by Superior and an affiliate of Unit, as both agreements may be
amended occasionally. Further details are in Note 16 – Variable Interest Entity Arrangements.
Contracts. Our mid-stream segment provides its customers with a full range of gathering, processing, and treating
services. These services are usually provided to each customer under long-term contracts (more than one year), but we have
short-term contracts. Our customer agreements include these types of contracts:
•
•
Fee-Based Contracts. These contracts provide for a set fee for gathering, transporting, compressing, and treating
services. Our mid-stream’s revenue is a function of the volume of natural gas and is not directly dependent on the
value of natural gas. For the year ended December 31, 2018, 67% of our mid-stream segment’s total volumes and
61% of its operating margins (as defined below) were under fee-based contracts.
Commodity-Based Contracts. These contracts consist of several contract structure types. Under these contract
structures, our mid-stream segment purchases the raw well-head natural gas and settles with the producer at a
stipulated price while retaining all sales proceeds from third parties or retains a negotiated percentage of the sales
proceeds from the residue natural gas and NGLs it gathers and processes, with the remainder being paid to the
producer. For the year ended December 31, 2018, 33% of our mid-stream segment’s total volumes and 39% of
operating margins (as defined below) were under commodity-based contracts.
For each of the above contracts, operating margin is defined as total operating revenues less operating expenses and does
not include depreciation, amortization, and impairment, general and administrative expenses, interest expense, or income taxes.
Customers. During 2018, ONEOK, Inc. accounted for approximately 45% of our mid-stream revenues. We believe that if
we lost this customer, there are other customers available to purchase our gas and NGLs. During 2018, 2017, and 2016 our mid-
stream segment purchased $81.4 million, $63.2 million, and $42.7 million, respectively, of our oil and natural gas segment's
natural gas and NGLs production, and provided gathering and transportation services of $7.3 million, $6.7 million, and $9.2
million, respectively. Intercompany revenue from services and purchases of production between this business segment and our
oil and natural gas segment has been eliminated in our consolidated financial statements.
12
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for oil, NGLs, and natural gas significantly affect our revenues, operating results, cash flow, and our
ability to grow our operations. Oil, NGLs, and natural gas prices have been volatile, and they will probably continue to be so.
For each period indicated, this table shows the highest and lowest average prices our oil and natural gas segment received for its
sales of oil, NGLs, and natural gas without considering the effect of derivatives:
Quarter
2016
First............................. $
Second......................... $
Third............................ $
Fourth.......................... $
2017
First............................. $
Second......................... $
Third............................ $
Fourth.......................... $
2018
First............................. $
Second......................... $
Third............................ $
Fourth.......................... $
Oil Price per Bbl
NGLs Price per Bbl
Natural Gas Price per Mcf
High
Low
High
Low
High
Low
31.49
45.13
41.75
48.80
50.48
48.73
49.66
57.38
63.04
68.61
70.75
69.88
$
$
$
$
$
$
$
$
$
$
$
$
26.62
36.63
41.40
42.71
46.85
43.49
44.54
49.62
58.74
65.76
68.38
47.54
$
$
$
$
$
$
$
$
$
$
$
$
9.49
13.19
14.95
19.07
20.71
15.33
19.99
22.39
22.52
23.46
29.61
25.12
$
$
$
$
$
$
$
$
$
$
$
$
4.54
8.61
9.87
12.14
15.04
14.36
16.17
21.13
20.03
21.14
25.15
16.32
$
$
$
$
$
$
$
$
$
$
$
$
1.86
1.52
2.48
2.85
3.76
2.95
2.53
2.58
2.92
2.23
2.28
3.72
$
$
$
$
$
$
$
$
$
$
$
$
1.20
1.36
2.32
2.25
2.14
2.30
2.04
1.93
2.08
1.96
2.19
2.25
Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the actual
or perceived supply of and demand for oil and natural gas, market uncertainty, and many additional factors beyond our control,
including:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
political conditions in oil producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and Russia to agree on
prices and their ability or willingness to maintain production quotas;
actions taken by foreign oil and natural gas producing nations;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future
prices of oil, NGLs, and natural gas. You are encouraged to read the Risk Factors discussed in Item 1A of this report for
additional risks that can affect our operations.
13
Our contract drilling operations depend on the level of demand in our operating markets. Both short-term and long-term
trends in oil, NGLs, and natural gas prices affect demand. Because oil, NGLs, and natural gas prices are volatile, the level of
demand for our services is also volatile.
Our mid-stream operations provide us greater flexibility in delivering our (and third parties) natural gas and NGLs from
the wellhead to major natural gas and NGLs pipelines. Margins received for the delivery of these natural gas and NGLs depend
on the price for oil, NGLs, and natural gas and the demand for natural gas and NGLs in our area of operations. If the price of
NGLs falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to us to extract certain
NGLs. The volumes of natural gas and NGLs processed depend highly on the volume and Btu content of the natural gas and
NGLs gathered.
COMPETITION
All of our businesses are highly competitive and price sensitive. Competition in the contract drilling business traditionally
involves factors such as demand, price, efficiency, tyy he condition of equipment, availability of labor and equipment, reputation,
and customer relations.
Our oil and natural gas operations likewise encounter strong competition from other oil and natural gas companies. Many
competitors have greater financial, technical, and other resources than we do and have more experience than we do in the
exploration for and production of oil and natural gas.
Our drilling success and the success of other activities integral to our operations will depend, in part, during times of
increased competition on our ability to attract and retain experienced geologists, engineers, and other professionals.
Competition for these professionals can be intense.
Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with
various producers, other major pipeline companies, and independent gatherers for the right to purchase natural gas and NGLs,
build gathering and processing systems, and deliver the natural gas and NGLs once the gathering and processing systems are
established. The principal elements of competition include the rates, terms, and availability of services, reputation, and the
flexibility and reliability of service.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST
Unit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships)
which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas
exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with
2011. We also had three non-employee partnerships, one formed in 1984 and two formed in 1986 (investments by third parties).
Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships
were dissolved.
The employee partnerships formed in 1984 through 1999 have been combined into a single consolidated partnership. The
employee partnerships each have a set annual percentage (ranging from 1% to 15%) of our interest that the partnership acquires
in most of the oil and natural gas wells we drill or acquire for our account during the year in which the partnership was formed.
The total interest the participants have in our oil and natural gas wells by participating in these partnerships does not exceed one
percent of our interest in the wells.
Under our partnership agreements, the general partner has broad discretionary authority to manage the business and
operations of the partnership, including the authority to decide regarding the partnership’s participation in a drilling location or
a property acquisition, the partnership’s expenditure of funds, and distributing funds to partners. Because the business activities
of the limited partners and the general partner are different, conflicts of interest will exist, and it is impossible to entirely
eliminate these conflicts. Additionally, cyy onflicts of interest may arise when we are the operator of an oil and natural gas well
and also provide contract drilling services. In these cases, the drilling operations are conducted under drilling contracts
containing terms comparable to those contained in our drilling contracts with non-affiliated operators. We believe we fulfill our
responsibility to each contracting party and comply fully with the terms of the agreements which regulate these conflicts.
Effective January 1, 2019, we elected to terminate and wind down all of the remaining employee limited partnerships. In
accordance with the partnership agreements, we, as the liquidating trustees will value the interests of the limited partners using
xpect the total purchase price
the formula provided in each partnership agreement and purchase those interests. Presently, we e
yy
14
for all of the limited partners interests will be approximately $0.6 million. We have no plans to sponsor additional employee
limited partnerships.
These partnerships are further described in Notes 2 and 11 to the Consolidated Financial Statements in Item 8 of this
report.
EMPLOYEES
As of February 12, 2019, we had approximately 913 employees in our contract drilling segment, 261 employees in our oil
and natural gas segment, 125 employees in our mid-stream segment, and 77 in our general corporate area. None of our
employees are members of a union or labor organization nor have our operations ever been interrupted by a strike or work
stoppage. We consider relations with our employees to be satisfactory.
GOVERNMENTAL REGULATIONS
General. Our business depends on the demand for services from the oil and natural gas exploration and development
industry, ayy nd therefore our business can be affected by political developments and changes in laws and regulations that control
or curtail drilling for oil and natural gas for economic, environmental, or other policy reasons.
Various state and federal regulations affect the production and sale of oil and natural gas. All states in which we conduct
activities impose varying restrictions on the drilling, production, transportation, and sale of oil and natural gas. This discussion
of certain laws and regulations affecting our operations should not be relied on as an exhaustive review of all regulatory
considerations affecting us, due to the multitude of complex federal, state, and local regulations, and their susceptibility to
change at any time by later agency actions and court rulings that may affect our operations.
Natural Gas Sales and Transportation. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
(FERC) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s jurisdiction
over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to
regulate the maximum selling prices of certain categories of gas sold in “first sales” in interstate and intrastate commerce.
Effective January 1, 1993, however, tr he Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices
for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced
from our natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect.
FERC’s jurisdiction over interstate natural gas transportation is not affected by the Decontrol Act.
Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC
adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are
intended by FERC to foster competition by, ayy mong other things, transforming the role of interstate pipeline companies from
wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines must divest
to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants.
Because of the various omnibus rulemaking proceedings in the late 1980s and the later individual pipeline restructuring
proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and
transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end
users, and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate
services, FERC expanded the impact of open access regulations to certain aspects of intrastate commerce.
FERC has pursued other policy initiatives that affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development
of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to
using electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information
timely and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and
promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates)
for transportation or transportation-related services on the pipeline’s demonstration of lack of market control in the relevant
service market.
Because of these changes, independent sellers and buyers of natural gas have gained direct access to the particular
pipeline services they need and can better conduct business with a larger number of counter parties. These changes generally
have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace.
15
However, we cannot predict what new or different regulations FERC and other regulatory agencies may adopt or what effect
later regulations may have on production and marketing of natural gas from our properties.
Although in the past Congress has been very active in the area of natural gas regulation as discussed above, the more
recent trend has been for deregulation and the promotion of competition in the natural gas industry. In a
deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable.
There continually are legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly
affect the petroleum industry. It is impossible to predict what proposals might be enacted by Congress or the various state
legislatures and what effect these proposals might have on the production and marketing of natural gas by us. Similarly, ayy nd
despite the trend toward federal deregulation of the natural gas industry, wyy
hether or to what extent that trend will continue or
what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted.
ddition to “first sales”
yy
Oil and Natural Gas Liquids Sales and Transportation. Our sales of oil and natural gas liquids currently are not
regulated and are at market prices. The prices received from the sale of these products are affected by the cost of transporting
these products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1,
1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to
certain conditions and limitations. These regulations may increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments could cause decreased rates in a given year. Trr hese regulations have
generally been approved on judicial review. Ew very five years, FERC examines the relationship between the annual change in the
index and the actual cost changes experienced by the oil pipeline industry and makes any necessary adjustment in the index to
be used during the ensuing five years. We cannot predict with certainty what effect the periodic review of the index by FERC
will have on us.
Exploration and Production Activities. Federal, state, and local agencies also have promulgated extensive rules and
regulations applicable to our oil and natural gas exploration, production, and related operations. The states we operate in require
permits for drilling operations, drilling bonds, and filing reports about operations and impose other requirements relating to the
exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including
provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production
from oil and natural gas wells, and regulating spacing, plugging and, abandonment of such wells. The statutes and regulations
of some states limit the rate at which oil and natural gas is produced from our properties. The federal and state regulatory
burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules
and regulations are amended or reinterpreted frequently, we c
laws.
annot predict the future cost or impact of complying with these
yy
Environmental.
General. Our operations are subject to federal, state, and local laws and regulations governing protection of the
environment. These laws and regulations may require acquisition of permits before certain of our operations may be
commenced and may restrict the types, quantities, and concentrations of various substances that can be released into the
environment. Planning and implementation of protective measures must prevent accidental discharges. Spills of oil, natural gas
liquids, drilling fluids, and other substances may subject us to penalties and cleanup requirements. Handling, storage, and
disposal of both hazardous and non-hazardous wastes are subject to regulatory requirements.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource
Conservation and Recovery Act, and their state counterparts, are the primary vehicles for imposition of such requirements and
for civil, criminal, and administrative penalties and other sanctions for violation of their requirements. In addition, the federal
Comprehensive Environmental Response Compensation and Liability Act and similar state statutes impose strict liability,
without regard to fault or the legality of the original conduct, on certain classes of persons considered responsible for the release
of hazardous substances into the environment. Such liability, wyy
conditions others have caused, includes the cost of remedial action and damages to natural resources.
hich may be imposed for the conduct of others and for
The EPA iPP n 2015 established publicly owned treatment works (POTWs) effluent guidelines and standards for oil and gas
extraction facilities which reflected industry best practices for unconventional oil and gas extraction facilities.
The EPA aPP
nd the U.S. Army Corp of Engineers (Army) in 2015 proposed a new expansive definition of the “waters of the
United States,” which the United States Court of Appeals for the Sixth Circuit stayed nationally. On F
Executive Order was issued and directed that the EPA aPP
nd Army consider interpreting the term “navigable waters” in a manner
ebruary 28, 2017, an
yy
16
,
rr
r
d
p
p
nd Army announced
(2006). On March 6, 2017, the EPA aPP
ddition, Army includes wetlands within its definition of
. vacated the Sixth Circuit’s nationwide stay. As a result, on January 31, 2018, the
nd Army issued a rule providing that the 2015 definition of “waters of the United States” will not apply until two years
consistent with Justice Scalia’s opinion in Rapanos v. United States
their intention to review and rescind or revise the 2015 Clean Water Rule and on June 27, 2017 they issued a proposed rule and
written recommendations ("Obama rule"). On January 22, 2018, the United States Supreme Court in National Association of
Manufacturers v. Department of Defense, et al
EPA aPP
following the date this rule is published in the Federal Register. In a
“waters of the United States.” However, due to ongoing litigation, the Obama rule only applies to 28 states, and is enjoined with
respect to the other 22 states challenging the Obama rule until such time as the litigation is resolved. On December 1, 2018, the
EPA aPP
nd Army released a proposed rule which would restrict the definition of “waters of the United States” to traditional large
navigable waters, rivers and lakes and territorial seas used in interstate or foreign commerce as well as the tributaries, navigable
lakes and ponds and tributaries that provide perennial or intermittent flow to them, as well as ditches that are “artificial
channels” used to carry water and meet the conditions of a tributary or are adjacent to wetlands, impoundments of jurisdictional
waters, and wetlands which are adjacent to jurisdictional waters in a “typical year” or which are connected by a channel to
“waters of the United States.” In 2016, the United States Supreme Court in U.S. Army Corps of Engineers v. Hawkes
held that
landowners can challenge in court an Army Corps of Engineers jurisdictional determination. It is anticipated this decision will
provide landowners an important tool in negotiating and resolving conflicts with federal agencies over the extent of wetlands on
a property. During 2018, the United States Courts of Appeals for the Fourth and Ninth Circuits applied the so-called
“hydrological connection” theory to extend jurisdiction of the Clean Water Act to cover pollutants that reach surface waters via
groundwater. The Sixth Circuit addressed the same issue, but rejected the Fourth and Ninth Circuits’ decisions and held the
opposite, consistent with 1994 Fifth Circuit and 2001 Seventh Circuit decisions. In response to an early December 2018 United
States Supreme Court invitation to comment on the Fourth and Ninth Circuit’s decisions, the United States Solicitor General
asked the United States Supreme Court to resolve the Circuit Courts’ split on whether the Clean Water Act applies when
pollutants from a point source reach navigable waters after traveling through the groundwater. Prr
etitions for review of the
Fourth and Ninth Circuits’ decision were filed with the United States Supreme Court in October and briefing completed in
November 2018.
p
y
g
Endangered Species Act. The federal Endangered Species Act, called the “ESA,” and analogous state laws regulate many
activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered
under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and
natural gas exploration and production operators and service companies to incur additional costs or become subject to operating
delays, restrictions or bans in affected areas, which impacts could adversely reduce drilling activities in affected areas. All three
of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within
the areas of our operations. Numerous species have been listed or proposed for protected status in areas in which we provide or
could undertake operations. The U.S. Fish and Wildlife Service ("FWS") and the National Marine Fisheries ("NMFS") in 2016
issued final revised definitions relating to impacts on critical habitats for potentially endangered species allowing exclusion of
certain areas if they will not result in the extinction of the species. In 2017, the Western Governor’s Association issued a Policy
Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to make the act more workable
and understandable. In December 2017, the Interior Department announced that it is working on possible changes to the ESA
with the FWS to revise the regulations for listing endangered and threatened species and for designation of critical habitat. On
July 19, 2018, the FWS and NMFS issued their proposals to revise the ESA regulations, to include: (1) reinstating the prior
two-step approach to designating critical habitat, first considering designation of occupied habitat and then considering non-
occupied habitat only if the existing inhabited area is inadequate to ensure conservation of the species; and (2) removal from the
definition of “adverse modification” by deleting the second sentence in the definition which includes impact to land that
“preclude or significantly delay development [physical or biological] features” essential to the conservation of the species.
However, some of the new proposals may be impacted by the United States Supreme Court’s decision issued in late November
2018. In vacating a United States Court of Appeals for the Fifth Circuit decision involving an endangered species, in
Weyerhaeuser Co. v. U.S. Fish & Wildlife Service
endangered species before the FWS can designate it as “habitat that is critical” and (2) federal courts should review for an abuse
of discretion the FWS’s decision not to exclude a site from designation. In other words, only the actual habitat of an
endangered species can be designated critical habitat, meaning that an uninhabited area that otherwise meets the definition of
critical habitat should not be so designated. The presence of protected species in areas where we provide contract drilling or
mid-stream services or conduct exploration and production operations could impair our ability to timely complete or carry out
those services and, consequently, hyy urt our results of operations and financial position.
, the Supreme Court held that (1) a proposed site must be “habitat” for an
W
y
Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly called “greenhouse
gases,” or GHGs, may be contributing to warming of the Earth’s atmosphere. As a result there have been many regulatory
developments, proposals or requirements, and legislative initiatives introduced in the United States (and other parts of the
World) that are focused on restricting the emission of carbon dioxide, methane, and other greenhouse gases.
17
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA
,
, held that carbon dioxide may be regulated as an
,
ff
ff
ff
A pPP
roposed revisions to these reporting requirements to
“air pollutant” under the federal Clean Air Act if it represents a health hazard to the public. On December 7, 2009, the U.S.
decision and issued a finding that the
Environmental Protection Agency (EPA) responded to the Massachusetts, et al. v. EPA
current and projected concentrations of GHGs in the atmosphere threaten the public health and welfare of current and future
generations, and that certain GHGs from new motor vehicles and motor vehicle engines contribute to the atmospheric
concentrations of GHG and hence to the threat of climate change. In addition, the EPA iPP ssued a final rule, effective in December
2009, requiring the reporting of GHG emissions from specified large (25,000 metric tons or more) GHG emission sources in the
U.S., beginning in 2011 for emissions in 2010. During 2010, the EP
apply to all oil and gas production, transmission, processing, and other facilities exceeding certain emission thresholds. On May
12, 2016, the EPA iPP ssued three final rules that together will curb emissions of methane, smog-forming volatile organic
compounds (VOCs) and toxic air-pollutants such as benzene from new, rww econstructed and modified oil and natural gas sources,
while providing greater certainty about Clean Air Act permitting requirements for the industry ("Methane Rule"). First, the EPA
issued updates to the New Source Performance Standards (NSPS) for the oil and natural gas industry to add requirements that
the industry reduce emissions of GHGs and to cover additional equipment and activities in the oil and natural gas distribution
chain by setting emissions limits for methane and to require owners/operators to find and repair methane and VOC leaks.
Second, the EPA iPP ssued a source determination rule regarding the EPA’PP s air permitting rules as they apply to the oil and natural
gas industry. The EPA cPP
determining whether (i) major source Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review
requirements apply regarding preconstruction permitting and (ii) a Title V Operating permit is required. Third, the EPA iPP ssued a
final rule to implement the Minor New Source Review Program in Indian Country for oil and natural gas production designed
to limit emissions of harmful air pollution while making the preconstruction permitting process more streamlined and efficient.
These regulations will cause additional costs to reduce emissions of GHGs associated with our operations and could hurt
demand for the crude oil we gather, trr
announced in April 2017 it will reconsider the GHG oil and gas emissions rule and delay its compliance, lawsuits have
prevented such an effort. On September 1, 2018, the EPA pPP
would “significantly reduce regulatory burden, saving the industry tens of millions of dollars in compliance each year.” The
EPA pPP
roposes to revise (decrease) the monitoring frequencies for fugitive emissions (leaks) at non-low production well sites,
low production well sites and compressor stations. The EPA aPP
fugitive emissions are detected to complete repairs, provided that a first attempt at repair has to be made within the first 30
days.
larified when multiple pieces of equipment and activities must be deemed a single source for
ransport, store or otherwise handle in connection with our services. Although the EPA
lso proposes to allow owners/operators up to 60 days after
roposed revisions to its Methane Rule, which the EPA ePP
stimates
ff
Hydraulic Fracturing. Our oil and natural gas segment routinely applies hydraulic fracturing techniques to many of our
oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the
Marmaton of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. On July 25, 2017, the Bureau of Land
Management announced a proposal to rescind the 2015 Department of Interior final rule on hydraulic fracturing, a rule that was
never in effect due to pending litigation. Multiple bills have been introduced in Congress that would (i) block federal regulation
of hydraulic fracturing in favor of state rules, (ii) allow a state to regulate hydraulic fracturing on federal lands within that state,
(iii) prevent federal regulation of hydraulic regulation to apply to any land held in trust or restricted status for the benefit of
Indians without their express consent, (iv) repeal the exemption for hydraulic fracturing in the Safe Drinking Water Act, and/or
(v) require the disclosure of chemicals used in hydraulic fracturing. In addition, certain states in which we operate, including
Texas, Oklahoma, Kansas, Colorado, and Wyoming have adopted, and other states and municipalities and other local
governmental entities in some states, have and others are considering adopting regulations and ordinances that could impose
more stringent permitting, public disclosure of fracking fluids, waste disposal, and well construction requirements on these
operations, and even restrict or ban hydraulic fracturing in certain circumstances.
rr
On December 31, 2016, the EPA rPP
eleased its scientific Final Report on Impacts from Hydraulic Fracturing Activities on
tates the report, which was done at the request of Congress, provides scientific evidence that
Drinking Water. The EPA sPP
hydraulic fracturing activities can affect drinking water resources in the United States under some circumstances. The EPA
identifies six conditions under which impacts from hydraulic fracturing activities can be more frequent or severe and existing
uncertainties and data gaps. Both the EPA aPP
nd the United States Geological Survey (USGS) have made statements indicating
that activities associated with hydraulic fracturing may be causing earthquakes, with the focus being on wastewater disposal
wells rather than injection wells. In an August 2015 report sent to the Texas Railroad Commission, the EPA sPP
tated it believes
there is a significant possibility that North Texas earthquake activity is associated with disposal wells. The USGS has stated that
hydraulic fracturing causes small earthquakes, but they are almost always too small to be detected. Regarding disposal wells,
the USGS has stated that the injection of wastewater and salt water by deep wells into the subsurface can cause earthquakes that
are large enough to be felt and may cause damage. As a result, the USGS and its university partners have deployed
seismometers at sites of known or possible injection induced earthquakes in Arkansas, Colorado, Kansas, Oklahoma, Ohio and
Texas and that it is also developing methods to assess the earthquake hazard associated with wastewater injection wells.
18
Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, oryy
increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit
the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our
costs of compliance and doing business and delay the development of unconventional gas resources from shale formations
which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and
natural gas we can ultimately produce from our reserves.
Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws,
regulations, and/or ordinances could increase our compliance costs and/or impose additional operating restrictions on us as well
as those of our customers. Such future developments also might curtail the demand for fossil fuels which could hurt the demand
for our services, which could hurt our future results of operations. Likewise we cannot predict with any certainty whether any
changes to temperature, storm intensity or precipitation patterns because of climate change (or otherwise) will have a material
impact on our operations.
Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our
operations, earnings, or competitive position. However, as n
hydraulic fracturing, compliance with amended, new or more stringent requirements of existing environmental regulations or
requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our
results of operations and financial condition.
oted above in our discussion of the regulation of GHGs and
rr
Item 1A. Risk Factors
FORWARR
RD-LOOKING STATTT EMENTS/CAUTIONARY SRR
TATEMENT AND RISK FACTORS
This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of
Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended.
All statements, other than statements of historical facts, included or incorporated by reference in this document which addresses
re forward-looking statements. The words
activities, events or developments which we expect or anticipate will or may occur, arr
“believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify
forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain
information we file with the SEC in the future will automatically update and supersede information in this report.
These forward-looking statements include, among others, such things as:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
prices for oil, NGLs, and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final outcome of our legal proceedings will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
19
•
•
•
•
•
•
•
•
our ability to transport or convey our oil, NGLs, or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions affecting our costs and increasing operating
restrictions or delays and other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill during the year;
our intended use of the proceeds from the sale of 50% of the interest we owned in our mid-stream segment;
and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have
to record in future periods.
These statements are based on certain assumptions and analyses made by us considering our experience and our
perception of historical trends, current conditions, and expected future developments and other factors we believe are
appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is
subject to several risks and uncertainties any one or combination of which could cause our actual results to differ materially
from our expectations and predictions, including:
•
•
•
•
•
•
•
•
•
•
•
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
risks associated with future weather conditions;
decreases or increases in commodity prices;
putative class action lawsuits that may result in substantial expenditures and divert management's attention;
and
other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we d
ww
isclaim any
intention to update forward-looking information and to release publicly the results of any future revisions we may make to
forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.
To help provide you with a more thorough understanding of the possible effects of these influences on any forward-
looking statements made by us, this discussion outlines some (but not all) of the factors that could cause our consolidated
results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.
Demand for our contract drilling and mid-stream services depends substantially on the levels of expenditures by the oil
substantial or an extended decline in oil and gas prices could cause lower expenditures by the oil and
hich could have a material adverse effect on our financial condition, results of operations and cash flows.
and gas industry. Ayy
gas industry, wyy
Demand for our contract drilling and mid-stream services depends substantially on the level of expenditures by the oil and gas
industry for the exploration, development and production of oil and natural gas reserves. These expenditures depend generally
on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and
the resulting impact on demand for oil and natural gas. Declines, and anticipated declines, in oil and gas prices could also result
in project modifications, delays or cancellations, general business disruptions, and delays in payment of, or nonpayment of,
amounts owed to us. These effects could have a material adverse effect on our financial condition, results of operations and cash
flows.
20
The oil and gas industry has historically experienced periodic downturns, which have been characterized by diminished
demand for oilfield services and downward pressure on the prices we charge. A significant downturn in the oil and gas industry
could cause a reduction in demand for oilfield services and could hurt our financial condition, results of operations and cash
flows.
Oil, NGLs, and Natural Gas Prices. Besides the impact oil and gas prices may have on our contract drilling and mid-
stream segments, the prices we receive for our oil, NGLs, and natural gas production directly affect our revenues, profitability,
and cash flow and our ability to meet our projected financial and operational goals. The prices for oil, NGLs, and natural gas are
determined on several factors beyond our control, including:
•
•
•
•
•
•
•
•
•
•
•
the demand for and supply of oil, NGLs, and natural gas;
weather conditions in the continental United States (which can greatly influence the demand and prices for natural
gas);
the amount and timing of oil, liquid natural gas, and liquefied petroleum gas imports and exports;
the ability of distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas,
particularly in times of peak demand which may result because of adverse weather conditions;
the ability or willingness of the OPEC to set and maintain production levels for oil;
oil and gas production levels by non-OPEC countries;
the level of excess production capacity;
political and economic uncertainty and geopolitical activity;
governmental policies and subsidies;
the costs of exploring for producing and delivering oil and gas; and
technological advances affecting energy consumption.
Oil prices are extremely sensitive to influences domestic and foreign based on political, social or economic
underpinnings, any of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of
oil, NGLs, and natural gas have been at various times influenced by trading on the commodities markets. That trading has
increased the volatility associated with these prices resulting in large differences in prices even on a week-to-week and month-
to-month basis. These factors, especially when coupled with much of our product prices being determined daily, cyy an, and do,
lead to wide fluctuations in the prices we receive.
Based on our 2018 production, a $0.10 per Mcf change in what we receive for our natural gas production, without the
effect of derivatives, would cause a corresponding $439,000 per month ($5.3 million annualized) change in our pre-tax
operating cash flow. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $228,000 per
month ($2.7 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs price,
without the effect of derivatives, would have a $393,000 per month ($4.7 million annualized) change in our pre-tax operating
cash flow.
To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter into
derivative contracts such as swaps and collars. To date, we have derivatives covering part, but not all of our production which
provides price protection only against declines in oil, NGLs, and natural gas prices on the production subject to our derivatives,
but not otherwise. Should market prices for the production we have derivatives exceed the prices due under our derivative
contracts, our derivative contracts then expose us to risk of financial loss and limit the benefit to us of those increases in market
prices. During 2018, all of our NGLs volumes, a quarter of our oil, and about a half of our natural gas volumes were sold at
market responsive prices. To help manage our cash flow and capital expenditure requirements, we had derivative contracts on
approximately 75% and 49% of our 2018 average daily production for oil and natural gas, respectively. A myy
discussion of our derivative arrangements is contained in the Management’s Discussion and Analysis of Financial Condition
and Results of Operations section of this report in Item 7.
ore thorough
Uncertainty of Oil, NGLs, and Natural Gas Reserves; Ceiling Test. Many uncertainties are inherent in estimating
quantities of oil, NGLs, and natural gas reserves and their values, including many factors beyond our control. The oil, NGLs,
and natural gas reserve information in this report represents only an estimate of these reserves. Oil, NGLs, and natural gas
reservoir engineering is a subjective and an inexact process of estimating underground accumulations of oil, NGLs, and natural
21
gas that cannot be measured in an exact manner. Err
depend on several variable factors, including historical production from the area compared with production from other
producing areas, and assumptions about:
stimates of economically recoverable oil, NGLs, and natural gas reserves
•
•
•
•
•
•
•
•
reservoir size;
the effects of regulations by governmental agencies;
ff
future oil, NGLs, and natural gas prices;
ff
future operating costs;
severance and excise taxes;
operational risks;
development costs; and
workover and remedial costs.
Some or all of these assumptions may vary considerably from actual results. For these and other reasons, estimates of the
economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of
those oil, NGLs, and natural gas reserves based on risk of recovery, ayy nd estimates of the future net cash flows from oil, NGLs,
and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially.
Accordingly, oyy il, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual
production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates and
those variances may be material.
The information regarding discounted future net cash flows in this report is not necessarily the current market value of the
estimated oil, NGLs, and natural gas reserves attributable to our properties. Using full cost accounting requires us to use the
unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the
reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual
arrangements. Actual future prices and costs may be materially higher or lower. Arr
part, by these factors:
ctual future net cash flows are also affected, in
•
•
•
•
the amount and timing of oil, NGLs, and natural gas production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.
In addition, the 10% discount factor, rrr equired by the SEC for calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks
associated with our operations or the oil and natural gas industry.
We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the
SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated
future net revenues from those proved reserves, discounted at 10%. Application of this “ceiling test” generally requires pricing
future revenue at the unescalated 12-month average price and requires a write-down for accounting purposes if we exceed the
ceiling. We may be required to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural
gas prices are depressed. If a write-down is required, it would cause a charge to earnings but would not impact our cash flow
from operating activities. Once incurred, a write-down is not reversible.
Debt and Bank Borrowing. We have incurred and expect to continue to incur substantial capital expenditures in our
yy
ave funded our capital needs through a combination of internally generated cash flow and
operations. Historically, we h
borrowings under our bank credit agreements. In 2011 and 2012, we issued $250.0 million (the 2011 Notes) and $400.0 million
(the 2012 Notes), respectively, of s
certain amount of indebtedness. At December 31, 2018, we had no outstanding long-term debt under the Unit or Superior credit
agreement, and $644.5 million, net of unamortized discount and debt issuance costs, under the Notes.
enior subordinated notes (collectively, tyy he Notes). We have, and will continue to have, a
yy
22
Depending on our debt, the cash flow needed to satisfy that debt and the covenants in our bank credit agreements and
those applicable to the Notes could:
•
•
•
limit funds otherwise available for financing our capital expenditures, our drilling program or other activities or cause
us to curtail these activities;
limit our flexibility in planning for or reacting to changes in our business;
place us at a competitive disadvantage to those of our competitors that are less indebted than we are;
• make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if a downturn in our business
occurs; and
•
prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or
any future credit facilities.
Our ability to meet our debt obligations depends on our future performance. If the requirements of our indebtedness are
not satisfied, a default could be deemed to occur and our lenders or the holders of the Notes could accelerate the payment of the
outstanding indebtedness. If that were to happen, we would not have sufficient funds available (and probably could not obtain
the financing required) to meet our obligations.
Our existing debt, and our future debt, if any, iyy s, largely, byy ased on the costs associated with the projects we undertake and
of our cash flow. Generally, oyy ur normal operating costs are those resulting from the drilling of oil and natural gas wells, the
acquisition of producing properties, the costs associated with the maintenance, upgrade, or expansion of our drilling rig fleet,
and the operations of our natural gas buying, selling, gathering, processing, and treating systems. To some extent, these costs,
particularly the first two, are discretionary and we maintain some control regarding the timing or the need to incur them. But,
sometimes, unforeseen circumstances may arise, like an unanticipated opportunity to make a large acquisition or the need to
replace a costly drilling rig component due to an unexpected loss, which could force us to incur additional debt above what we
had expected or forecasted. Likewise, if our cash flow should prove insufficient to cover our cash requirements we would need
to increase our debt either through bank borrowings or otherwise.
RISK FACTORS
Many other factors could hurt our business. This discussion describes the material risks currently known to us. However,
additional risks we do not know about or that we currently view as immaterial may also impair our business or hurt the value of
our securities. You should carefully consider the risks described below together with the other information contained in, or
incorporated by reference into, this report.
If demand for oil, NGLs, and natural gas is reduced, our ability to market and produce our oil, NGLs, and natural gas may
be negatively affected.
Historically, oyy il, NGLs, and natural gas prices have been volatile, with significant increases and significant price drops
being experienced occasionally. Vy
VV
prices. Those factors include, among other things, the domestic and foreign supply of oil, NGLs, and natural gas, the price of
imports, the levels of consumer demand, the price and availability of alternative fuels, the availability of pipeline capacity, ayy nd
changes in existing and proposed federal regulation and price controls.
a significant effect on oil, NGLs, and natural gas
arious factors beyond our control will have
The oil, NGLs, and natural gas markets are also unsettled due to several factors. Production from oil and natural gas wells
in some geographic areas of the United States has been curtailed for considerable periods of time due to a lack of market
demand and transportation and storage capacity. It is p
ossible, however, that some of our wells may be shut-in or that oil,
NGLs, and natural gas will be sold on terms less favorable than might otherwise be obtained should demand for oil, NGLs, and
natural gas decrease. Competition for markets has been vigorous and there remains great uncertainty about prices that
purchasers will pay. Oil, NGLs, and natural gas surpluses could cause our inability to market oil, NGLs, and natural gas
profitably, cyy ausing us to curtail production and/or receive lower prices for our oil, NGLs, and natural gas, situations which
would hurt us.
yy
23
Disruptions in the financial markets could affect our ability to obtain financing or refinance existing indebtedness on
reasonable terms and may have other adverse effects.
Commercial-credit and equity market disruptions may cause tight capital markets in the United States. Liquidity in the
global-capital markets can be severely contracted by market disruptions making terms for certain financings less attractive, and
in certain cases, result in the unavailability of certain types of financing. Because credit and equity market turmoil, we may not
be able to obtain debt or equity financing, or refinance existing indebtedness on favorable terms, which could affect operations
and financial performance.
Oil, NGLs, and natural gas prices are volatile, and low prices have negatively affected our financial results and could do so
in the future.
Our revenues, operating results, cash flow, aww nd growth depend substantially on prevailing prices for oil, NGLs, and
natural gas. Historically, oyy il, NGLs, and natural gas prices and markets have been volatile, and they are likely to continue to be
volatile. Any decline in prices would have a negative impact on our future financial results and our ability to grow our business
segments.
Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the actual
or perceived supply of and demand for oil, NGLs, and natural gas, market uncertainty, ayy nd many additional factors that are
beyond our control. These factors include:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
political conditions in oil producing regions;
the ability of the members of the OPEC to agree on prices and their ability or willingness to maintain production
quotas;
actions taken by foreign oil and natural gas companies;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, ayy nd acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future
prices of oil, NGLs, and natural gas.
Our contract drilling operations depend on levels of activity in the oil, NGLs, and natural gas exploration and production
industry.
Our contract drilling operations depend on the level of activity in oil, NGLs, and natural gas exploration and production
in our operating markets. Both short-term and long-term trends in oil, NGLs, and natural gas prices affect the level of that
activity. Because oil, NGLs, and natural gas prices are volatile, the level of exploration and production activity can also be
volatile. Any decrease from current oil, NGLs, and natural gas prices could further depress the level of exploration and
production activity. This, in turn, would likely result in further declines in the demand for our drilling services and would have
an adverse effect on our contract drilling revenues, cash flows, and profitability. Ayy
s a result, the future demand for our drilling
services is uncertain.
24
The industries in which we operate are highly competitive, and many of our competitors have resources greater than we do.
The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded based on
competitive bids, which may cause intense price competition. Some of our competitors in the contract drilling industry have
greater financial and human resources than we do. These resources may enable them to better withstand periods of low drilling
rig utilization, to compete more effectively based on price and technology, to b
uild new drilling rigs or acquire existing drilling
rigs, and to provide drilling rigs more quickly than we do in periods of high drilling rig utilization.
yy
The oil and natural gas industry is also highly competitive. We compete in the areas of property acquisitions and oil and
natural gas exploration, development, production, and marketing with major oil companies, other independent oil and natural
gas concerns, and individual producers and operators. In addition, we must compete with major and independent oil and natural
gas concerns in recruiting and retaining qualified employees. Many of our competitors in the oil and natural gas industry have
resources substantially greater than we do.
The mid-stream industry is also highly competitive. We compete in areas of gathering, processing, transporting, and
treating natural gas with other mid-stream companies. We are continually competing with larger mid-stream companies for
acquisitions and construction projects. Many of our competitors have greater financial resources, human resources, and
geographic presence larger than we do.
Growth through acquisitions is not assured.
We have experienced growth in each segment, in part, through mergers and acquisitions. The contract land drilling
industry, tyy he exploration and development industry, ayy nd the gas gathering and processing industry, hyy ave experienced significant
consolidation over the past several years, and there can be no assurance that acquisition opportunities will be available. Even if
available, there is no assurance we would have the financial ability to pursue the opportunity. Ayy
nd we are likely to continue to
face intense competition from other companies for acquisition opportunities.
There can be no assurance we will:
•
•
•
•
be able to identify suitable acquisition opportunities;
a
have sufficient capital resources to complete additional acquisitions;
successfully integrate acquired operations and assets;
effectively manage the growth and increased size;
ff
• maintain the crews and market share to operate any future drilling rigs we may acquire; or
•
improve our financial condition, results of operations, business or prospects in any material manner because of any
completed acquisition.
We may incur substantial indebtedness to finance future acquisitions and also may issue debt instruments, equity
securities, or convertible securities in connection with any acquisitions. Debt service requirements could represent a significant
burden on our results of operations and financial condition and issuing additional equity would be dilutive to existing
shareholders. Also, continued growth could strain our management, operations, employees, and other resources.
Successful acquisitions, particularly those of oil and natural gas companies or of oil and natural gas properties, require an
assessment of several factors, many of which are beyond our control. These factors include recoverable reserves, exploration
potential, future oil, NGLs, and natural gas prices, operating costs, and potential environmental and other liabilities. Such
assessments are inexact and their accuracy is inherently uncertain.
Our operations have significant capital requirements, and our indebtedness could have important consequences.
We have experienced and will continue to experience substantial capital needs for our operations. We have $644.5 million
of indebtedness outstanding (net of unamortized discount and debt issuance costs) under the senior subordinated notes we have
issued to-date and, in addition, may borrow up to $425.0 million under the Unit credit agreement and up to $200.0 million
under the Superior credit agreement. As of February 12, 2019, we had $36.2 million outstanding borrowings under our Unit
25
credit agreement and had no outstanding borrowings under our Superior credit agreement. Our level of indebtedness, the cash
flow to satisfy our indebtedness, and the covenants governing our indebtedness could:
•
•
•
limit funds available for financing capital expenditures, our drilling program or other activities or cause us to curtail
these activities;
limit our flexibility in planning for, or r
rr
eacting to changes in, our business;
place us at a competitive disadvantage to some of our competitors that are less leveraged than we are;
• make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if downturn in our business
occurs; and
•
prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or
any future credit facilities.
Our ability to meet our debt service and other contractual and contingent obligations will depend on our future
performance. In addition, lower oil, NGLs, and natural gas prices could cause future reductions in the amount available for
borrowing under our credit agreements, reducing our liquidity, ayy nd even triggering mandatory loan repayments.
The instruments governing our indebtedness contain various covenants limiting the conduct of our business.
The indentures governing our senior subordinated notes and our credit agreements contain various restrictive covenants
that limit the conduct of our business. These agreements place certain limits on our ability to, among other things:
•
•
incur additional indebtedness, guarantee obligations or issue disqualified capital stock;
pay dividends or distributions on our capital stock or redeem, repurchase or retire our capital stock;
• make investments or other restricted payments;
•
•
•
•
•
invest in Unrestricted Subsidiaries over $200.0 million;
grant liens on assets;
enter into transactions with stockholders or affiliates;
sell assets;
issue or sell capital stock of certain subsidiaries; and
• merge or consolidate.
In addition, our credit agreements also requires us to maintain a minimum current ratio and a maximum senior
indebtedness or leverage ratio.
If we violate the restrictions in the indentures governing our senior subordinated notes, our credit agreements or any other
subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related
indebtedness and any other indebtedness to which a cross-acceleration or cross-default provision applies. If that occurs, we may
not make the required payments or borrow sufficient funds to refinance that debt. Even if new financing were available at that
time, it may not be on terms acceptable to us. In addition, lenders may be able to terminate any commitments they had made to
make available further funds.
Our future performance depends on our ability to find or acquire additional oil, NGLs, and natural gas reserves that are
economically recoverable.
Production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Unless we replace the reserves we produce, our reserves will decline, resulting eventually in a decrease
in oil, NGLs, and natural gas production and lower revenues and cash flow from operations. Historically, we h
reserves after taking production into account through exploration and development. We have conducted these activities on our
existing oil and natural gas properties and on newly acquired properties. We may not continue to replace reserves from these
activities at acceptable costs. Lower prices of oil, NGLs, and natural gas may further limit the reserves that can economically be
developed. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
ave increased
yy
26
We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including
acquisitions significantly larger than those consummated by us. We cannot assure you we will successfully consummate any
acquisition, that we can acquire producing oil and natural gas properties that contain economically recoverable reserves or that
any acquisition will be profitably integrated into our operations.
The competition for producing oil and natural gas properties is intense. This competition could mean that to acquire
properties we must pay higher prices and accept greater ownership risks than we have in the past.
Our exploration and production and mid-stream operations involve high business and financial risk which could hurt us.
Exploration and development involve numerous risks that may cause dry holes, the failure to produce oil, NGLs, and
natural gas in commercial quantities and the inability to fully produce discovered reserves. The cost of drilling, completing, and
operating wells is substantial and uncertain. Numerous factors beyond our control may cause the curtailment, delay, oryy
cancellation of drilling operations, including:
•
•
•
•
•
•
•
unexpected drilling conditions;
pressure or irregularities in formations;
capacity of pipeline systems;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs, pressure pumping services, or delivery crews and the delivery of
equipment.
Exploratory drilling is a speculative activity. Ayy
lthough we may disclose our overall drilling success rate, those rates may
decline. Although we may discuss drilling prospects we have identified or budgeted for, we m
these prospects within the expected time frame, or at all. Lack of drilling success will have an adverse effect on our future
results of operations and financial condition.
ay ultimately not lease or drill
rr
Our mid-stream operations involve numerous risks, both financial and operational. The cost of developing gathering
systems and processing plants is substantial and our ability to recoup these costs is uncertain. Our operations may be curtailed,
delayed, or canceled because of many things beyond our control, including:
•
•
•
•
•
•
•
•
unexpected changes in the deliverability of natural gas reserves from the wells connected to the gathering systems;
availability of competing pipelines in the area;
capacity of pipeline systems;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements;
delays in developing other producing properties within the gathering system’s area of operation; and
demand for natural gas and its constituents.
Many of the wells from which we gather and process natural gas are operated by other parties. We have little control over
the operations of those wells which can act to increase our risk. Operators of those wells may act in ways not in our best
interests.
Competition for experienced technical personnel may negatively affect our operations or financial results.
The success of our three segments and the success of our other activities integral to our operations will depend, in part, on
our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for these professionals
can be intense, particularly when the industry is experiencing favorable conditions.
27
Our derivative arrangements might limit the benefit of increases in oil, NGLs, and natural gas prices.
To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter into
derivative contracts. These derivative contracts apply to only a portion of our production and provide only partial price
protection against declines in oil, NGLs, and natural gas prices. These derivative contracts may expose us to risk of financial
loss and limit the benefit to us of increases in prices.
Estimates of our reserves are uncertain and may prove inaccurate.
Numerous uncertainties are inherent in estimating quantities of proved reserves and their values, including many factors
beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Err
economically recoverable oil, NGLs, and natural gas reserves depend on several variable factors, including historical
production from the area compared with production from other producing areas, and assumptions about:
stimates of
•
•
•
•
•
•
•
reservoir size;
the effects of regulations by governmental agencies;
ff
future oil, NGLs, and natural gas prices;
ff
future operating costs;
severance and excise taxes;
development costs; and
workover and remedial costs.
Some or all of these assumptions may vary considerably from actual results. Estimates of the economically recoverable
quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those reserves based on risk of
recovery, ayy nd estimates of the future net cash flows from reserves prepared by different engineers or by the same engineers but
at different times may vary substantially. Ay
Actual production, revenues and expenditures regarding our reserves will likely vary from estimates, and those variances may
be material.
ccordingly, ryy eserve estimates may be subject to downward or upward adjustment.
The information regarding discounted future net cash flows should not be considered as the current market value of the
estimated oil, NGLs, and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted
future net cash flows from proved reserves are based on prices on the first day of the month for each month within the 12-
month period before the end of the reporting period and costs as of the date of the estimate, while actual future prices and costs
may be materially higher or lower. Arr
ctual future net cash flows also will be affected by these factors:
•
•
•
•
the amount and timing of actual production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.
In addition, the 10% per year discount factor, wrr
hich is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from
time to time and risks associated with our operations or the oil and natural gas industry.
If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may have to take write-downs of our oil and
natural gas properties, the carrying value of our drilling rigs or our natural gas gathering and processing systems.
We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the
SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated
future net revenues from proved reserves, discounted at 10% per year. Arr
pplication of the ceiling test generally requires pricing
future revenue at the unweighted arithmetic average of the price on the first day of month for each month within the 12-month
period before the end of the reporting period, unless prices were defined by contractual arrangements, and requires a write-
down for accounting purposes if the ceiling is exceeded. We may be required to write-down the carrying value of our oil and
28
natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would cause a charge
to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas
properties is not reversible later. Brr
write down during a reporting period will not remove the need for us to take additional write downs in one or more succeeding
periods. This would be the case when months with higher commodity prices roll off tff he 12-month period and are replaced with
more recent months having lower commodity prices.
ecause our ceiling tests use a rolling 12-month look back average price it is possible that a
Our drilling equipment, transportation equipment, gas gathering and processing systems, and other property and
equipment are carried at cost. We are required to periodically test to see if these values, including associated goodwill and other
intangible assets, have been impaired whenever events or changes in circumstances suggest the carrying amount may not be
recoverable. If any of these assets are determined to be impaired, the loss is measured as the amount by which the carrying
amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices
for similar assets. Changes in these estimates could cause us to reduce the carrying value of property, eyy quipment, and related
intangible assets. Once these values have been reduced, they are not reversible.
Our operations present inherent risks of loss that, if not insured or indemnified against, could hurt our results of operations.
Our contract drilling operations are subject to many hazards inherent in the drilling industry, iyy ncluding blowouts,
cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment, and damage or loss from
ur exploration and production and mid-stream operations are subject to these and similar risks. These
inclement weather. Or
events could cause personal injury or death, damage to or destruction of equipment and facilities, suspension of operations,
environmental damage, and damage to the property of others. Generally, dyy rilling contracts provide for the division of
responsibilities between a drilling company and its customer, arr nd we seek to obtain indemnification from our drilling customers
by contract for some of these risks. If we cannot transfer these risks to drilling customers by contract or indemnification
agreements (or to the extent we assume obligations of indemnity or assume liability for certain risks under our drilling
contracts), we seek protection from some of these risks through insurance. However, srr ome risks are not covered by insurance
and we cannot assure you that the insurance we have or the indemnification agreements we have will adequately protect us
against liability from the consequences of the hazards described above. An event not fully insured or indemnified against, or the
failure of a customer to meet its indemnification obligations, could cause substantial losses. In addition, we cannot assure you
that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover
all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.
ff
ff
We do not operate many of the wells in which we own an interest. Our operating risks for those wells and our ability to
influence the operations for those wells are less subject to our control. Operators of those wells may act in ways not in our best
interests.
Governmental and environmental regulations could hurt our business.
Our business is subject to federal, state, and local laws and regulations on taxation, the exploration for and development,
production, and marketing of oil and natural gas, and safety matters. Many laws and regulations require drilling permits and
govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties, and other matters.
These laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning our
oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the
jurisdictions where we have production, could limit the number of wells drilled or the allowable production from successful
wells, which could limit our revenues.
We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we
own properties or operate. We could incur liability to governments or third parties for discharges of oil, natural gas or other
pollutants into the air, srr oil or water, including responsibility for remedial costs. We could discharge these materials into the
environment in many ways including:
•
•
•
•
•
fromff
a well or drilling equipment at a drill site;
ff
from gathering systems, pipelines, transportation facilities, and storage tanks;
damage to oil and natural gas wells resulting from accidents during normal operations;
sabotage; and
blowouts, cratering, and explosions.
29
Because the requirements imposed by laws and regulations frequently change, we cannot assure you that future laws and
regulations, including changes to existing laws and regulations, will not hurt our business. The United States Congress and
White House administration may impose or change laws and regulations that will hurt our business. Stricter standards, greater
regulation, and more extensive permit requirements, could increase our future risks and costs related to environmental matters.
In addition, because we acquire interests in properties operated in the past by others, we may be liable for environmental
damage caused by the former operators, which liability could be material.
Any future implementation of price controls on oil, NGLs, and natural gas would affect our operations.
Certain groups have asserted efforts to have the United States Congress impose price controls on either oil, natural gas, or
both. There is no way at this time to know what result these efforts will have nor, if implemented, their effect on our operations.
However, it is possible that these efforts, if successful, would limit the amount we might get for our future oil, NGLs, and
natural gas production. Any future limits on the price of oil, NGLs, and natural gas could also cause hurting the demand for our
drilling services.
Provisions of Delaware law and our by-laws and charter could discourage change in control transactions and prevent
shareholders from receiving a premium on their investment.
Our by-laws and charter provide for a classified board of directors with staggered terms and authorizes the board of
directors to set the terms of preferred stock. In addition, our charter and Delaware law contain provisions that impose
restrictions on business combinations with interested parties. Because of our by-laws, charter, arr nd Delaware law, pww ersons
considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of
directors rather than pursue non-negotiated takeover attempts. These provisions may make it more difficult for our shareholders
to benefit from transactions opposed by an incumbent board of directors.
New technologies may cause our exploration and drilling methods to become obsolete, resulting in an adverse effect on our
production.
Our industry is subject to rapid and significant advancements in technology, iyy ncluding the introduction of new products
and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition,
competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages
and may allow them to implement new technologies before we can. We cannot be certain that we can implement technologies
timely or at a cost acceptable to us. One or more technologies that we use or that we may implement may become obsolete or
may not work as we expected and we may be hurt.
We may be affected by climate change and market or regulatory responses to climate change.
Climate change, including the impact of potential global warming regulations, could have a material adverse effect on our
yy
estrictions, caps, taxes, or other controls on emissions of greenhouse
c) manufacture or produce goods that consume significant energy or burn fossil fuels, including
results of operations, financial condition, and liquidity. Ryy
gases, including diesel exhaust, could significantly increase our operating costs. Restrictions on emissions could also affect our
customers that (a) use commodities we carry to produce energy, (yy b) use significant energy in producing or delivering the
commodities we carry, or (
chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases,
government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or
emissions reductions could materially affect the markets for the commodities associated with our business, which could have a
material adverse effect on our results of operations, financial condition, and liquidity. Gyy
overnment incentives encouraging the
use of alternative sources of energy could also affect certain of our customers and the markets for certain of the commodities
ould face increased
associated with our business in an unpredictable manner that could alter our business activities. Finally, we c
costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our
operations on climate change. These factors, individually or in operation with one or more of the other factors, or other
unforeseen impacts of climate change could reduce the business activity we conduct and have a material adverse effect on our
results of operations, financial condition, and liquidity.
yy
The results of our operations depend on our ability to transport oil, NGLs, and gas production to key markets.
The marketability of our oil, NGLs, and natural gas production depends in part on the availability, pyy roximity, ayy nd capacity
of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of capacity on these systems and
30
facilities could cause the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal
and state regulation of oil, NGLs, and natural gas production and transportation, tax and energy policies, changes in supply and
demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could hurt our ability to
produce, gather and, transport oil, NGLs, and natural gas.
Losing one or several of our larger customers could have a material adverse effect on our financial condition and results of
operations.
During 2018, sales to CVR Refining, LP and Valero Energy Corporation accounted for 14% and 10% of our oil and
natural gas revenues, respectively. Qyy EP Resources, Inc. and Slawson Exploration Company, Iyy nc. were our largest third-party
nd for our
drilling customers accounting for approximately 16% and 10% of our total contract drilling revenues, respectively. Ayy
mid-stream segment, ONEOK, Inc. accounted for approximately 45% of our revenues. No other third party customer accounted
for 10% or more of any of our individual segment revenues. Any of our customers may choose not to use our services and
losing several our larger customers could have a material adverse effect on our financial condition and results of operations if
we could not find replacements.
Shortage of completion equipment and services could delay or otherwise hurt our oil and natural gas segment's operations.
As there is an increase in horizontal drilling activity in certain areas, shortages could cause the availability of third party
equipment and services required for completing wells drilled by our oil and natural gas segment. We could experience delays in
completing some of our wells. Although we can try to reduce the delays associated with these services, we anticipate these
services will be in high demand for the immediate future and could delay, ryy estrict, or curtail part of our exploration and
development operations, which could in turn harm our results.
Our mid-stream segment depends on certain natural gas producers and pipeline operators for a significant portion of its
supply of natural gas and NGLs. Losing any of these producers could cause a decline in our volumes and revenues.
dd
We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. Wyy
hile some of
these producers are subject to long-term contracts, we may not negotiate extensions or replacements of these contracts on
favorable terms, if at all. Losing all or even a portion of the natural gas volumes supplied by these producers, because of
competition or otherwise, could have a material adverse effect on our mid-stream segment unless we acquired comparable
volumes from other sources.
The counterparties to our commodity derivative contracts may not perform their obligations to us, which could materially
affect our cash flows and results of operations.
To reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, ayy nd may in the future,
enter into commodity derivative contracts for a significant portion of our forecasted oil, NGLs, and natural gas production. The
extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, and to the
ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. If one or more of our
counterparties are unable or unwilling to pay us under our commodity derivative contracts, it could have a material adverse
effect on our financial condition and results of operations.
Reliance on management.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or
unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We are subject to various claims and litigation that could ultimately be resolved against us requiring material future cash
payments and/or future material charges against our operating income and materially impairing our financial position.
The nature of our business makes us highly susceptible to claims and litigation. We are subject to various existing legal
claims and lawsuits, which could have a material adverse effect on our consolidated financial position, results of operations, or
cash flows. Any claims or litigation, even if fully indemnified or insured, could negatively affect our reputation among our
customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
31
Derivative regulations in current financial reform legislation could impede our ability to manage business and financial
risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was passed by Congress and signed into
law. This Act contains significant derivative regulations, requiring that certain transactions be cleared on exchanges and a
requirement to post cash collateral (commonly called margin) for such transactions. This Act provides for a potential exception
from these clearing and cash collateral requirements for commercial end-users and it includes several defined terms used in
determining how this exception applies to particular derivative transactions and the parties to those transactions.
We use crude oil and natural gas derivative instruments regarding a portion of our expected production to reduce
commodity price uncertainty and enhance the predictability of cash flows relating the marketing of our crude oil and natural
gas. As commodity prices increase, our derivative liability positions increase; however, nrr one of our current derivative contracts
require posting margin or similar cash collateral when there are changes in the underlying commodity prices referred to in these
contracts.
Depending on the rules and definitions adopted by the Commodity Futures Trading Commission, we could have to post
ff
collateral with our dealer counterparties for our commoditie
s derivative transactions. Such a requirement could have a
significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price
uncertainty and to protect cash flows. Requirements to post collateral would cause significant liquidity issues by reducing our
ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt. In addition, a
requirement for our counterparties to post collateral would likely cause additional costs being passed on to us, thereby
decreasing the effectiveness of our derivative contracts and our profitability.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs
and additional operating restrictions or delays.
Hydraulic-fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil,
natural gas, and associated liquids from dense subsurface rock formations. Our oil and natural gas segment routinely applies
hydraulic-fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in
the Granite Wash of Texas and Oklahoma, the Marmaton and Hoxbar of Oklahoma, the Wilcox of Texas, and the Mississippian
of Kansas. Hydraulic-fracturing involves using water, srr and, and certain chemicals to fracture the hydrocarbon-bearing rock
formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas
commissions; however, tr he Environmental Protection Agency (the EPA) has asserted federal regulatory authority over certain
hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published permitting guidance addressing
the performance of such activities using diesel. The EPA iPP s also seeking to require companies to disclose information regarding
the chemicals used in hydraulic fracturing and the Bureau of Land Management has imposed requirements for hydraulic
fracturing activities of federal lands. In addition, Congress has occasionally considered legislation to provide for federal
regulation of hydraulic-fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.
ff
Certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming, have adopted, and
other states are considering adopting, regulations that could impose more stringent permitting, public disclosure of fracking
fluids, waste disposal, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing
activities altogether. Frr or example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas
and the public of certain information regarding the components used in the hydraulic-fracturing process. Besides state laws,
local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling and/or hydraulic
fracturing. If state, local, or municipal legal restrictions are adopted in areas where we are conducting, or plan to conduct
operations, we may incur additional costs to comply with such requirements that may be significant, experience delays or
curtailment pursuing exploration, development, or production activities, and perhaps even be precluded from the drilling and/or
completion of wells.
There are certain governmental reviews either underway or being proposed that focus on environmental aspects of
hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic-
fracturing practices, and a committee of the United States House of Representatives investigated hydraulic-fracturing practices.
Furthermore, several federal agencies are analyzing, or have been requested to review, mww any environmental issues associated
with hydraulic fracturing. The EPA iPP s evaluating the potential environmental effects of hydraulic fracturing on drinking water
and groundwater. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better
protect the environment from drilling using hydraulic-fracturing completion methods.
32
And certain members of Congress have called on the U.S. Government Accountability Office to investigate how
hydraulic fracturing might hurt water resources, the SEC to investigate the natural gas industry and any possible misleading of
investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic
fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates
regarding natural gas reserves, including reserves from shale formations, and uncertainties associated with those estimates.
These ongoing or proposed studies, depending on their course and results obtained, could spur initiatives to further regulate
hydraulic fracturing under the Safe Drinking Water Act or other regulatory processes.
ff
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including
litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could
also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including
from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal,
state or local laws or implementing regulations regarding hydraulic fracturing could cause a decrease in completing of new oil
and gas wells, increased compliance costs and time, which could hurt our financial position, results of operations, and cash
flows.
Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be
impaired if we cannot acquire adequate supplies of water for our drilling operations and/or completions or cannot dispose of or
recycle the water we use at a reasonable cost and under applicable environmental rules.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our
fracturing operations. We do not have insurance policies in effect intended to provide coverage for losses solely related to
hydraulic fracturing operations; however, orr ur general liability and excess liability insurance policies might cover third-party
claims related to hydraulic fracturing operations and associated legal expenses depending on the specific nature of the claims,
the timing of the claims, and the specific terms of such policies.
Uncertainty regarding increased seismic activity in Oklahoma and Kansas.
We conduct oil and natural gas exploration, development and drilling activities in Oklahoma, Kansas, and elsewhere. In
recent years, Oklahoma and Kansas have experienced a significant increase in earthquakes and other seismic activity. Syy ome
parties believe there is a correlation between certain oil and gas activities and the increased occurrence of earthquakes. The
extent of this correlation is the subject of studies by both state and federal agencies the results of which remain uncertain. We
cannot state at this time what if any impact this seismic activity may have on us or our industry.
The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil, natural gas, and
associated NGLs from many reservoirs requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to d
ispose of or recycle the water used in our oil and natural gas
segment operations, could adversely affect our operations. The imposition of new environmental initiatives and regulations
could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes,
including, but not limited to, produced water, drr
production of oil and natural gas.
rilling fluids, and other wastes associated with the exploration, development or
rr
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and, use of
surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays,
interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse
effect on our operations and financial condition.
We may decide not to drill some prospects we have identified, and locations we drill may not yield oil, NGLs, and natural gas
in commercially viable quantities.
Our oil and natural gas segment's prospective drilling locations are in various stages of evaluation, ranging from a
prospect ready to drill to a prospect that will require additional geological and engineering analysis. Based on many factors,
including future oil, NGLs, natural gas prices, the generation of additional seismic or geological information, and other factors,
we may decide not to drill one or more of these prospects. As a result, we may not increase or maintain our reserves or
production, which in turn could have an adverse effect on our business, financial position, and results of operations. In addition,
the SEC's reserve reporting rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if
they relate to wells scheduled to be drilled within five years of booking. At December 31, 2018, we had 158 proved
33
undeveloped drilling locations. If we do not drill these locations within five years of initial booking, they may not continue to
qualify for classification as proved reserves, and we may have to reclassify such reserves as unproved reserves. The
reclassification of those reserves could also have a negative effect on the borrowing base under our credit facility.
The cost of drilling, completing, and operating a well is often uncertain, and cost factors can hurt the economics of a well.
Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, NGLs, and
natural gas to be commercially viable after drilling, operating, and other costs.
The borrowing base under the Unit credit agreement is determined semi-annually at the discretion of the lenders and is
based in a large part on the prices for oil, NGLs, and natural gas.
ll
Significant declines in oil, NGLs, and natural gas prices may cause a decrease in our borrowing base. The lenders can
unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under the Unit credit
agreement. If outstanding borrowings are over the borrowing base, we must (a) repay the amount in excess of the borrowing
base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments under the Unit credit
agreement.
The amount Superior can borrow under its credit agreement may be impacted by its cash flow.
Superior must maintain a funded debt to consolidated EBITDA ratio of not greater than 4.00 to 1.00. As
ff
a result, if
Superior’s EBITDA falls below $50.0 million, its maximum funded debt would be limited to 4.00 times consolidated EBITDA.
We have $650.0 million outstanding under our 6.625% Senior Subordinated Notes that mature on May 15, 2021.
Our ability to make scheduled payments of the principal and interest on or to refinance our outstanding 6.625% Senior
Subordinated Notes, depends on our financial and operating performance, which is subject to economic, financial, competitive
and other factors, many of which are beyond our control. In addition, our ability to refinance this indebtedness will depend on
the capital and credit markets and our financial condition prevailing at such time. We cannot provide assurance that our
operating performance will generate sufficient cash flow or that our capital resources will be sufficient for payment of our
obligations under this indebtedness or that we will be able to refinance this indebtedness on desirable terms, if at all, which
could result in increased costs to us or require us to sell material assets or operations or use our available cash to meet our
obligations under this indebtedness.
Potential listing of species as “endangered” under the federal Endangered Species Act could cause increased costs and new
operating restrictions or delays on our operations and that of our customers, which could hurt our operations and financial
results.
The federal Endangered Species Act (the ESA) and analogous state laws regulate a variety of activities, including oil and
gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their
habitats. The designation of previously unidentified endangered or threatened species could cause oil and natural gas
exploration and production operators and service companies to incur additional costs or become subject to operating delays,
restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas.
All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered
within the areas of our operations. Numerous species have been listed or proposed for protected status in areas in which we
provide or could in the future undertake operations. In 2016, the U.S. Fish and Wildlife Service and the National Marine
Fisheries issued final revised definitions relating to impacts on critical habitats for potentially endangered species allowing
exclusion of certain areas so long as they will not result in the extinction of the species. In 2017, the Western Governor’s
Association issued a Policy Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to
make the act more workable and understandable. In December 2017, the U.S. Department of Interior (the Interior Department)
announced that it is working on possible changes to the ESA with the U.S. Fish and Wildlife Service to revise the regulations
for listing endangered and threatened species and for designation of critical habitat. The presence of protected species in areas
where we provide contract drilling or mid-stream services or conduct exploration and production operations could impair our
ability to timely complete or carry out those services and, consequently, ayy dversely affect our results of operations and financial
position.
34
Constructing our new proprietary BOSS drilling rigs is subject to risks, including delays and cost overruns, and may not
meet our expectations.
We have designed and built several new proprietary 1,500 horsepower AC electric drilling rigs, which we call BOSS
drilling rigs. This new design should position us to better meet the demands of our customers. Constructing any future new
BOSS drilling rigs is subject to the risks of delays or cost overruns inherent in any large construction project because of
numerous possible factors, including:
•
•
•
•
•
•
•
•
•
•
shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
unanticipated increases in the cost of equipment, labor and raw materials used in construction of our drilling rigs,
particularly steel;
weather interferences;
difficulties in obtaining necessary permits or in meeting permit conditions;
unforeseen design and engineering problems;
ff
failure or delay in obtaining acceptanc
e of the drilling rig from our customer;
ff
failure or delay of third party equipment vendors or service providers; and
lack of demand from the downturn in the oil and gas industry.
On our new BOSS drilling rigs, there can be no assurance we will:
•
•
obtain additional new-build contract opportunities; or
improve our financial condition, results of operations or prospects because of the new drilling rigs.
While we hold certain patents regarding our BOSS drilling rig design, it is still possible that third parties may claim we
infringe their intellectual property rights. We may receive notices from others claiming that our BOSS drilling rig design
infringes on their intellectual property rights. In that event we may resolve these claims by signing royalty and licensing
agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to decline. Besides
money damages, in some jurisdictions plaintiffs can seek injunctive relief that may limit or prevent marketing and use of our
drilling rigs that have infringing technologies.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of
operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, ayy nd economic conditions, including our
operations and our customers, as well as general economic conditions, consumer confidence and spending and market liquidity.
Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. A
cyber incident could result in information theft, data corruption, operational disruption and/or financial loss. Our insurance may
not protect us against such occurrences. Consequently, it is p
could have a material adverse effect on our business, financial condition and results of operations.
ossible that any of these occurrences, or a combination of them,
yy
The oil and natural gas industry has become increasingly dependent upon digital technologies, including information
systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and
operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate
quantities of natural gas reserves, and perform other activities related to our businesses. Our business partners, including
vendors, service providers, and financial institutions, are also dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events,
have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of
misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-
service on websites.
35
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or
information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of
proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as
surveillance, may remain undetected for an extended period.
Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of
third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in
production or delivery, dyy ifficulty in completing and settling transactions, challenges in maintaining our books and records,
environmental damage, communication interruptions, other operational disruptions and third-party liability, iyy ncluding the
following:
•
•
•
•
•
•
a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt
development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber-attack on our facilities may result in equipment damage or failure;
a cyber-attack on mid-stream or downstream pipelines could prevent our product from being delivered, resulting in a
loss of revenues;
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of
revenues;
deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to
regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our
reputation, or a negative impact on the price of our units.
Implementation of various controls and processes to monitor and mitigate security threats and to increase security for our
information, facilities and infrastructure is costly and labor intensive. Moreover, trr here can be no assurance that such measures
will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to
expend significant additional resources to continue to modify or enhance our protective measures or to investigate and
remediate any information security vulnerabilities. We are not aware that any attempts to breach our systems have successfully
occurred.
We are the subject of putative class action lawsuits that may result in substantial expenditures and divert management's
attention.
We are the subject of putative class action lawsuits in Oklahoma raising allegations that we underpaid royalties and that
we failed to pay interest on untimely royalty payments. These lawsuits seek various remedies, including damages, injunctive
relief, and attorney’s fees. For additional information on these lawsuits, see Item
Form 10-K.
3 Legal Proceedings in this Annual Report on
ff
Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation
vigorously, lyy itigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may
arise from time to time could have a material adverse effect on our business, results of operations and financial condition.
Defending the lawsuits may be costly and, further, crr ould require significant involvement of our senior management and may
divert management's attention from our business and operations.
Ineffective internal controls could impact the accuracy and timely reporting of our business and financial results.
Our internal control over financial reporting (ICFR) may not prevent or detect misstatements because of its inherent
limitations, including the possibility of human error, trr he circumvention or overriding of controls, or fraud. Even effective
internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial
statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or
improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed
and we could fail to meet our financial reporting obligations. For example, in connection with the revisions made in this Form
10-K/A, management re-evaluated the effectiveness of our ICFR as of December 31, 2017 and concluded that a deficiency in
our internal controls related to the control over the preparation and review of the financial statements, and therefore, that we did
not maintain effective ICFR as of December 31, 2017. For a description of the material weakness identified by management and
the remediation efforts being implemented for the material weakness, see Part II, Item 9A. Controls and Procedures. If the
36
enhanced controls implemented to address the material weakness and to strengthen the overall internal control related to the
preparation and review of the financial statements are not designed or do not operate effectively, if we a
implementing or following these enhanced processes, or we are otherwise unable to remediate the material weakness, this may
result in untimely or inaccurate reporting of our financial results.
re unsuccessful in
yy
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information called for by this item was consolidated with and disclosed in connection with Item 1 above.
a
Item 3. Legal Proceedings
Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer
County, Oyy
klahoma.
Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita
elody Culberson, and Charlotte Abernathy are the Plaintiffs and are royalty owners in oil and gas drilling and
he Plaintiffs’ central allegation is that the
Golightly, Myy
spacing units for which the company’s exploration segment distributes royalty. Tyy
company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees.
Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma
production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. Www e hWW ave also
asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if
any, dyy eductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May
11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the Supreme
Court for certiorari and on October 8, 2012, the Plaintiff’ff s petition was denied. On January 22, 2013, the Plaintiffs filed a
second request to certify a class of royalty owners slightly smaller than their first attempt. Since then, the Plaintiffs have further
amended their proposed class to just include royalty owners entitled to royalties under certain leases in Latimer, Le F
Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, besides the defenses described
above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial
class certification. Closing arguments were held on December 2, 2014. There is no timetable for when the court will issue its
ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.
lore, and
rr
ff
Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, UPP nited States District Court for the
Eastern District of Oklahoma.
On March 11, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Cockerell Oil
klahoma. We removed the case to federal court in the Eastern
Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oyy
District of Oklahoma. The plaintiff aff
lleges that Unit Petroleum wrongfully failed to pay interest with respect to untimely royalty
payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting,
disgorgement, injunctive relief, and attorney’s fees. Plaintif
ff
f is s
wells. We have asserted several defenses including that the case cannot be properly certified as a class action because of the
wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under
Oklahoma law. The issue of class certification has not been heard by the court.
eeking relief on behalf of royalty owners in our Oklahoma
ff
Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oyy
klahoma.
On November 3, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Chieftain Royalty
klahoma. Plaintiff aff
Company v. Unit Petroleum Company in LeFlore County, Oyy
lleges that Unit Petroleum breached its duty to
pay royalties on natural gas used for fuel off tff he lease premises. The lawsuit seeks actual and punitive damages, an accounting,
eeking relief on behalf of Oklahoma citizens who are or were royalty owners
ff
injunctive relief, and attorney’s fees. Plaintif
f is s
in our Oklahoma wells. We filed a motion to dismiss on the basis that the claims asserted by the Plaintiff aff nd the putative class
are barred because they have already been asserted by the putative class in the Panola lawsuit and are subject to its reversal of
class certification. The court denied our motion to dismiss and we have asked the court to certify its order so that it can be
immediately appealed. That issue is still pending before the court. If we do not ultimately prevail on our claim of issue
preclusion, we have several other defenses, including that the case cannot be properly certified as a class action because of the
ff
37
wide variety of circumstances that determine whether a royalty payment was wrongfully withheld. The issue of class
certification has not been heard by the court.
We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion
with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Ryy
Securities
elated Stockholder Matters, and Issuer Purchases of Equity
Our common stock trades on the New York Stock Exchange under the symbol “UNT.” The high and low closing sales
prices per share of our common stock can be easily accessed for free on numerous websites.
On February 12, 2019, the closing sale price of our common stock, as reported by the NYSE, was $15.55 per share. On
that date, there were approximately 738 holders of record of our common stock.
We have declared no cash dividends on our common stock. Any future determination by our board of directors to pay
dividends on our common stock will be made only after considering our financial condition, results of operations, capital
requirements, and other relevant factors. Our bank credit agreements and the Notes prohibit the payment of cash dividends on
our common stock under certain circumstances. For further information regarding our bank credit agreements and the Notes
agreement’s impact on our ability to pay dividends see “Our Credit Agreements and Senior Subordinated Notes” under Item 7
of this report.
38
Performance Graph. The following graph and related information shall not be deemed “soliciting material” or be deemed
to be “filed” with the SEC, nor will this information be incorporated by reference into any future filing, except to the extent that
we specifically incorporate it by reference into that filing.
Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the
cumulative total return of the S&P 500 Stock Index, S&P 600 Oil and Gas Exploration & Production, and a peer group chosen
by us. We changed our peer group for the performance graph to align with the 2018 peer group used by the compensation
committee of our board of directors. Our new peer group consists of Cabot Oil & Gas Corp., Carrizo Oil & Gas, Inc., Cimarex
Energy Co., Denbury Resources, Inc., Helmerich & Payne, Inc., Laredo Petroleum, Inc., Newfield Exploration Co., Oasis
Petroleum, Inc., Parker Drilling Co., Patterson-UTI Energy, Inc., PDC Energy, Inc., Pioneer Energy Services Corp., SM Energy
Co., Whiting Petroleum Corp., and WPX Energy, Inc. Our old peer group consisted of Helmerich & Payne, Inc., Patterson –
UTI Energy Inc., and Pioneer Energy Services Corp. We decided to use the new peer group because we measure our
performance against theirs to determine components of our executives’ compensation, and we believe that the new peer group
better reflects the diversified nature of our energy operations than the old peer group. The graph below assumes an investment
of $100 at the beginning of the period. The shareholder return set forth below is not necessarily indicative of future
performance.
39
Item 6. Selected Financial Data
The following table shows selected consolidated financial data. The data should be read in conjunction with Item 7
“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a review of 2018, 2017, and
2016 activity.
As of and for the Year Ended December 31,
2018
2017
2016
2015
2014
(In thousands except per share amounts)
Revenues................................................... $
843,281
$
739,640
Net income (loss) attributable to Unit
Corporation........................................... $
(45,288) (4) $
117,848
Net income (loss) attributable to Unit
Corporation per common share:
Basic.................................................... $
(0.87)
$
Diluted................................................. $
Total assets................................................ $
Long-term debt (5)..................................... $
Other long-term liabilities (6).................... $
(0.87)
$
2,698,053 (4) $
644,475
101,527
Cash dividends per common share........... $
—
2.31
2.28
2,581,452
820,276
100,203
—
$
$
$
$
$
$
$
$
$
$
$
602,177
$
854,231
$
1,572,944
(135,624) (3) $ (1,037,361) (2) $
136,276 (1)
(2.71)
$
(21.12)
$
2.80
(2.71)
$
2,479,303 (3) $
(21.12)
$
2,799,842 (2) $
2.78
4,463,473 (1)
800,917
103,479
—
$
$
$
918,995
140,626
—
$
$
$
801,908
148,785
—
_________________________
1.
In December 2014, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million, net of tax),
a non-cash write-down associated with the removal of 31 drilling rigs from our fleet along with certain other equipment and drill pipe of $74.3 million
pre-tax ($46.3 million, net of tax), and a non-cash write-down associated with a reduction in the carrying value of three mid-stream segment systems of
$7.1 million pre-tax ($4.4 million, net of tax).
2.
3.
4.
5.
6.
In total for 2015, we incurred non-cash ceiling test write-downs on our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). We
also incurred a non-cash write-down on certain drilling rigs and other equipment of approximately $8.3 million pre-tax ($5.1 million, net of tax), and a
non-cash write-down associated with a reduction in the carrying value of three mid-stream segment systems of $27.0 million pre-tax ($16.8 million, net of
tax).
For the first three quarters of 2016, we incurred non-cash ceiling test write-downs on our oil and natural gas properties of $161.6 million pre-tax ($100.6
million, net of tax).
In December 2018, we incurred a non-cash write-down associated with the removal of 41 drilling rigs from our fleet of $147.9 million pre-tax
($111.7 million, net of tax).
Long-term debt is net of unamortized discount and debt issuance costs.
Includes non-current derivative liabilities, if any.
40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Please read this discussion of our financial condition and results of operations with the consolidated financial
statements and related notes in Item 8 of this report.
tt
General
yy
We were founded in 1963 as a contract drilling company. Tyy oday
, we o
TT
perate, manage, and analyze our results of
operations through our three principal business segments:
•
•
Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. Tyy
acquires, and produces oil and natural gas properties for our own account.
his segment explores, develops,
Contract Drilling
CC
and natural gas wells for others and for our own account.
– carried out by our subsidiary Unit Drilling Company. Tyy
his segment contracts to drill onshore oil
• Mid-Stream – carried out by our subsidiary Superior Pipeline Company, Lyy
.L.C. and its subsidiaries. This segment
buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We own 50% of this
subsidiary.
Business Outlook
di
d i
i
As discussed in other parts of this report, our success depends, to la l
l
il
natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the
h
amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United
i d
i
States affect us and our industry.
arge degree, on the prices we receive for our oil and
d
i
h
h d
h
f
i d
i
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hi h i fl
f hi
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ff
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d
d
d
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d
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fff
fy f
l i
h
b
i
or the extended time, can result in industry wide reductions in drilling activity and spending which reduce the rates
Fluctuating commodity prices can result in significant changes to our industry and us. Depressed commodity prices,
h
particularl
particularl
d
f
for and the number of our drilling rigs we were able to put to work. Such industry wide reductions in drilling activity and
d h
d
spending for extended periods also reduces the rates for and the number of our drilling rigs we can work. In addition, sustained
i d
d h
f
l
lower commodity prices impact the liquidity condition of some of our industry partners and customers, which could limit their
i h i
ability to meet their financial obligations to us.
bili
d
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During the last three years, commodity prices have been volatile. Late in 2016, commodity prices improved over 2015. In
l
h l
di
di
b
h
h
i
i
i
i
f
h
the fourth quarter of 2016, our oil and natural gas segment began using two of our drilling rigs and used two to three drilling
h f
th improved commodity prices during the first quarter of 2018, our oil and natural gas segment put
rigs throughout 2017.
h
i
four of our drilling rigs to work and increased the number to six drilling rigs for ba b i f
i
d illi
f
i
d i
l
b
We h
k
have subsequently reduced our operated rig count.
d
l
rief period during the third quarter of 2018.
h hi d
d
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il
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di
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d i
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d illi
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41
The following chart reflects the significant fluctuations in the prices for oil and natural gas:
We incurred non-cash ceiling test write-downs in the first nine months of 2016 totaling $161.6 million ($100.6 million,
net of tax). We had no write-downs in 2017 or 2018. It is hard to predict with any reasonable certainty the need for or amount of
any future impairments given the many factors that go into the ceiling test calculation including, future pricing, operating costs,
drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax
attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2018,
and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2019 prices constant
for the remaining one month of the first quarter of 2019), our forward looking expectation is that we will not recognize an
impairment in the first quarter of 2019. But commodity prices (and other factors) remain volatile and they could negatively
affect the 12-month average price resulting in the potential for a future impairment.
The number of gross wells our oil and gas segment drilled in 2018 verses 2017 increased from 70 wells to 117 wells due
to increased cash flow. For 2019, we plan to decrease the number of gross wells drilled to 90-100 wells (depending on future
commodity prices).
Our contract drilling segment completed the construction of three additional BOSS drilling rigs between the fourth
quarter of 2016 and the third quarter of 2018. During the second quarter and third quarter of 2018, we were awarded term
contracts to build our 12th and 13th BOSS drilling rigs. Construction was completed for one of these in January and it was
placed into service for a third-party operator. Recently the other contract was terminated but we were able to find another third-
party operator and it was placed into service in February. Rig utilization fluctuated over the past year due to commodity prices
changing and budget constraints on operators. We expect commodity prices and budget constraints on operators to continue to
affect rig utilization throughout 2019. In 2016, utilization bottomed out in May at 13 operating drilling rigs. As commodity
prices began improving for the remainder of 2016, we exited the year with 21 active rigs. As of December 31, 2017, we had 31
drilling rigs operating. During 2018, utilization increased from 31 to a high of 36 drilling rigs and with a decline in commodity
prices during the fourth quarter, declined to 32 drilling rigs as of December 31, 2018. As of December 31, 2018, all 11 of our
BOSS drilling rigs were operating.
In December 2018, we removed from service 41 drilling rigs, some older top drives, and certain drill pipe that has been
reclassed to 'Assets held for sale.' As of February 12, our drilling rig fleet totaled 56 drilling rigs.
During 2018, due to low ethane and residue prices, we operated some of our mid-stream processing facilities in ethane
rejection mode which reduces the liquids sold. At the end of 2018 and into the first part of 2019, as NGLs and gas prices
42
improved, we began operating some of our mid-stream processing facilities in ethane recovery mode. We are continuing to
monitor commodity prices to determine the most economical method in which to operate our processing facilities.
On April 3, 2018, we completed the sale of 50% of the ownership interests in Superior to SP Investor Holdings, LLC, a
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In December 2018, we closed on an acquisition of certain oil and natural gas assets located primarily in Custer County,
Oklahoma. The total preliminary adjusted value of consideration given was $29.6 million. As of November 1, 2018, the
effective date of the acquisition, the estimated proved oil and gas reserves for the acquired properties was 2.6 MMBoe net to
Unit. The acquisition added approximately 8,667 net oil and gas leasehold acres to our Penn Sands area in Oklahoma including
approximately 44 wells. The acquisitions included approximately 30 potential horizontal drilling locations which are anticipated
to have a high percentage of oil relative to the total production stream. Of the acreage acquired, approximately 82% was held by
production.
Executive Summary
Oil and Natural Gas
Fourth quarter 2018 production from our oil and natural gas segment was 4,318 MBoe, a decrease of 1% from the third
quarter of 2018 and was essentially unchanged from the fourth quarter of 2017. The decrease from the third quarter came from
fewer net wells being completed in the fourth quarter. Orr
the fourth quarter of 2018 and the fourth quarter of 2017.
il and NGLs production was 46% of our total production during both
Fourth quarter 2018 oil and natural gas revenues decreased 5% from the third quarter of 2018 and increase
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fourth quarter of 2017. The decrease from the third quarter was primarily due to a decrease in production and decrease in oil
and NGL prices partially offset by an increase in natural gas prices. The increase over the fourth quarter 2017 was primarily due
to higher unhedged natural gas prices and higher oil and natural gas production volumes.
Our hedged natural gas prices for the fourth quarter of 2018 increased 22% and 16% over third quarter of 2018 and fourth
quarter of 2017, respectively. Our hedged oil prices for the fourth quarter of 2018 decreased 6% and 1% from the third quarter
of 2018 and the fourth quarter of 2017, respectively. Our hedged NGLs prices for the fourth quarter of 2018 decreased 24% and
10% from the third quarter of 2018 and fourth quarter of 2017, respectively.
Direct profit (oil and natural gas revenues less oil and natural gas operating expense) decreased 6% from the third quarter
of 2018 and increased 12% over the fourth quarter of 2017. The decrease from the third quarter of 2018 was primarily due to a
decrease in production, a decrease in oil and NGLs prices, and an increase in lease operating expenses (LOE) partially offset by
an increase in natural gas prices. The increase over the fourth quarter of 2017 was primarily due to higher revenues due to rising
unhedged oil and natural gas prices and increased oil and natural gas production volumes.
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Operating cost per Boe produced for the fourth quarter of 2018 decreased 2% from the third quarter of 2018 and
decreased 11% from the fourth quarter of 2017. The decrease from the the third quarter of 2018 was primarily due to lower
gross production taxes due to tax credits received and decrease tax from lower revenues and lower saltwater disposal expense
partially offset by higher LOE and general and administrative (G&A) expenses net of geological and geophysical capitalized.
The decrease from the fourth quarter of 2017 was primarily due to the reclass of deduction to revenues under ASC 606 offset
partially by production that was essentially unchanged.
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43
At December 31, 2018, these non-designated hedges were outstanding:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Jan’19 – Mar'19
Natural gas – swap
Apr'19 – Dec'19
Natural gas – swap
50,000 MMBtu/day
40,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
20,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
10,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
30,000 MMBtu/day
Jan’20 – Dec'20
Natural gas – basis swap
30,000 MMBtu/day
$3.440
$2.900
$(0.659)
$(0.625)
$(0.265)
$(0.275)
IF – NYMEX (HH)
IF – NYMEX (HH)
PEPL
NGPL MIDCON
NGPL TEXOK
NGPL TEXOK
Jan’19 – Dec'19
Natural gas – collar
20,000 MMBtu/day
$2.63 - $3.03
IF – NYMEX (HH)
Jan'19 – Mar'19
Natural gas – three-way collar
30,000 MMBtu/day
$3.17 - $2.92 - $4.32
IF – NYMEX (HH)
Jan’19 – Dec'19
Crude oil – three-way collar
4,000 Bbl/day
$61.25 - $51.25 - $72.93
WTI – NYMEX
After December 31, 2018, these non-designated hedges were entered into:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Apr'19 – Oct'19
Natural gas – swap
20,000 MMBtu/day
$2.900
IF – NYMEX (HH)
In our Wilcox play, located primarily in Polk, Tyler, Hardin, and Goliad Counties, Texas, we completed seven vertical and
one horizontal well (average working interest 100%) in 2018, all of which were completed as gas/condensate producers. Annual
production from our Wilcox play averaged 89 MMcfe per day (9% oil, 27% NGLs, 64% natural gas) which is a decrease of 2%
compared to 2017. We averaged approximately 0.7 Unit drilling rigs operating during 2018 and we plan to use one Unit drilling
rig during 2019. We anticipate completing approximately 13 vertical wells during 2019. In addition, we plan to complete
approximately ten behind pipe gas and liquids zones.
In our Southern Oklahoma Hoxbar Oil Trend (SOHOT) play, in western Oklahoma primarily in Grady County, we
completed seven horizontal oil wells (average working interest 77.6%) in the Marchand zone of the Hoxbar interval. In our
Western STACK area, we completed two horizontal wells (average working interest 94.8%), and in our Thomas Field (Red
Fork), we completed two horizontal wells (average working interest 79.2%). Annual production from western Oklahoma
averaged 76.4 MMcfe per day (33% oil, 21% NGLs, 46% natural gas) which is an increase of approximately 26% compared to
2017. During 2018, we averaged approximately 1.4 Unit drilling rigs operating, and we currently plan to use approximately
three Unit drilling rigs for the first half of 2019. We anticipate completing approximately eight horizontal Marchand wells in
our SOHOT play and eight horizontal wells in our Red Fork play in Thomas Field during 2019. During 2018, we participated in
61 non-operated wells in the mid-continent region, with most of those occurring in the STACK play. Unit’s average working
interest in these wells is 3.7%.
In our Texas Panhandle Granite Wash play, we completed 12 extended lateral horizontal gas/condensate wells (average
working interest 99.7%) in our Buffalo Wallow field. Annual production from the Texas Panhandle averaged 96.3 MMcfe per
day (10% oil, 39% NGLs, 51% natural gas) which is an increase of approximately 11% compared to 2017. We used 1.3 Unit
drilling rigs during 2018 and ww plan to operate one Unit drilling rig for the first four months of the year in 2019. We anticipate
completing approximately four extended lateral Granite Wash horizontal wells in our Buffalo Wallow field during 2019.
In 2018, we performed two recompletions on existing wells in our Panola Field. Both recompletions were upper zones in
the Lower Atoka formation. We also drilled one vertical well that targeted the Middle Atoka. We plan on drilling one vertical
well in early 2019 that will target the Middle Atoka.
During 2018, we participated in the drilling of 117 wells (33.16 net wells). For 2019, we plan to participate in the drilling
of approximately 90 to 100 gross wells. Our 2019 production guidance is approximately 17.4 to 17.9 MMBoe, an increase of
2-5% over 2018, actual results which will be subject to many factors. This segment’s capital budget for 2019 ranges from
approximately $271.0 million to $315.0 million, a decrease of 21% to 9% from 2018, excluding acquisitions and ARO liability.
44
Contract Drilling
The average number of drilling rigs we operated in the fourth quarter was 33.1 compared to 34.2 and 31.2 in the third
quarter of 2018 and fourth quarter of 2017, respectively. As of December 31, 2018, 32 of our drilling rigs were operating.
Revenue for the fourth quarter of 2018 increased 5% over the third quarter of 2018 and increased 14% over the fourth
quarter of 2017. The increase over the third quarter of 2018 was primarily due to higher dayrates partially offset by fewer
drilling rigs operating. The increase over the fourth quarter of 2017 was primarily due to more drilling rigs operating and higher
dayrates.
Dayrates for the fourth quarter of 2018 averaged $18,047, a 3% increase over the third quarter of 2018 and an 8%
increase over the fourth quarter of 2017. The increase over the third quarter of 2018 was primarily due to general increases with
the improving market and the addition of a BOSS drilling rig. The increase over the fourth quarter of 2017 was primarily due to
two labor increases passed through to contracted rig rates and improving market dayrates.
Operating costs for the fourth quarter of 2018 increased 12% over the third quarter of 2018 and increased 14% over the
fourth quarter of 2017. The increase over the third quarter of 2018 was primarily due to a decrease in eliminations with a lower
percentage of our drilling rig usage coming from our oil and gas segment and increased indirect and G&A expenses, partially
offset by decreased direct cost with decrease utilization. The increase over the fourth quarter of 2017 was primarily due to more
drilling rigs operating and increased per day cost.
Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2018 decreased
8% from the third quarter of 2018 and increased 12% over the fourth quarter of 2017. The decrease from the third quarter of
2018 was primarily due to fewer drilling rigs operating and increased indirect and drilling G&A expenses while the increase
over the fourth quarter of 2017 was primarily due to more drilling rigs operating.
Operating cost per day for the fourth quarter of 2018 increased 15% over the third quarter of 2018 and increased 8% over
the fourth quarter of 2017. The increase over the third quarter of 2018 was primarily due to decreased eliminations with a lower
percentage of our drilling rig usage coming from our oil and gas segment and higher per day indirect and G&A costs. The
increase over the fourth quarter of 2017 was primarily due to more rigs operating.
In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR
diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9.
Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on
our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that
we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the
estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these
estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax).
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The contract drilling segment has operations in Oklahoma, Texas, Louisiana, Kansas, Colorado, Utah, Wyoming,
Montana and North Dakota. As of December 31, 2018, 18 rigs were working in Oklahoma and the Texas Panhandle, one in East
Texas, and six in the Permian Basin of West Texas, two drilling rigs in Wyoming and five drilling rigs in the Bakken Shale of
North Dakota.
During 2018, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The
future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates.
As of December 31, 2018, we had 24 term drilling contracts with original terms ranging from six months to three years.
Seventeen of these contracts are up for renewal in 2019, (seven in the first quarter, seven in the second quarter, one in the third
quarter, and two in the fourth quarter) and seven are up for renewal in 2020 and beyond. Term contracts may contain a fixed
rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had
signed term contracts have opted to release the drilling rig and pay an early termination penalty for the remaining term of the
contract. We recorded $0.1 million, $0.8 million, and $3.1 million in early termination fees in 2018, 2017, and 2016,
respectively. In the first quarter of 2019, we recorded $4.6 million in early termination fees.
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All 13 of our existing BOSS drilling rigs are under contract.
All of our contracts are daywork contracts.
45
Our anticipated 2019 capital expenditures for this segment ranges from approximately $30.0 million to $65.0 million, a
60% to 14% decrease from 2018.
Mid-Stream
Fourth quarter 2018 liquids sold per day was essentially unchanged from the third quarter of 2018 and increased 20%
over the fourth quarter of 2017. The increase over the fourth quarter of 2017 was due primarily to more processed volume from
connecting additional wells to our systems. For the fourth quarter of 2018, gas processed per day was essentially unchanged
from the third quarter of 2018 and increased 8% over the fourth quarter of 2017. The increase over the fourth quarter of 2017
was due to connecting additional wells to our processing systems. For the fourth quarter of 2018, gas gathered per day
decreased 5% from the third quarter of 2018 and increase
quarter of 2018 was primarily due to declining volumes from the Appalachian region and the increase over the fourth quarter of
2017 was mainly due to connecting the infill wells on the Pittsburgh Mills gathering system.
d 3% over the fourth quarter of 2017. The decrease from the third
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NGLs prices in the fourth quarter of 2018 decreased 20% and 23% from the prices received in the third quarter of 2018
and the fourth quarter of 2017, respectively. Because certain of the contracts used by our mid-stream segment for NGLs
transactions are commodity-based contracts – under which we receive a share of the proceeds from the sale of the NGLs – our
revenues from those commodity-based contracts fluctuate based on NGLs prices.
Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2018 decreased 16% and
5% from the third quarter of 2018 and fourth quarter of 2017, respectively. The decrease from the third quarter of 2018 was
primarily due to lower NGLs and condensate prices. The decrease from the fourth quarter of 2017 was primarily due to the
increased revenues from the timing of demand fees recognition under ASC 606 along with a decrease in NGLs prices. Total
operating cost for this segment for the fourth quarter of 2018 increased 1% over the third quarter of 2018 and decreased 1%
from the fourth quarter of 2017. The increase over the third quarter of 2018 was primarily due to a decrease from the third
quarter of 2018 in purchases made from our oil and gas segment that was eliminated and the increase over the fourth quarter of
2017 was due primarily to higher field direct operating expenses.
In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the fourth quarter of
2018 was approximately 129.7 MMcf per day and the annual average gathered volume was 123.9 MMcf per day. In 2
added seven new infill wells late in the second quarter and all the new infill wells are currently online and flowing gas. We have
completed construction of the new pipeline to connect the next scheduled well pad to our system. We have also completed the
upgrade of the compressor station and dehydration facilities. Production from this new pad started online during January 2019.
018, we
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At the Hemphill Texas system, average total throughput volume for the fourth quarter of 2018 increased to 75.3 MMcf
per day and total production of natural gas liquids was approximately 301,500 gallons per day during this same period. The
annual average throughput volume was 72.6 MMcf per day while the annual total production of natural gas liquids averaged
264,971 gallons per day. During the fourth quarter, we connected five new wells in the Buffalo Wallow area. These new wells
along with increased production from recently drilled wells in this area contributed to the increased throughput volume. Our oil
and gas segment continues to operate a rig in the Buffalo Wallow area and we anticipate connecting additional wells to this
system in 2019.
At the Cashion processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2018 averaged
approximately 49.2 MMcf per day and total production of natural gas liquids increased to 246,873 gallons per day. Tyy he annual
average throughput volume was 46.0 MMcf per day and the annual average natural gas liquids production was 234,316 gallons
per day. This system is currently operating at full processing capacity and we are adding additional capacity to this system. We
are relocating a 60 MMcf per day processing plant from our Bellmon facility to the Cashion area. This processing plant will be
installed at the Reeding site on the Cashion system. This plant is expected to be operational by the end of the first quarter of
2019 and it will increase our total processing capacity on the Cashion system to approximately 105 MMcf per day. We
connected eight new wells to this system during the fourth quarter of 2018 and we are continuing to connect additional wells
from a third party producer who continues to be active in this area.
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At the Minco processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2018 was
approximately 8.0 MMcf per day and the average annual total throughput volume was 9.5 MMcf per day. Dyy
quarter of 2018 we completed a new interconnect with a producer who is currently delivering gas to our system. Additionally,
we are completing construction of a new well connect for a third party producer who is expected to deliver gas to our system in
2019. The current processing capacity of the Minco facility is approximately 12 MMcf per day.
uring the fourth
46
Anticipated 2019 capital expenditures for this segment range from approximately $35.0 million to $42.0 million, a 22% to
6% decrease from 2018.
Critical Accounting Policies and Estimates
Summary
In this section, we identify those critical accounting policies we follow in preparing our financial statements and related
disclosures. Many policies require us to make difficult, subjective, and complex judgments while making estimates of matters
inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent there is reasonable
likelihood that materially different amounts could have been reported under different conditions, or had different assumption
been used. We evaluate our estimates and assumptions regularly. Wyy
e bWW ase our estimates on historical experience and various
other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the
carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates
and assumptions used in preparation of our financial statements. In this discussion we attempt to explain the nature of these
estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial
statements under different conditions or using different assumptions.
47
This table lists the critical accounting policies, identifies the estimates and assumptions that can have a significant impact
on applying these accounting policies, and the financial statement accounts affected by these estimates and assumptions.
Accounting Policies
Full cost method of accounting for oil,
NGLs, and natural gas properties
• Oil, NGLs, and natural gas reserves,
estimates, and related present value of
future net revenues
• Valuation of unproved properties
• Estimates of future development costs
Estimates or Assumptions
Accounts Affected
• Oil and natural gas properties
• Accumulated depletion, depreciation and
amortization
• Provision for depletion, depreciation and
•
amortization
Impairment of oil and natural gas
properties
• Long-term debt and interest expense
• Oil and natural gas properties
• Accumulated depletion, depreciation and
amortization
• Provision for depletion, depreciation and
amortization
• Current and non-current liabilities
• Operating expense
• Oil and natural gas properties
• Non-current liabilities
Accounting for ARO for oil, NGLs, and
natural gas properties
• Cost estimates related to the plugging and
abandonment of wells
• Timing of cost incurred
• Credit adjusted risk free rate
Accounting for material producing property
and undeveloped acreage acquisitions
• Value the reserves with the income
approach using cash flow projections
• Value the undeveloped acreage with the
market approach using comparable sales
data
• Value equipment with the market
approach using comparable sales data
and CEPS pricing
Accounting for impairment of long-lived
assets
• Forecast of undiscounted estimated future
• Drilling and mid-stream property and
net operating cash flows
equipment
• Accumulated depletion, depreciation and
amortization
• Provision for depletion, depreciation and
amortization
Goodwill
• Forecast of discounted estimated future
• Goodwill
net operating cash flows
• Terminal value
• Weighted average cost of capital
Accounting for value of stock compensation
awards
• Estimates of stock volatility
• Estimates of expected life of awards
granted
• Estimates of rates of forfeitures
• Estimates of performance shares granted
• Oil and natural gas properties
• Shareholder’s equity
• Operating expenses
• General and administrative expenses
Accounting for derivative instruments
• Derivatives measured at fair value
• Current and non-current derivative assets
and liabilities
• Gain (loss) on derivatives
Significant Estimates and Assumptions
Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. Determining our oil, NGLs, and natural gas
reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that cannot be
measured in an exact manner. Accuracy of these estimates depends on several factors, including, the quality and availability of
geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire
an independent petroleum engineering firm to audit our internal evaluation of our reserves. The audit of our reserve wells or
locations as of December 31, 2018 covered those that we projected to comprise 83% of the total proved developed future net
income discounted at 10% and 82% of the total proved discounted future net income (based on the SEC's unescalated pricing
policy). Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and our
employees responsible for preparing our reserve reports.
48
As a rule, the accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the
r
related accumulation of available data, as shown in this table:
Type of Reserves
yp
Nature of Available Data
AA
y
Degree of Accuracy
g
Proved undeveloped
Data from offsetting wells, seismic data
Less accurate
Proved developed non-producing
The above and logs, core samples, well tests, pressure data
More accurate
Proved developed producing
The above and production history, pyy ressure data over time
Most accurate
Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in
estimating these reserves and the estimated present value of the cash flows to be received from the future production of those
reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point
when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves are greater than the
projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, tyy he estimated present value of the
future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on
different assumptions. Companies, like ours, using full cost accounting use the unweighted arithmetic average of the
commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate
discounted future revenues, unless prices were otherwise determined under contractual arrangements.
We compute DD&A on a units-of-production method. Each quarter, we u
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se these formulas to compute the provision for
DD&A for our producing properties:
•
•
DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production
Provision for DD&A = DD&A Rate x Current Period Production
Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization,
unproved properties, and equipment not placed in service.
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a
property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates
are revised upward, the DD&A rate will decrease. Based on our 2018 production level of 17.1 MMBoe, a decrease in our 2018
oil, NGLs, and natural gas reserves by 5% would increase our DD&A rate by $0.42 per Boe and would decrease pre-tax income
by $7.2 million annually. Conversely, an i
DD&A rate by $0.36 per Boe and would increase pre-tax income by $6.1 million annually.
ncrease in our 2018 oil, NGLs, and natural gas reserves by 5% would decrease our
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The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities
adjusted for period production.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting.
Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas
properties. At the end of each quarter, trr he net capitalized costs of our oil and natural gas properties are limited to that amount
which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10%
discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price
on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the
lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes.
If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess
amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’
equity in the period of occurrence and results in lower DD&A expense in future periods. Once incurred, a write-down cannot be
reversed.
The risk we will be required to write-down the carrying value of our oil and natural gas properties increases when the
prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs,
and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, iyy ncreases the
chance of a ceiling test write-down. At December 31, 2018, our reserves were calculated based on applying 12-month 2018
49
average unescalated prices of $65.56 per barrel of oil, $37.68 per barrel of NGLs, and $3.10 per Mcf of natural gas (then
adjusted for price differentials) over the estimated life of each of our oil and natural gas properties. We had no ceiling test write-
down for 2018.
It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many
factors that go into the ceiling test calculation including future pricing, operating costs, drilling and completion costs, upward or
downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties,
if we hold these same factors constant as they existed at December 31, 2018 and only adjust the 12-month average price to an
estimated first quarter ending average (holding February 2019 prices constant for the remaining one month of the first quarter
of 2019), our forward looking expectation is that we will not recognize an impairment in the first quarter of 2019. But
commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in
the potential for an impairment in the first quarter.
We
account for revenue transactions under ASC 606 for recording natural gas sales, which may be more or less than our
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f
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share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all
wells as incurred. The expenses relating to the wells in which we have a production imbalance are not material.
Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base
until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, the
drilling of wells, and capitalized interest are initially excluded from our amortization base. Leasehold costs are transferred to
our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or
reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred.
Our decision to withhold costs from amortization and the timing of transferring those costs into the amortization base
involve significant judgment and may be subject to changes over time based on several factors, including our drilling plans,
availability of capital, project economics and results of drilling on adjacent acreage. In December 2016 and December 2017, we
determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment
evaluation and our anticipated future exploration plans. Those determinations resulted in $7.6 million and $10.5 million in 2016
and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We did not have any in 2018.
At December 31, 2018, we had approximately $330.2 million of costs excluded from the amortization base of our full cost pool.
Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with the
future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise
become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the
liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities.
Our engineering staff uff
oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the
estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the
current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the
present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
ses historical experience to determine the estimated plugging costs considering the type of well (either
Accounting for Impairment of Long-Lived Assets. Drilling equipment, transportation equipment, gas gathering and
rr
processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and
enhancements are capitalized while repairs and maintenance are expensed. We review the carrying amounts of long-lived assets
for potential impairment annually, tyy ypically during the fourth quarter, or w
hen events occur or changes in circumstances suggest
these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment
obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling
rig utilization, declining revenue per day, dyy eclining cash margin per day, or o
determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset,
including disposal value if any, is l
measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on
the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the
carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve
expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding
future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and
assumptions could cause materially different carrying values of our assets.
ess than the carrying amount of the asset. If any asset is determined to be impaired, the loss is
verall changes in market conditions. Assets are
yy
yy
ff
50
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs,
expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig
type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s
other marketed rigs are transferred to other rigs or to its yards to be spare equipment. The remaining components of these rigs
are retired. No impairments were recorded in 2016 or 2017. In December 2018, our Board of Directors approved a plan to sell
41 drilling rigs (29 mechanical drilling rigs and 12 SCR diesel-electric drilling rigs) and other equipment. This plan satisfies the
criteria of assets held for sale under ASC 360-10-45-9. Over the last five years, only six of our drilling rigs in the fleet have not
been utilized. We made a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs (good
candidates for modification) and sell the other drilling rigs that we now choose not to market. We estimated the fair value of the
41 drilling rigs we will no longer market based on the estimated market value from third-party assessments (Level 3 fair value
measurement) less cost to sell. Based on these estimates, we recorded a non-cash write-down of approximately $147.9 million,
pre-tax ($111.7 million, net of tax).
ff
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired.
Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has
decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing,
goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment
test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and
other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows
include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded
at December 31, 2018, 2017, or 2016. Based on our impairment test performed as of December 31, 2018, the fair value of our
drilling segment exceeded its carrying value by 37%. While the goodwill of this reporting unit is not currently impaired, there
could be an impairment in the future as a result of changes in certain assumptions. For example, the fair value could be
adversely affected and result in an impairment of goodwill if we do not realize the anticipated drilling rig utilization of the
anticipated drilling rig dayrates, or if the estimated cash flows are discounted at a higher risk-adjusted rate or market multiples
decrease.
Drilling Contracts.The type of contract used determines our compensation. All of our contracts in 2018, 2017, and 2016
were daywork contracts. Under a daywork contract, we provide the drilling rig with the required personnel and the operator
supervises the drilling of the well. Our compensation is based on a negotiated rate to be paid for each day the drilling rig is
used.
Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is
measured at the grant date based on the fair value of an award and is recognized over the service period, which is usually the
vesting period. We elected to use the modified prospective method, which requires compensation expense to be recorded for all
unvested stock options and other equity-based compensation beginning in the first quarter of adoption. Determining the fair
value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option
pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent uncertainties
related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock
compensation may not accurately reflect the amount ultimately earned by the employee.
Accounting for Derivative Instruments and Hedging. All derivatives are recognized on the balance sheet and measured at
fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) along with any
derivatives settled are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
New Accounting Standards
FF
Fair Value Measurement (Topic 820): Disclosure Frr
ramework—Changes to the Disclosur
e Rrr
equirements for Fair Value
Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were
removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after
December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and
delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our
financial statements.
Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. TheTT
FASB
issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic
718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The
51
amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This
amendment will not have a material impact on our financial statements.
Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to
simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment
will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This
amendment will not have a material impact on our financial statements.
ff
Leases. The FASB has issued several accounting standards updates and amendments related to leases in the past two
years, which are codified within Topic 842. For public companies, these are effective for annual periods beginning after
December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the
commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the
lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the
lease term. Other recently issued amendments to Topic 842 have provided clarifying guidance regarding land easements, an
additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees
and lessors. The standard will not apply to leases of mineral rights.
We have an implementation team working through the provisions of the new guidance including a review of different
types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal
control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new
guidance is substantially complete.
We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition
exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization
threshold. Our transition will utilize the modified retrospective approach to adopting the new standard, and will be applied at
the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We have elected the transition practical
expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019, and the optional transition
e eWW xpect for certain lessee
method to record the our immaterial adoption impact through a cumulative adjustment to equity. Wyy
asset classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will
account for the agreements as a single lease component.
We have determined that Unit Drilling Company lessor drilling rig contracts will be accounted for under ASC 606 as the
service has been deemed the predominate component of the contract.
For both lessee and lessor practical expedients, we considered quantitative and qualitative factors when determining if an
asset class qualified for the application of the practical expedient.
The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the
consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. Upon
adoption, the Company expects to record operating lease right-of-use assets and the corresponding operating lease liabilities in
the range of approximately $3.0 million to $4.5 million, representing the present value of future lease payments under operating
leases. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its
processes. There would be no impact to the Superior credit agreement debt covenants and an immaterial impact to the Unit
credit agreement debt covenants as a result of adopting this standard.
Adopted Standards
As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other
ff
Comprehensive Income. This standard is explained further in Note 8 - New Accounting Pronouncements. We adopted this
amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect
on AOCI and we now use 24.5%. This change is reflected in our Consolidated Statements of Comprehensive Income and in
Note 17 - Equity.
Also, as of January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606)
and all later amendments that modified ASC 606. This new revenue standard is explained further in Note 8 – New Accounting
Pronouncements. We elected to apply this standard on the modified retrospective approach method to contracts not completed
as of January 1, 2018, where the cumulative effect on adoption, which only affected our mid-stream segment, is recognized as
an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for
TT
52
certain demand fees. Our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative
prior periods have not been adjusted and continue to be reported under ASC 605.
The additional disclosures required by ASC 606 have been included in Note 3 – Revenue from Contracts with Customers.
Our internal control framework did not materially change because of this standard, but the existing internal controls have
been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard,
we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU
2014-09.
Financial Condition and Liquidity
Summary.
Our financial condition and liquidity primarily depends on the cash flow from our operations and borrowings under our
credit agreements. The principal factors determining our cash flow are:
•
•
•
•
the amount of natural gas, oil, and NGLs we produce;
the prices we receive for our natural gas, oil, and NGLs production;
the demand for and the dayrates we receive for our drilling rigs; and
the fees and margins we obtain from our natural gas gathering and processing contracts.
We believe we have sufficient cash flow and liquidity to meet our obligations and remain in compliance with our debt
covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreements and our Indenture)
and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be affected by
financial, business, economic, regulatory, and other factors. For example, lower oil, natural gas, and NGLs prices since the last
redetermination under the Unit credit agreement could cause a redetermination of the borrowing base to a lower level and
therefore reduce or limit our ability to borrow funds. We monitor our liquidity and capital resources, endeavor to anticipate
potential covenant compliance issues and work with our lenders to address any of those issues ahead of time.
Below is a summary of certain financial information for the years ended December 31:
Net cash provided by operating activities................................................................ $
347,759
$
265,956
$
240,130
Net cash used in investing activities........................................................................
(450,342)
Net cash provided by (used in) financing activities.................................................
108,334
(293,366)
27,218
(110,971)
(129,101)
Net increase (decrease) in cash and cash equivalents........................................... $
5,751
$
(192)
$
58
2018
2017
(In thousands)
2016
Cash Flows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production,
the quantity of oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party demand for our drilling
rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also
affected by changes in working capital.
Net cash provided by operating activities increased by $81.8 million in 2018 compared to 2017 due primarily from higher
revenues due to higher commodity prices and higher drilling rig utilization partially offset by changes in operating assets and
liabilities related to the timing of cash receipts and disbursements.
Cash Flows from Investing Activities
We dedicate and expect to continue to dedicate a substantial portion of our capital budget to the exploration for and
production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically
experienced in oil and gas wells.
53
Cash flows used in investing activities increased by $157.0 million in 2018 compared to 2017. The change was due
primarily to an increase in capital expenditures due to an increase in wells drilled, oil and gas property acquisitions, and the
construction of new BOSS drilling rigs partially offset by an increase in the proceeds received from the disposition of assets.
See additional information on capital expenditures below under Capital Requirements.
Cash Flows from Financing Activities
Cash flows provided by financing activities increased by $81.1 million in 2018 compared to 2017. The increase was
primarily due to the proceeds from the sale of 50% interest in our mid-stream segment partially offset by the pay down of our
outstanding debt under the Unit credit agreement.
At December 31, 2018, we had unrestricted cash totaling $6.5 million and had borrowed none of the amounts available
under either of the Unit or Superior credit agreements.
Below is a summary of certain financial information as of December 31, and for the years ended December 31:
2018
2017
(In thousands)
2016
Working capital.............................................................................................. $
Long-term debt (1).......................................................................................... $
Shareholders' equity attributable to Unit Corporation (2)............................... $
Net income (loss) attributable to Unit Corporation (2)................................... $
(38,746)
644,475
1,390,881
(45,288)
$
$
$
$
(62,264)
820,276
1,345,560
117,848
$
$
$
$
(43,719)
800,917
1,194,070
(135,624)
_________________________
1.
Long-term debt is net of unamortized discount and debt issuance costs.
2.
In December 2018, we incurred a non-cash write-down associated with the removal of 41 drilling rigs from our fleet of $147.9 million pre-tax
($111.7 million, net of tax). In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6
million, net of tax).
Working Capital
Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and
accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative
activity. We had negative working capital of $38.7 million, $62.3 million, and $43.7 million as of December 31, 2018, 2017,
and 2016, respectively. The increase in working capital from 2017 is primarily due to increased cash and cash equivalents from
the sale of 50% interest in our mid-stream segment and increased accounts receivable due to increased revenues, the change in
the value of the derivatives outstanding and the fair value of drilling assets held for sale partially offset by increased accounts
payable due to increased activity in our drilling program. The Unit and Superior credit agreements are used primarily for
working capital and capital expenditures. At December 31, 2018, we had borrowed none of the $425.0 million available to us
under the Unit credit agreement and none of the $200.0 million available to us under the Superior credit agreement. The effect
of our derivatives increased working capital by $12.9 million as of December 31, 2018, decreased working capital by $7.1
million as of December 31, 2017, and increased working capital by $21.6 million as of December 31, 2016.
54
This table summarizes certain operating information for the years ended December 31:
Oil and Natural Gas:
Oil production (MBbls)...........................................................................................
Natural gas liquids production (MBbls)..................................................................
Natural gas production (MMcf)...............................................................................
Average oil price per barrel received....................................................................... $
Average oil price per barrel received excluding derivatives.................................... $
Average NGLs price per barrel received................................................................. $
Average NGLs price per barrel received excluding derivatives.............................. $
Average natural gas price per mcf received............................................................. $
Average natural gas price per mcf received excluding derivatives.......................... $
Contract Drilling:
Average number of our drilling rigs in use during the period..................................
Total drilling rigs available for use at the end of the period....................................
2018
2017
2016
2,874
4,925
55,626
55.78
63.78
22.18
22.58
2.46
2.42
32.8
55
$
$
$
$
$
$
2,715
4,737
51,260
49.44
48.98
18.35
18.35
2.46
2.49
30.0
95
$
$
$
$
$
$
2,974
5,014
55,735
40.50
39.05
11.26
11.26
2.07
1.98
17.4
94
Average dayrate....................................................................................................... $
17,510
$
16,256
$
17,784
Mid-Stream:
Gas gathered—Mcf/day...........................................................................................
Gas processed—Mcf/day.........................................................................................
Gas liquids sold—gallons/day.................................................................................
Number of natural gas gathering systems................................................................
Number of processing plants...................................................................................
393,613
158,189
663,367
22 (1)
14
385,209
137,625
534,140
24
13
419,217
155,461
536,494
25
13
________________________
1.
In 2018, our mid-stream segment transferred two natural gas gathering systems to our oil and natural gas segment.
Oil and Natural Gas Operations
Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value
of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather
conditions, supply imbalances, and by worldwide oil price levels. Domestic oil prices are primarily influenced by world oil
market developments. These factors are beyond our control and we cannot predict nor measure their future influence on the
prices we will receive.
Based on our 2018 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the
effect of derivatives, would cause a corresponding $439,000 per month ($5.3 million annualized) change in our pre-tax
operating cash flow. Our 2018 average natural gas price was $2.46 compared to an average natural gas price of $2.46 for 2017
and $2.07 for 2016. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $228,000 per
month ($2.7 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices,
without the effect of derivatives, would have a $393,000 per month ($4.7 million annualized) change in our pre-tax operating
cash flow based on our production in 2018. Our 2018 average oil price per barrel was $55.78 compared with an average oil
price of $49.44 in 2017 and $40.50 in 2016, and our 2018 average NGLs price per barrel was $22.18 compared with an average
NGLs price of $18.35 in 2017 and $11.26 in 2016.
Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a
decline in the carrying value of our oil and natural gas properties. At December 31, 2018, the 12-month average unescalated
prices were $65.56 per barrel of oil, $37.68 per barrel of NGLs, and $3.10 per Mcf of natural gas, and then are adjusted for
price differentials. We did not have to take a write down in 2018.
It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many
factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and
completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to
these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2018 and only adjust the 12-
month average price to an estimated first quarter ending average (holding February 2019 prices constant for the remaining one
55
month of the first quarter of 2019), our forward-looking expectation is that we will not recognize an impairment in the first
quarter of 2019. Commodity prices remain volatile and they could negatively affect the 12-month average price and the
potential for an impairment in the first quarter.
Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers
under contracts with terms generally ranging from one month to five years. Our oil production is sold to independent marketing
firms generally under six-month contracts.
Contract Drilling Operations
Many factors influence the number of drilling rigs we have working and the costs and revenues associated with that work.
These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the
prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply
the equipment needed.
Competition to keep qualified labor continues. We increased compensation for some rig personnel during the first quarter
of 2018. Our drilling rig personnel are a key component to the overall success of our drilling services. With the present
conditions in the drilling industry, we do n
ot anticipate increases in the compensation paid to those personnel in the near term.
yy
During 2018, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The
continuous fluctuations in commodity prices for oil and natural gas changes demand for drilling rigs. These factors ultimately
affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of
drilling rigs to meet that demand will affect our future dayrates. For 2018, our average dayrate was $17,510 per day compared
to $16,256 and $17,784 per day for 2017 and 2016, respectively. Our average number of drilling rigs used (utilization %) in
2018 was 32.8 (34%) compared with 30.0 (32%) and 17.4 (19%) in 2017 and 2016, respectively. Based on the average
utilization of our drilling rigs during 2018, a $100 per day change in dayrates has a $3,280 per day ($1.2 million annualized)
change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling
services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an
ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our statement of
operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for
these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. By
providing drilling services for the oil and natural gas segment, we eliminated revenue of $22.5 million and $13.4 million during
2018 and 2017, respectively, fyy rom our contract drilling segment and eliminated the associated operating expense of $19.5
million and $11.8 million during 2018 and 2017, respectively, yyy ielding $3.0 million and $1.6 million during 2018 and 2017,
respectively, as a r
our contract drilling segment during 2016.
eduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in
yy
ff
Mid-Stream Operations
This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates
three natural gas treatment plants, 14 processing plants, 22 gathering systems, and approximately 1,475 miles of pipeline. Its
operations are in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to gather and
market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism through which
we can construct or acquire existing natural gas gathering and processing facilities. During 2018, 2017, and 2016 this segment
purchased $81.4 million, $63.2 million, and $42.7 million, respectively, of o
NGLs production, and provided gathering and transportation services of $7.3 million, $6.7 million, and $9.2 million,
respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and
natural gas segment has been eliminated in our consolidated financial statements.
ur oil and natural gas segment's natural gas and
yy
Our mid-stream segment gathered an average of 393,613 Mcf per day in 2018 compared to 385,209 Mcf per day in 2017
and 419,217 Mcf per day in 2016. It processed an average of 158,189 Mcf per day in 2018 compared to 137,625 Mcf per day in
2017 and 155,461 Mcf per day in 2016, and sold NGLs of 663,367 gallons per day in 2018 compared to 534,140 gallons per
day in 2017 and 536,494 gallons per day in 2016. Gas gathering volumes per day in 2018 increased primarily due to higher
volumes at our Cashion and Hemphill facilities. Volumes processed increased primarily due to connecting new wells to our
processing systems in 2018. NGLs sold increased primarily due to higher purchased volumes and better recoveries at our
processing facilities.
56
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may
offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up
to an aggregate offering price of $100.0 million. We intended to use the net proceeds from these sales to fund (or offset costs of)
acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, ayy nd general corporate
purposes.
On May 2, 2018, we terminated the Distribution Agreement. The Distribution Agreement was terminable at will on
written notification by us with no penalty. Ayy
the Distribution Agreement resulting in net proceeds of approximately$18.6 million. We paid the sales agent a commission of
2.0% of the gross sales price per share sold. As a result of the termination, there will be no more sales of our common stock
under the Distribution Agreement.
s of the date of termination, we had sold 787,547 shares of our common stock under
Our Credit Agreements and Senior Subordinated Notes
Unit Credit Agreement. On October 18, 2018, we signed a Fifth Amendment to our Senior Credit Agreement (Unit credit
agreement) amending our existing credit agreement entered into between the Company and certain lenders on September 13,
2011, as amended September 5, 2012, as further amended April 10, 2015, as further amended on April 8, 2016, as further
amended on April 2, 2018, attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 15,
2011, September 11, 2012, April 13, 2015, April 8, 2016, and April 6, 2018, respectively, ayy nd the Company’s Current Report on
Form 8-K/A filed on April 13, 2016, and each incorporated by reference herein.
The Fifth Amendment, among other things, (i) extends the term of the Unit credit agreement to October 18, 2023, subject
to certain conditions; (ii) reduces the pricing for borrowing and non-use fees; and (iii) eliminates the requirement that the
company maintain a senior indebtedness to consolidated EBITDA ratio. The total commitment of credit and the borrowing base
both remain unchanged at $425.0 million.
Under the Unit credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment
amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit
agreement. We are charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on
the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency,
syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the Unit credit
agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total
value of our oil and gas properties.
On April 2, 2018, we signed the fourth amendment to the Unit credit agreement. The Fourth Amendment provided,
among other things, for a reduction of the maximum credit amount from $875.0 million to $425.0 million, a reduction in the
borrowing base from $475.0 million to $425.0 million, a reduction in the total commitment amount from $475.0 million to
$425.0 million; and the full release of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit
agreement. Under the amendment once the sale of the interest in Superior was completed, we were required to us part of the
proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018 and the pay down was made that
day.
On May 2, 2018, as contemplated under the Fourth Amendment, we entered into a Pledge Agreement with BOKF, NA
(dba Bank of Oklahoma), as administrative agent for the benefit of the secured parties, under which we granted a security
interest in the limited liability membership interests and other equity interests we own in Superior (which as of the date of this
report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the
Unit credit agreement.
57
The lenders under our Unit credit agreement and their respective participation interests are:
Lender
Participation
Interest
BOK (BOKF, NA, dba Bank of Oklahoma)..............................................................................................................
BBVA Compass Bank................................................................................................................................................
BMO Harris Financing, Inc.......................................................................................................................................
Bank of America, N.A...............................................................................................................................................
Comerica Bank..........................................................................................................................................................
Toronto Dominion Bank, New York Branch.............................................................................................................
Canadian Imperial Bank of Commerce.....................................................................................................................
Arvest Bank...............................................................................................................................................................
Branch Banking & Trust............................................................................................................................................
IBERIABANK...........................................................................................................................................................
17.060 %
17.060 %
15.294 %
15.294 %
8.235 %
8.235 %
8.235 %
3.529 %
3.529 %
3.529 %
100.000 %
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–
is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may
request a one time special redetermination of the borrowing base between each scheduled redetermination. In addition, we may
request a redetermination following the completion of an acquisition that meets the requirements in the Unit credit agreement.
At our election, any part of the outstanding debt under the Unit credit agreement may be fixed at a London Interbank
Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.50% to 2.50%
depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days,
whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement that cannot
be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in
whole or in part at any time, without a premium or penalty. At December 31, 2018, we had no outstanding borrowings.
We can use borrowings for financing general working capital requirements for (a) exploration, development, production
and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of
credit, (d) contract drilling services, and (e) general corporate purposes.
The Unit credit agreement prohibits, among other things:
•
•
•
•
the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income
for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions;
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except for our lenders; and
investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.
The Unit credit agreement also requires that we have at the end of each quarter:
•
•
a current ratio (as defined in the Unit credit agreement) of not less than 1 to 1.
a leverage ratio of funded debt to consolidated EBITDA (as defined in the Unit credit agreement) for the most
recently ended rolling four fiscal quarters of no greater than 4 to 1.
As of December 31, 2018, we were in compliance with the covenants in the Unit credit agreement.
Superior Credit Agreement. On May 10, 2018, Superior, a limited liability company equally owned between us and SP
Investor Holdings, LLC, entered into a five-year, $200.0 million senior secured revolving credit facility with an option to
increase the credit amount up to $250.0 million, subject to certain conditions. The amounts borrowed under the Superior credit
agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25%
or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus
58
1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by,
among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.
Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the
amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication,
and other related fees. These fees are being amortized over the life of the Superior credit agreement.
The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the
most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not
greater than 4.00 to 1.00. Additionally, the Superior credit agreement contains a number of customary covenants that, among
other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on
its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with
affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of
December 31, 2018, Superior was in compliance with the Superior credit agreement covenants.
The borrowings the Superior credit agreement will be used to fund capital expenditures and acquisitions, provide general
working capital, and for letters of credit for Superior.
On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the
agreement.
Superior's credit agreement is not guaranteed by Unit.
The current lenders under the Superior credit agreement and their respective participation interests are:
Lender
BOK (BOKF, NA, dba Bank of Oklahoma)............................................................................................................................
Compass Bank.........................................................................................................................................................................
BMO Harris Financing, Inc.....................................................................................................................................................
Toronto Dominion (New York), LLC......................................................................................................................................
Bank of America, N.A.............................................................................................................................................................
Branch Banking and Trust Company.......................................................................................................................................
Comerica Bank........................................................................................................................................................................
Canadian Imperial Bank of Commerce...................................................................................................................................
Participation
Interest
17.50 %
17.50 %
13.75 %
13.75 %
10.00 %
10.00 %
10.00 %
7.50 %
100.00 %
6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior
subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each
year. The Notes will mature on May 15, 2021. In issuing the Notes, we incurred $14.7 million of fees that are being amortized
as debt issuance cost over the life of the Notes.
The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association
(successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of
May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture
dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the
terms and providing for issuing the Notes. The Guarantors are our direct and indirect subsidiaries. The discussion of the Notes
in this report is qualified by and subject to the actual terms of the 2011 Indenture.
Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes
(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary
releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets
of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not
Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through
dividends, loans, advances or otherwise.
59
ff
We may redeem all or, frr
rom time to time,
a part of the Notes at certain redemption prices, plus accrued and unpaid
interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any
part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and
unpaid interest, if any, to t
also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or
guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness;
transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with
other companies. We were in compliance with all covenants of the Notes as of December 31, 2018.
he date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture
yy
Capital Requirements
Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this
segment are discretionary and directed toward growth. Any decision to increase our oil, NGLs, and natural gas reserves through
acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future
drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these
costs. We completed drilling 117 gross wells (33.16 net wells) in 2018 compared to 70 gross wells (25.71 net wells) in 2017,
and 21 gross wells (9.67 net wells) in 2016.
On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo
Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the
effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of
oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in
southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition included 13 potential
horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% was
held by production. We also received one gathering system as part of the transaction.
In December 2018, we closed on an acquisition of certain oil and natural gas assets located primarily in Custer County,
Oklahoma. The total preliminary adjusted value of consideration given was $29.6 million. As of November 1, 2018, the
effective date of the acquisition, the estimated proved oil and gas reserves for the acquired properties was 2.6 MMBoe net to
Unit. The acquisition added approximately 8,667 net oil and gas leasehold acres to our Penn Sands area in Oklahoma including
approximately 44 wells. The acquisitions included approximately 30 potential horizontal drilling locations which are anticipated
to have a high percentage of oil relative to the total production stream. Of the acreage acquired, approximately 82% was held by
production.
Capital expenditures for oil and gas properties on the full cost method for 2018 by this segment, excluding a $7.6 million
reduction in the ARO liability and $30.7 million in acquisitions (including associated ARO), totaled $344.3 million compared to
2017 capital expenditures of $215.4 million (excluding a $4.0 million reduction in the ARO liability and $59.0 million in
acquisitions), and 2016 capital expenditures of $119.9 million (excluding an $30.9 million reduction in the ARO liability and
$0.6 million in acquisitions).
For 2019, we plan to participate in drilling approximately 90 to 100 gross wells and estimate our total capital expenditures
(excluding any possible acquisitions) for our oil and natural gas segment will range from approximately $271.0 million to
$315.0 million. Whether we drill all of those wells depends on several factors, many of which are beyond our control and
include the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand
for oil, NGLs, and natural gas, the cost to drill wells, the weather, arr nd the efforts of outside industry partners.
We sold non-core oil and natural gas assets, net of related expenses, for $22.5 million, $18.6 million, and $67.2 million
during 2018, 2017, and 2016, respectively. Proceeds from those dispositions reduced the net book value of our full cost pool
with no gain or loss recognized.
Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During December 2016, we sold an idle 1500 HP
SCR drilling rig to an unaffiliated third party. We aWW lso fabricated and placed into service our ninth new BOSS drilling rig for a
third party operator. This new BOSS rig was constructed using the long lead time components purchased in prior years.
During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term
contract. We also returned to service 14 SCR drilling rigs that had been previously stacked.
60
During 2018, we built our 11th BOSS drilling and placed it into service for a third party operator under a long term
contract. We also made modifications to nine SCR rigs to meet customer requirements.
In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR
diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9.
Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on
our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that
we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the
estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these
estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax).
ff
Our anticipated 2019 capital expenditures for this segment range from approximately $30.0 million to $65.0 million. We
spent $75.5 million for capital expenditures during 2018 compared to $36.1 million in 2017, and $19.1 million in 2016.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. In the Appalachian region at the Pittsburgh Mills
gathering system, average gathered volume for the fourth quarter of 2018 was approximately 129.7 MMcf per day and the
annual average gathered volume was 123.9 MMcf per day. In 2
and all the new infill wells are currently online and flowing gas. We have completed construction of the new pipeline to connect
the next scheduled well pad to our system. We have also completed the upgrade of the compressor station and dehydration
facilities. Production from this new pad started online during January 2019.
018, we added seven new infill wells late in the second quarter
yy
At the Hemphill Texas system, average total throughput volume for the fourth quarter of 2018 increased to 75.3 MMcf
per day and total production of natural gas liquids was approximately 301,500 gallons per day during this same period. The
annual average throughput volume was 72.6 MMcf per day while the annual total production of natural gas liquids averaged
264,971 gallons per day. During the fourth quarter, we connected five new wells in the Buffalo Wallow area. These new wells
along with increased production from recently drilled wells in this area contributed to the increased throughput volume. Our oil
and gas segment continues to operate a rig in the Buffalo Wallow area and we anticipate connecting additional wells to this
system in 2019.
At the Cashion processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2018 averaged
approximately 49.2 MMcf per day and total production of natural gas liquids increased to 246,873 gallons per day. Tyy he annual
average throughput volume was 46.0 MMcf per day and the annual average natural gas liquids production was 234,316 gallons
per day. This system is currently operating at full processing capacity and we are adding additional capacity to this system. We
are relocating a 60 MMcf per day processing plant from our Bellmon facility to the Cashion area. This processing plant will be
installed at the Reeding site on the Cashion system. This plant is expected to be operational by the end of the first quarter of
2019 and it will increase our total processing capacity on the Cashion system to approximately 105 MMcf per day. We
connected eight new wells to this system during the fourth quarter of 2018 and we are continuing to connect additional wells
from a third party producer who continues to be active in this area.
yy
At the Minco processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2018 was
approximately 8.0 MMcf per day and the average annual total throughput volume was 9.5 MMcf per day. Dyy
quarter of 2018 we completed a new interconnect with a producer who is currently delivering gas to our system. Additionally,
we are completing construction of a new well connect for a third party producer who is expected to deliver gas to our system in
2019. The current processing capacity of the Minco facility is approximately 12 MMcf per day.
uring the fourth
During 2018, our mid-stream segment incurred $44.8 million in capital expenditures as compared to $22.2 million in
2017, and $16.8 million, in 2016. For 2019, our estimated capital expenditures range from approximately $35.0 million to
$42.0 million.
61
Contractual Commitments
At December 31, 2018, we had these contractual obligations:
Long-term debt (1)........................................... $
Operating leases (2)..........................................
Capital lease interest and maintenance (3).......
Drill pipe, drilling components, and
equipment purchases (4)...............................
Total contractual obligations..................... $
Payments Due by Period
Total
Less Than
1 Year
2-3
Years
(In thousands)
4-5
Years
After
5 Years
752,052
$
43,063
$
708,989
$
— $
6,702
4,724
9,215
4,550
2,168
9,215
2,152
2,556
—
—
—
—
772,693
$
58,996
$
713,697
$
— $
—
—
—
—
—
_________________________
1.
See previous discussion in MD&A regarding our long-term debt. This obligation is presented under the Notes and the Unit and Superior credit agreements
and includes interest calculated using our December 31, 2018 interest rates of 6.625% for the Notes. The outstanding Unit credit facility balance was paid
down on April 3, 2018, and as of December 31, 2018, we did not have any outstanding borrowings.
2. We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg,
Pennsylvania under the terms of operating leases expiring through December 2021. And, we have several equipment leases and lease space on short-term
commitments to stack excess drilling rig equipment and production inventory.
3. Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.0%. Total
maintenance and interest remaining are $4.1 million and $0.6 million, respectively.
4. We have committed to purchase approximately $9.2 million of new drilling rig components over the next year.
During the second quarter of 2018, we entered into a contractual obligation that commits us to spend $150.0 million for
drilling wells in the Granite Wash/Buffalo Wallow area over the next three years starting January 1, 2019. This amount is
already included in our drilling plan. For each dollar of the $150.0 million that we do not spend (over the three year period), we
would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary.
If we elected not to drill or spend any money in the designated area over the three year period, the maximum amount we could
forgo from distributions would be $87.0 million.
62
At December 31, 2018, we also had these commitments and contingencies that could create, increase or accelerate our
liabilities:
Other Commitments
Deferred compensation plan (1)....................... $
Separation benefit plans (2).............................. $
ARO liability (3).............................................. $
Gas balancing liability (4)................................ $
Repurchase obligations (5)............................... $
Workers’ compensation liability (6)................. $
Capital lease obligations (7)............................. $
Contract liability (8)......................................... $
Derivative liabilities—commodity hedges..... $
Estimated Amount of Commitment Expiration Per Period
Total
Accrued
Less
Than 1
Year
2-3
Years
(In thousands)
4-5
Years
After 5
Years
5,132
8,814
64,208
3,331
—
12,738
11,380
9,881
293
$
$
$
$
$
$
Unknown
812
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
1,437
$
36,033
$
3,570
$
23,168
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
5,126
4,001
2,874
$
$
$
— $
2,478
7,379
5,460
293
$
$
$
$
1,000
$
— $
1,547
$
— $
Unknown
Unknown
4,134
—
—
—
_________________________
1. We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits,
which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record
a liability, included in other long-term liabilities in our Consolidated Balance Sheets, at the time of deferral.
2.
Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment
with us is involuntarily terminated or with an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits
equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the
recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit
Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of the company with benefits generally
equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals
covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit
Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.
3. When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with
the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
4. We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners
to recover their under-production from future production volumes.
5. We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the
Partnerships) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of
each of these programs. Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships
were also dissolved. The Partnerships were formed to conduct oil and natural gas acquisition, drilling and development operations and serving as co-
general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in
most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the
Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited
partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We
made repurchases of approximately $1,700, $2,900, and $5,000 in 2018, 2017, and 2016, respectively. Effective January 1, 2019, we elected to terminate
and wind down all of the remaining employee limited partnerships. In accordance with the partnership agreements, we, as the liquidating trustees will
value the interests of the limited partners using the formula provided in each partnership agreement and purchase those interests. Presently, we expect the
total purchase price for all of the limited partners interests will be approximately $0.6 million. We have no plans to sponsor additional employee limited
partnerships.
6. We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling
segment.
7.
This amount includes commitments under capital lease arrangements for compressors in our mid-stream segment.
8. We have recorded a liability related to the timing of the revenue recognized on certain demand fees for Superior.
Derivative Activities
Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and
natural gas production. Any change in the fair value of all our derivatives are reflected in the statement of operations.
63
Commodity Derivatives. Our commodity derivatives should reduce our exposure to price volatility and manage price
risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view
of current and future market conditions. As of December 31, 2018, based on our fourth quarter 2018 average daily production,
the approximated percentages of our production under derivative contracts are as follows:
Mark-to-Market
2019
Q1
Q2
Q3
Q4
Daily oil production.........................................................................
Daily natural gas production............................................................
51 %
66 %
51 %
52 %
51 %
52 %
51 %
44 %
Regarding the commodities subject to derivative contracts, those contracts limit the risk of adverse downward price
movements. However, they also limit increases in future revenues that would otherwise result from price movements above the
contracted prices.
Using derivative transactions has the risk that the counterparties may not meet their financial obligations under the
transactions. Based on our evaluation at December 31, 2018, we believe the risk of non-performance by our counterparties is
not material. At December 31, 2018, the fair values of the net assets we had with each of the counterparties to our commodity
derivative transactions are:
December 31, 2018
(In millions)
Bank of Montreal.................................................................................................................................................... $
Bank of America Merrill Lynch..............................................................................................................................
Total net assets........................................................................................................................................................ $
9.9
2.7
12.6
If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our
Consolidated Balance Sheets. At December 31, 2018, we recorded the fair value of our commodity derivatives on our balance
sheet as current derivative assets of $12.9 million and long-term derivative liabilities of $0.3 million. At December 31, 2017, we
recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.7 million and
current derivative liabilities of $7.8 million.
All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value
before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated
Statements of Operations.
These gains (losses) are as follows at December 31:
2018
2017
(In thousands)
2016
Gain (loss) on derivatives, included are amounts settled during the period of
($22,803), $173, and $9,658, respectively................................................................ $
(3,184) $
14,732
$
(22,813)
Stock and Incentive Compensation
During 2018, we granted awards covering 1,279,255 shares of restricted stock. These awards were granted as retention
incentive awards. These stock awards had an estimated fair value as of the grant date of $24.7 million. Compensation expense
will be recognized over the awards' three year vesting period. During 2018, we recognized $9.4 million in additional
compensation expense and capitalized $1.4 million for these awards. During 2017, we granted awards covering 708,276 shares
of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three
year vesting period. During 2016, we granted awards covering 736,451 shares of restricted stock. These awards were granted as
retention incentive awards and are being recognized over their two and three year vesting periods. No SAR awards were made
during 2018, 2017, or 2016.
64
During 2018, we recognized compensation expense of $17.8 million for our restricted stock grants and capitalized $2.1
million of compensation cost for oil and natural gas properties.
Insurance
We are self-insured for certain losses relating to workers’ compensation, general liability, cyy ontrol of well, and employee
medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to
$1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to
certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all
potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise
our deductibles, or any combination of these rather than pay higher premiums.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships.
We are the general partner of 13 oil and natural gas partnerships formed privately or publicly. Eyy
ach partnership’s revenues
and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well
supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees
are the related party’s share of such costs. These costs are billed the same as billings to unrelated third parties for similar
services. General and administrative reimbursements consist of direct general and administrative expense incurred on the
related party’s behalf and indirect expenses assigned to the related parties. Allocations are based on the related party’s level of
activity and are considered by us to be reasonable. During 2018, 2017, and 2016, the total we received for these fees was $0.2
million, $0.2 million, and $0.3 million, respectively. Our proportionate share of assets, liabilities, and net income relating to the
oil and natural gas partnerships is included in our consolidated financial statements. These partnerships will be terminated in
2019.
Effects of Inflation
The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil, NGLs, and natural gas.
Increases in these prices increase the demand for our contract drilling rigs and services. This increase in demand affects the
dayrates we can obtain for our contract drilling services. During periods of higher demand for our drilling rigs we have
experienced increases in labor costs and the costs of services to support our drilling rigs. Historically, dyy uring this same period,
when oil, NGLs, and natural gas prices declined, labor rates did not come back down to the levels existing before the increases.
If commodity prices increase substantially for a long period, shortages in support equipment (like drill pipe, third party services,
and qualified labor) can cause additional increases in our material and labor costs. Increases in dayrates for drilling rigs also
increase the cost of our oil and natural gas properties. Commodity prices also can affect our fracking and completion costs.
How inflation will affect us in the future will depend on increases, if any, ryy ealized in our drilling rig rates, the prices we receive
for our oil, NGLs, and natural gas, and the rates we receive for gathering and processing natural gas. Due to increased demand
for drilling rigs and the need to maintain qualified labor, we i
ncreased pay for some of our drilling personnel in the first quarter
of 2018.
d
rr
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and
re subject to
ustomary in the oil and gas industry, we a
yy
rr
capital resource positions, or for any other purpose. However, as is c
various contractual commitments.
65
Results of Operations
2018 versus 2017
Total revenue............................................................................................................... $
Net income (loss) ....................................................................................................... $
Net income attributable to non-controlling interest.................................................... $
Net income (loss) attributable to Unit Corporation..................................................... $
Oil and Natural Gas:
Revenue................................................................................................................. $
Operating costs excluding depreciation, depletion, amortization, and
impairment......................................................................................................... $
Depreciation, depletion, and amortization............................................................. $
Average oil price received (Bbl)............................................................................ $
Average NGL price received (Bbl)........................................................................ $
Average natural gas price received (Mcf).............................................................. $
Oil production (MBbls).........................................................................................
NGLs production (MBbls).....................................................................................
Natural gas production (MMcf).............................................................................
Depreciation, depletion, and amortization rate (Boe)............................................ $
Contract Drilling:
Revenue................................................................................................................. $
Operating costs excluding depreciation................................................................. $
Depreciation........................................................................................................... $
Impairment of contract drilling equipment............................................................ $
Percentage of revenue from daywork contracts.....................................................
Average number of drilling rigs in use..................................................................
Average dayrate on daywork contracts.................................................................. $
Mid-Stream:
Revenue................................................................................................................. $
Operating costs excluding depreciation and amortization..................................... $
Depreciation and amortization............................................................................... $
Gas gathered—Mcf/day.........................................................................................
Gas processed—Mcf/day.......................................................................................
Gas liquids sold—gallons/day...............................................................................
Corporate and other:
General and administrative expense............................................................................ $
Other depreciation....................................................................................................... $
Gain on disposition of assets....................................................................................... $
Other income (expense):
Interest income....................................................................................................... $
Interest expense, net............................................................................................... $
Gain (loss) on derivatives ..................................................................................... $
Other....................................................................................................................... $
Income tax benefit....................................................................................................... $
Average interest rate....................................................................................................
Average long-term debt outstanding........................................................................... $
66
2018
2017
(In thousands unless otherwise specified)
739,640
117,848
—
117,848
$
843,281
(39,767) $
5,521
$
(45,288) $
Percent
Change (1)
14 %
(134)%
— %
(138)%
423,059
131,675
133,584
55.78
22.18
2.46
2,874
4,925
55,626
7.50
196,492
131,385
57,508
147,884
100 %
32.8
17,510
223,730
167,836
44,834
393,613
158,189
663,367
38,707
7,679
704
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
972
(34,466) $
(3,184) $
$
22
(13,996) $
6.5 %
685,330
$
357,744
130,789
101,911
49.44
18.35
2.46
2,715
4,737
51,260
6.00
174,720
122,600
56,370
—
100 %
30.0
16,256
207,176
155,483
43,499
385,209
137,625
534,140
38,087
7,477
327
—
(38,334)
14,732
21
(57,678)
6.0 %
810,734
18 %
1 %
31 %
13 %
21 %
— %
6 %
4 %
9 %
25 %
12 %
7 %
2 %
— %
— %
9 %
8 %
8 %
8 %
3 %
2 %
15 %
24 %
2 %
3 %
115 %
— %
(10)%
(122)%
5 %
76 %
8 %
(15)%
Oil and Natural Gas
Oil and natural gas revenues increased $65.3 million or 18% in 2018 as compared to 2017 due primarily to higher oil and
NGLs prices and higher production. Oil production increased 6%, NGLs production increased 4%, and natural gas production
increased 9%. Average oil prices between the comparative years increased 13% to $55.78 per barrel, NGLs prices increased
21% to $22.18 per barrel, and natural gas prices remained at $2.46 per Mcf.
Oil and natural gas operating costs increased $0.9 million or 1% between the comparative years of 2018 and 2017
primarily due to higher LOE, gross production taxes, general and administrative expenses, and saltwater disposal expense,
partially offset by less expenses due to certain deductions being netted in revenues after ASC 606 implementation in 2018.
DD&A increased $31.7 million or 31% primarily due to a 25% increase in our DD&A rate and by the effect of a 7%
increase in equivalent production. The increase in our DD&A rate in 2018 compared to 2017 resulted primarily from the cost of
wells drilled in 2018.
Contract Drilling
Drilling revenues increased $21.8 million or 12% in 2018 as compared to 2017. The increase was due primarily to a 9%
increase in the average number of drilling rigs in use and an 8% increase in the average dayrate compared to 2017. Average
drilling rig utilization increased from 30.0 drilling rigs in 2017 to 32.8 drilling rigs in 2018.
Drilling operating costs increased $8.8 million or 7% in 2018 compared to 2017. The increase was due primarily to more
drilling rigs operating and to a less extent from increased per day direct cost. Contract drilling depreciation increased $1.1
million or 2% also due primarily to more drilling rigs operating and the acceleration of depreciation on drilling rigs stacked for
more than 48 months.
In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR
diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9.
Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on
our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that
we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the
estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these
estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax).
ff
Mid-Stream
Our mid-stream revenues increased $16.6 million or 8% in 2018 as compared to 2017 primarily due to increased NGLs
and condensate sales partially offset by lower gas sales, transportation revenue, and increased intercompany eliminations. Gas
processing volumes per day increased 15% between the comparative years primarily due to connecting new wells to our
processing systems. Gas gathering volumes per day increased 2% primarily due to connecting new wells at several of our
gathering and processing systems.
Operating costs increased $12.4 million or 8% in 2018 compared to 2017 primarily due to an increase in purchased
volume along with an increase in purchase prices combined with increased mid-stream direct G&A and field direct expenses
partially offset by increased intercompany eliminations. Depreciation and amortization increased $1.3 million or 3% primarily
due to placing additional capital assets into service in 2018.
General and Administrative
General and administrative expenses increased $0.6 million or 2% in 2018 compared to 2017 primarily due to higher
employee costs.
Other Depreciation
Other depreciation increased $0.2 million in 2018 compared to 2017 primarily due to the depreciation on the new ERP
system.
67
Gain on Disposition of Assets
Gain on disposition of assets increased $0.4 million in 2018 compared to 2017. The gain in 2018 was primarily for the
sale of drilling equipment and vehicles, while gain in 2017 was primarily for the sale of a corporate aircraft and vehicles.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $3.9 million between the comparative years of 2018 and 2017. We
capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of
additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2018 was $16.5 million compared
to $15.9 million in 2017, and was netted against our gross interest of $51.0 million and $54.2 million for 2018 and 2017,
respectively. Our average interest rate increased from 6.0% to 6.5% and our average debt outstanding was $125.4 million lower
in 2018 as compared to 2017 primarily due to the pay down of our Unit credit agreement in the second quarter of 2018. We had
interest earned of $1.0 million from the excess cash in our investment accounts from the sale of 50% of Superior.
ff
Gain (loss) on derivatives decreased from a gain of $14.7 million in 2017 to a loss of $3.2 million in 2018 primarily due
to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Baa
enefit
Income tax benefit decreased $43.7 million in 2018 compared to 2017. We recognized an income tax benefit of $14.0
million in 2018 compared to an income tax benefit of $57.7 million in 2017. The 2017 benefit was due to the revaluation of our
net deferred tax liability in connection with the enactment of the Tax Cuts and Jobs Act (the Tax Act) in December 2017 which
TT
resulted in an $81.3 million reduction in our deferred liability. Tyy axable income before the impairment was higher in 2018
resulting in higher tax netted against the $111.7 tax benefit from the impairment.
Our effective tax rate was 26.0% for 2018 compared to 95.9% for 2017. The effective tax rate for the current year was
more normalized as compared to 2017 because of the negative rate resulting from enactment of the Tax Act and revaluation of
our net deferred tax liability during 2017. We paid $3.6 million in state income taxes during 2018 due to the sale of 50% interest
in our mid-stream segment.
68
2017 versus 2016
2017
2016
(In thousands unless otherwise specified)
602,177
(135,624)
739,640
117,848
$
$
Percent
Change (1)
23 %
187 %
Total revenue............................................................................................................... $
Net income (loss)........................................................................................................ $
Oil and Natural Gas:
Revenue................................................................................................................. $
Operating costs excluding depreciation, depletion, amortization, and
impairment......................................................................................................... $
Depreciation, depletion, and amortization............................................................. $
Impairment of oil and natural gas properties......................................................... $
Average oil price received (Bbl)............................................................................ $
Average NGLs price received (Bbl)...................................................................... $
Average natural gas price received (Mcf).............................................................. $
Oil production (MBbls).........................................................................................
NGLs production (MBbls).....................................................................................
Natural gas production (MMcf).............................................................................
Depreciation, depletion, and amortization rate (Boe)............................................ $
Contract Drilling:
Revenue................................................................................................................. $
Operating costs excluding depreciation and impairment....................................... $
Depreciation........................................................................................................... $
Percentage of revenue from daywork contracts.....................................................
Average number of drilling rigs in use..................................................................
Average dayrate on daywork contracts.................................................................. $
Mid-Stream:
Revenue................................................................................................................. $
Operating costs excluding depreciation, amortization, and impairment............... $
Depreciation and amortization............................................................................... $
Gas gathered—Mcf/day.........................................................................................
Gas processed—Mcf/day.......................................................................................
Gas liquids sold—gallons/day...............................................................................
Corporate and other:
General and administrative expense............................................................................ $
Other depreciation....................................................................................................... $
Gain on disposition of assets....................................................................................... $
Other income (expense):
Interest expense, net............................................................................................... $
Gain (loss) on derivatives ..................................................................................... $
Other....................................................................................................................... $
Income tax benefit....................................................................................................... $
Average interest rate....................................................................................................
Average long-term debt outstanding........................................................................... $
357,744
$
294,221
22 %
130,789
101,911
$
$
— $
49.44
18.35
2.46
2,715
4,737
51,260
6.00
174,720
122,600
56,370
100 %
30.0
16,256
207,176
155,483
43,499
385,209
137,625
534,140
38,087
7,477
327
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(38,334) $
$
14,732
$
21
(57,678) $
6.0 %
810,734
$
120,184
113,811
161,563
40.50
11.26
2.07
2,974
5,014
55,735
6.24
122,086
88,154
46,992
100 %
17.4
17,784
185,870
137,609
45,715
419,217
155,461
536,494
33,337
1,835
2,540
(39,829)
(22,813)
307
(71,194)
5.7 %
868,332
9 %
(10)%
(100)%
22 %
63 %
19 %
(9)%
(6)%
(8)%
(4)%
43 %
39 %
20 %
— %
72 %
(9)%
11 %
13 %
(5)%
(8)%
(11)%
— %
14 %
NM
(87)%
(4)%
165 %
(93)%
19 %
5 %
(7)%
_________________________
1.
NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
69
Oil and Natural Gas
Oil and natural gas revenues increased $63.5 million or 22% in 2017 as compared to 2016 due primarily to higher
commodity prices partially offset by a decrease in production. Oil production decreased 9%, NGLs production decreased 6%,
and natural gas production decreased 8%. Average oil prices between the comparative years increased 22% to $49.44 per barrel,
NGLs prices increased 63% to $18.35 per barrel, and natural gas prices increased 19% to $2.46 per Mcf.
Oil and natural gas operating costs increased $10.6 million or 9% between the comparative years of 2017 and 2016
primarily due to higher LOE and gross production taxes partially offset by lower saltwater disposal expense.
DD&A decreased $11.9 million or 10% primarily due to a 4% decrease in our DD&A rate and by the effect of a 7%
decrease in equivalent production. The decrease in our DD&A rate in 2017 compared to 2016 resulted primarily from the effect
of the ceiling test write-downs throughout 2016. Our DD&A expense on our oil and natural properties is calculated each quarter
using period end reserve quantities adjusted for period production.
During 2016, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $161.6 million
pre-tax ($100.6 million net of tax). We did not have a non-cash ceiling test write-down in 2017. The write-downs were due
primarily from the reduction of the 12-month average commodity prices during 2016.
Contract Drilling
Drilling revenues increased $52.6 million or 43% in 2017 as compared to 2016. The increase was due primarily to a 72%
increase in the average number of drilling rigs in use partially offset by a 9% decrease in the average dayrate compared to 2016.
Average drilling rig utilization increased from 17.4 drilling rigs in 2016 to 30.0 drilling rigs in 2017.
Drilling operating costs increased $34.4 million or 39% in 2017 compared to 2016. The increase was due primarily to
more drilling rigs operating. Contract drilling depreciation increased $9.4 million or 20% also due primarily to more drilling
rigs operating.
Mid-Stream
Our mid-stream revenues increased $21.3 million or 11% in 2017 as compared to 2016 primarily due to increased NGLs
and condensate sales. Gas processing volumes per day decreased 11% between the comparative years primarily due to fewer
new well connections to our processing systems. Gas gathering volumes per day decreased 8% primarily due to declining
volumes in the Appalachian region.
Operating costs increased $17.9 million or 13% in 2017 compared to 2016 primarily due to increased natural gas, NGLs,
and condensate prices. Depreciation and amortization decreased $2.2 million or 5% primarily due to less capital expenditures
this year while older assets became fully depreciated.
General and Administrative
General and administrative expenses increased $4.8 million or 14% in 2017 compared to 2016 primarily due to higher
employee costs.
Other Depreciation
Other depreciation increased $5.6 million in 2017 compared to 2016 primarily due to the depreciation on the new ERP
system and the corporate office facility.
Gain on Disposition of Assets
Gain on disposition of assets decreased $2.2 million in 2017 compared to 2016. The gain in 2017 was primarily for the
sale of a corporate aircraft and vehicles, while the pre-tax gain of $3.2 million in 2016 was primarily for the sale of one drilling
rig, various drilling rig components, vehicles, and other equipment somewhat offset by losses from our oil and natural gas and
mid-stream segments in 2016.
70
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $1.5 million between the comparative years of 2017 and 2016. We
capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of
additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2017 was $15.9 million compared
to $15.3 million in 2016, and was netted against our gross interest of $54.2 million and $55.1 million for 2017 and 2016,
respectively. Our average interest rate increased from 5.7% to 6.0% and our average debt outstanding was $57.6 million lower
in 2017 as compared to 2016 primarily due to the decrease in our outstanding borrowings under the Unit credit agreement over
the comparative periods.
Gain (loss) on derivatives increased from a loss of $22.8 million in 2016 to a gain of $14.7 million in 2017 primarily due
to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Baa
enefit
Income tax benefit decreased $13.5 million in 2017 compared to 2016. During the fourth quarter of 2017, the U.S.
government enacted the Tax Cuts and Jobs Act (the Tax Act). Among other provisions, the Tax Act reduces the federal corporate
tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. As a result of the Tax Act, the Company
recorded a tax benefit of $81.3 million due to a revaluation of our net deferred tax liability. Wyy
W
ithout this income tax benefit
charge, income tax expense would have been $23.6 million in 2017 compared to an income tax benefit of $71.2 million in 2016
or an increase of $94.8 million which is commensurate with the increase in pre-tax income for 2017 compared to 2016.
Our effective tax rate was (95.9%) for 2017 compared to 34.4% for 2016. The effective tax rate for the current year was
W
dramatically lower due to the Tax Act and revaluation of our net deferred tax liability. Wyy
benefit, our effective tax rate for 2017 would have been 39.3%. The rate change without consideration of deferred tax liability
revaluation was primarily due to increased deferred income tax expense related to our restricted stock vestings in both years
whereby the increase in 2017 increased our deferred income tax expense and the increase in 2016 decreased our income tax
benefit. We did not pay any income taxes during 2017.
ithout the $81.3 million income tax
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Our operations are exposed to market risks primarily because of changes in the prices for natural gas and oil and interest
rates.
Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas
production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to
our natural gas production. Historically, tyy hese prices have fluctuated and they will probably continue to do so. The price of oil,
NGLs, and natural gas also affects both the demand for our drilling rigs and the amount we can charge for our drilling rigs.
Based on our 2018 production, a $0.10 per Mcf change in what we are paid for our natural gas production would cause a
corresponding $439,000 per month ($5.3 million annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our
oil price would have a $228,000 per month ($2.7 million annualized) change in our pre-tax operating cash flow and a $1.00 per
barrel change in our NGLs prices would have a $393,000 per month ($4.7 million annualized) change in our pre-tax cash flow.
We use derivative transactions to manage the risk associated with price volatility. Oyy
ur decision on the type and quantity of
our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. The
transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a
variable market price to the contract counterparty. Wyy
ot hold or issue derivative instruments for speculative trading
purposes.
e do nWW
ff
71
At December 31, 2018, these non-designated hedges were outstanding:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Jan’19 – Mar'19
Natural gas – swap
Apr'19 – Dec'19
Natural gas – swap
50,000 MMBtu/day
40,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
20,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
10,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
30,000 MMBtu/day
Jan’20 – Dec'20
Natural gas – basis swap
30,000 MMBtu/day
$3.440
$2.900
$(0.659)
$(0.625)
$(0.265)
$(0.275)
IF – NYMEX (HH)
IF – NYMEX (HH)
PEPL
NGPL MIDCON
NGPL TEXOK
NGPL TEXOK
Jan’19 – Dec'19
Natural gas – collar
20,000 MMBtu/day
$2.63 - $3.03
IF – NYMEX (HH)
Jan'19 – Mar'19
Natural gas – three-way collar
30,000 MMBtu/day
$3.17 - $2.92 - $4.32
IF – NYMEX (HH)
Jan’19 – Dec'19
Crude oil – three-way collar
4,000 Bbl/day
$61.25 - $51.25 - $72.93
WTI – NYMEX
After December 31, 2018, these non-designated hedges were entered into:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Apr'19 – Oct'19
Natural gas – swap
20,000 MMBtu/day
$2.900
IF – NYMEX (HH)
Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements and the Notes. The
credit agreements, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election,
borrowings under our credit agreements may be fixed at the LIBOR Rate for periods of up to 180 days. As of February 12,
2019, we had $36.2 million in outstanding borrowings under our Unit credit agreement and no outstanding borrowings under
our Superior credit agreement. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in
arrears on May 15 and November 15 of each year).
72
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Unit Corporation and Subsidiaries
Management’s Report on Internal Control over Financial Reporting.......................................................................................
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm...................................................................................................
Consolidated Balance Sheets at December 31, 2018 and 2017..............................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017, and 2016......................................
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017, and 2016......
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2017, and
2018......................................................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016.....................................
Notes to Consolidated Financial Statements.............................................................................................................................
Page
74
75
77
79
80
81
82
84
73
Management’s Report on Internal Control over Financial Reporting
Management of the company is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in Rules 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or u
nder the supervision of, the company’s principal executive and principal
financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles and includes those policies and procedures that:
yy
•
•
•
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and
dispositions of the assets of the company;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements
in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition
of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because
of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance
and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting
also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that
material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting.
However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into
the process safeguards to reduce, though not eliminate, this risk.
The company’s management assessed the effectiveness of the company’s internal control over financial reporting as of
December 31, 2018. In making this assessment, the company’s management used the criteria set forth in Internal Control—
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on this assessment, our management identified a control deficiency during 2018, that constituted a material weakness.
A material weakness is a deficiency, or c
yy
ombination of deficiencies, in ICFR, such that there is a reasonable possibility
that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a
timely basis.
We did not design and maintain effective controls to verify the proper presentation and disclosure of the interim and
annual consolidated financial statements. Specifically, our controls were not sufficiently precise to allow for the effective
review of the underlying information used in the preparation of the consolidated financial statements, nor verify that
transactions were appropriately presented. This material weakness could result in misstatements of the annual or interim
consolidated financial statements or disclosures that would not be prevented or detected. Accordingly, oyy ur management has
determined that this control deficiency constitutes a material weakness.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2018, has been audited by
PricewaterhouseCoopers LLP, an i
PP
ndependent registered public accounting firm, as stated in their report which appears herein.
74
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Unit Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Unit Corporation and its subsidiaries (the “Company”) as of
December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), changes in
shareholders’ equity, ayy nd cash flows for each of the three years in the period ended December 31, 2018, including the related
notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control
II
over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in a
position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over
financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework
(2013)
issued by the COSO because a material weakness in internal control over financial reporting existed as of that date related to the
ineffective design and maintenance of controls to verify the proper presentation and disclosure of the interim and annual
consolidated financial statements.
ll material respects, the financial
yy
II
yy
ombination of deficiencies, in internal control over financial reporting, such that there
A material weakness is a deficiency, or a c
is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or
detected on a timely basis. The material weakness referred to above is described in Management’s Report on Internal Control
over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and
extent of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the
effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated
financial statements.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included
in management's report referred to above. Our responsibility is to express opinions on the Company’s consolidated financial
statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm
registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
75
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 26, 2019
We have served as the Company’s auditor since 1989.
76
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
2018
2017
(In thousands except share and par
value amounts)
6,452
$
701
119,397
111,512
473
12,870
2,054
22,511
11,356
6,018,568
330,216
1,284,419
767,388
68,339
59,081
29,524
57,507
8,615,042
6,182,726
2,432,316
62,808
27,816
505
721
61
—
6,172
119,672
5,712,813
296,764
1,593,611
726,236
62,618
59,080
29,631
53,439
8,534,192
6,151,450
2,382,742
62,808
16,230
2,698,053
$
2,581,452
Total current assets..............................................................................................................
175,113
Current assets:
ASSETS
Cash and cash equivalents..................................................................................................................... $
Accounts receivable (less allowance for doubtful accounts of $2,531 and $2,450 December 31,
2018 and 2017, respectively).............................................................................................................
Materials and supplies...........................................................................................................................
Current derivative asset (Note 13).........................................................................................................
Current income taxes receivable...........................................................................................................
Assets held for sale (Note 2).................................................................................................................
Prepaid expenses and other....................................................................................................................
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties...........................................................................................................................
Unproved properties not being amortized.....................................................................................
Drilling equipment.................................................................................................................................
Gas gathering and processing equipment..............................................................................................
Saltwater disposal systems....................................................................................................................
Corporate land and building..................................................................................................................
Transportation equipment......................................................................................................................
Other......................................................................................................................................................
Less accumulated depreciation, depletion, amortization, and impairment...........................................
Net property and equipment...............................................................................................
Goodwill (Note 2).......................................................................................................................................
Other assets.................................................................................................................................................
Total assets (1).............................................................................................................................................. $
77
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31,
2018
2017
(In thousands except share and par
value amounts)
Current liabilities:
LIABILITIES AND SHAREHOLDERS’ EQUITY
Accounts payable................................................................................................................................... $
Accrued liabilities (Note 6)...................................................................................................................
Current derivative liabilities (Note 13)..................................................................................................
Current portion of other long-term liabilities (Note 7)..........................................................................
Total current liabilities........................................................................................................
Long-term debt less unamortized discount and debt issuance costs (Note 7)............................................
Non-current derivative liabilities (Note 13)................................................................................................
Other long-term liabilities (Note 7)............................................................................................................
Deferred income taxes (Note 9)..................................................................................................................
Commitments and contingencies (Note 15)................................................................................................
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued........................................
Common stock, $0.20 par value, 175,000,000 shares authorized, 54,055,600 and 52,880,134
shares issued as of December 31, 2018 and 2017, respectively........................................................
Capital in excess of par value................................................................................................................
Accumulated other comprehensive income (loss) (net of tax ($155) and $39 at December 31, 2018
and 2017, respectively) (Note 17).....................................................................................................
Retained earnings..................................................................................................................................
Total shareholders' equity attributable to Unit Corporation..................................................
Non-controlling interests in consolidated subsidiaries..........................................................................
Total shareholders’ equity...........................................................................................................................
Total liabilities and shareholders’ equity (1)................................................................................................ $
149,945
$
112,648
49,664
—
14,250
213,859
644,475
293
101,234
144,748
—
—
10,414
628,108
(481)
752,840
1,390,881
202,563
1,593,444
48,523
7,763
13,002
181,936
820,276
—
100,203
133,477
—
—
10,280
535,815
63
799,402
1,345,560
—
1,345,560
2,698,053
$
2,581,452
_________________________
1.
Unit Corporation's consolidated total assets as of December 31, 2018 include current and long-term assets of its variable interest entity (VIE) (Superior) of
$41.7 million and $421.6 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as
of December 31, 2018 include current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the
VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.
The accompanying notes are an integral part of the consolidated financial statements.
78
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2018
2017
(In thousands except per share amounts)
2016
Revenues:
Oil and natural gas.................................................................................................. $
Contract drilling......................................................................................................
Gas gathering and processing.................................................................................
Total revenues.................................................................................................
$
423,059
196,492
223,730
843,281
$
357,744
174,720
207,176
739,640
Expenses:
Operating costs:
Oil and natural gas...............................................................................................
Contract drilling...................................................................................................
Gas gathering and processing...............................................................................
Total operating costs.......................................................................................
Depreciation, depletion, and amortization..............................................................
Impairments (Note 2)..............................................................................................
General and administrative.....................................................................................
Gain on disposition of assets..................................................................................
Total operating expenses.................................................................................
Income (loss) from operations.....................................................................................
Other income (expense):
Interest, net..............................................................................................................
Gain (loss) on derivatives ......................................................................................
Other........................................................................................................................
Total other income (expense)..........................................................................
Income (loss) before income taxes...............................................................................
Income tax expense (benefit):
Current....................................................................................................................
Deferred..................................................................................................................
Total income taxes..........................................................................................
Net income (loss).........................................................................................................
Net income attributable to non-controlling interest................................................
Net income (loss) attributable to Unit Corporation...................................................... $
Net income (loss) attributable to Unit Corporation per common share:
131,675
131,385
167,836
430,896
243,605
147,884
38,707
(704)
860,388
(17,107)
(33,494)
(3,184)
22
(36,656)
(53,763)
(3,131)
(10,865)
(13,996)
(39,767)
5,521
130,789
122,600
155,483
408,872
209,257
—
38,087
(327)
655,889
83,751
(38,334)
14,732
21
(23,581)
60,170
5
(57,683)
(57,678)
117,848
—
(45,288) $
117,848
Basic........................................................................................................................ $
Diluted.................................................................................................................... $
(0.87) $
(0.87) $
2.31
2.28
$
$
$
294,221
122,086
185,870
602,177
120,184
88,154
137,609
345,947
208,353
161,563
33,337
(2,540)
746,660
(144,483)
(39,829)
(22,813)
307
(62,335)
(206,818)
15
(71,209)
(71,194)
(135,624)
—
(135,624)
(2.71)
(2.71)
The accompanying notes are an integral part of the consolidated financial statements.
79
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss).......................................................................................................... $
Other comprehensive income (loss), net of taxes:
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39,
and $0......................................................................................................................
Comprehensive income (loss)...................................................................................... $
Less: Comprehensive income attributable to non-controlling interest...................
For Years Ended December 31,
2018
2017
2016
(In thousands)
(39,767) $
117,848
$
(135,624)
(557)
63
—
(40,324) $
117,911
$
(135,624)
5,521
—
—
Comprehensive income (loss) attributable to Unit Corporation................................... $
(45,845) $
117,911
$
(135,624)
The accompanying notes are an integral part of the consolidated financial statements.
80
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2016, 2017, and 2018
Shareholders' Equity Attributable to Unit Corporation
Common
Stock
Capital
In Excess
of Par Value
Accumulated
Other
Comprehensive
Income
Retained
Earnings
Non-
controlling
Interest in
Consolidated
Subsidiaries
Total
Balances, January 1, 2016........ $
9,831
$
486,571
$
— $
817,178
$
(In thousands except per share amounts)
Net loss..................................
—
—
Activity in employee
compensation plans
(1,081,217 shares).............
Balances, December 31, 2016..
Net income.............................
Other comprehensive
income (net of tax $39)......
Total comprehensive
income..........................
Proceeds from sale of stock
(787,547 shares)................
Activity in employee
compensation plans
(598,269 shares)................
Balances, December 31, 2017..
Cumulative effect
adjustment for adoption
of ASUs.............................
Net income (loss)...................
Other comprehensive loss
(net of tax ($181))..............
Total comprehensive
loss...............................
Contributions.........................
Transaction costs associated
with sale of non-
controlling interest.............
Tax effect of the sale of
non-controlling interest.....
Activity in employee
compensation plans
(1,175,466 shares).............
185
10,016
—
—
15,929
502,500
—
—
158
18,465
106
10,280
14,850
535,815
—
—
—
—
—
—
—
—
—
102,958
(2,503)
(27,453)
134
19,291
—
—
—
—
63
—
—
63
13
—
(557)
—
—
—
—
(135,624)
—
681,554
117,848
—
—
—
799,402
(1,274)
(45,288)
—
—
—
—
—
— $
—
1,313,580
(135,624)
—
—
—
—
—
—
—
—
5,521
—
197,042
—
—
—
16,114
1,194,070
117,848
63
117,911
18,623
14,956
1,345,560
(1,261)
(39,767)
(557)
(40,324)
300,000
(2,503)
(27,453)
19,425
Balances, December 31, 2018.. $
10,414
$
628,108
$
(481) $
752,840
$
202,563
$
1,593,444
The accompanying notes are an integral part of the consolidated financial statements.
81
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2018
2017
2016
(In thousands)
OPERATING ACTIVITIES:
Net income (loss)....................................................................................................... $
(39,767) $
117,848
$
(135,624)
Adjustments to reconcile net income (loss) to net cash provided (used) by
operating activities:
Depreciation, depletion, and amortization......................................................
Impairments (Note 2)......................................................................................
Amortization of debt issuance costs and debt discount..................................
(Gain) loss on derivatives...............................................................................
Cash receipts (payments) on derivatives settled.............................................
Gain on disposition of assets..........................................................................
Deferred tax benefit........................................................................................
Employee stock compensation plans..............................................................
Bad debt expense............................................................................................
ARO liability accretion...................................................................................
Contract assets and liabilities, net (Note 3)....................................................
Other, net.........................................................................................................
243,605
147,884
2,198
3,184
(22,803)
(704)
(10,865)
22,899
81
2,393
(4,970)
2,032
209,257
—
2,159
(14,732)
173
(327)
(57,683)
17,747
348
2,886
—
(865)
208,353
161,563
2,122
22,813
9,658
(3,127)
(71,209)
13,812
785
2,779
—
(6,037)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable........................................................................................
(12,955)
(32,073)
(11,796)
Materials and supplies....................................................................................
Prepaid expenses and other.............................................................................
Accounts payable............................................................................................
Accrued liabilities...........................................................................................
Income taxes...................................................................................................
Contract advances...........................................................................................
32
(4,950)
26,272
(3,724)
(1,993)
(90)
2,835
1,527
8,192
6,996
38
1,630
225
2,585
27,400
(4,388)
20,903
(687)
Net cash provided by operating activities...............................................
347,759
265,956
240,130
INVESTING ACTIVITIES:
Capital expenditures..................................................................................................
(446,282)
Producing property and other acquisitions................................................................
Proceeds from disposition of property and equipment..............................................
Other..........................................................................................................................
(29,970)
25,910
—
(255,553)
(58,026)
21,713
(1,500)
(186,149)
(564)
74,823
919
Net cash used in investing activities.......................................................
(450,342)
(293,366)
(110,971)
FINANCING ACTIVITIES:
Borrowings under line of credit.................................................................................
99,100
Payments under line of credit....................................................................................
(277,100)
Payments on capitalized leases..................................................................................
(3,843)
Proceeds from common stock issued, net of issue costs (Note 17)...........................
Tax expense from stock compensation......................................................................
—
—
Proceeds from investments in non-controlling interest.............................................
300,000
Transaction costs associated with sale of non-controlling interest............................
Decrease in book overdrafts (Note 2)........................................................................
(2,503)
(7,320)
Net cash provided by (used in) financing activities................................
108,334
Net increase (decrease) in cash and cash equivalents.....................................................
Cash and cash equivalents, beginning of year................................................................
5,751
701
Cash and cash equivalents, end of year........................................................................... $
6,452
$
343,900
(326,700)
(3,694)
18,623
—
—
—
(4,911)
27,218
(192)
893
701
$
251,398
(371,600)
(3,694)
—
(376)
—
—
(4,829)
(129,101)
58
835
893
82
Year Ended December 31,
2018
2017
2016
(In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)..................................................................... $
Income taxes................................................................................................... $
34,535
3,600
$
$
33,931
$
35,690
— $
42
Changes in accounts payable and accrued liabilities related to purchases of
property, plant, and equipment.............................................................................. $
(18,119) $
(20,574) $
21,190
Non-cash reductions to oil and natural gas properties related to asset retirement
obligations............................................................................................................. $
7,629
$
3,613
$
30,897
The accompanying notes are an integral part of the consolidated financial statements.
83
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS
NOTE 1 – ORGANIZATION
Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like
terms refer to Unit Corporation or, as a
a
ppropriate, one or more of its subsidiaries. References to our mid-stream segment refers
rr
to Superior of which we own 50%.
We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties,
the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas.
Our operations are principally in the United States and are organized in the following three reporting segments: (1) Oil and
Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.
Oil and Natural Gas. Carried out by our subsidiary, Uyy
nit Petroleum Company, we e
yy
xplore, develop, acquire, and produce
oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and
related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Montana,
New Mexico, North Dakota, Utah, and Wyoming.
Contract Drilling. Carried out by our subsidiary, Uyy
nit Drilling Company, we d
yy
rill onshore oil and natural gas wells for our
own account and for a wide range of other oil and natural gas companies. Our drilling operations are mainly in Oklahoma,
Texas, Wyoming, North Dakota, and to a lesser extent in Colorado and Utah.
Mid-Stream. Carried out by our subsidiary, Syy uperior, we buy, syy ell, gather, transport, process, and treat natural gas for our
own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West
Virginia.
NOTE 2 – SUMMARY ORR
F SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its
subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our
share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the
accompanying consolidated financial statements. We consolidate the activities of Superior, a 5
Corporation and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the
United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting
standards, since we have the power, trr hrough 50% ownership, to direct those activities that most significantly affect the
economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.
0/50 joint venture between Unit
VV
rr
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to
conform to current year presentations. Certain financial statement captions were expanded or combined with no impact to
consolidated net income or shareholders' equity.
Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting
principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ from those estimates.
Drilling Contracts. We recognize revenues and expenses generated from “daywork” drilling contracts as the services are
performed, since we do not bear the risk of completion of the well. Typically, tyy his type of contract can be used for the drilling of
one well which can take from 10 to 90 days. At December 31, 2018, all of our contracts were daywork contracts of which 24
were multi-well and had durations which ranged from six months to three years, 17 of which expire in 2019 and seven expiring
in 2020 and beyond. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the
ff
periodic renegotiation of the rate within a specific range from the existing rate.
Cash Equivalents and Book Overdrafts. We include as cash equivalents all investments with maturities at date of
purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that
have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At
December 31, 2018 and 2017, book overdrafts were $5.1 million and $12.4 million, respectively.
84
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for
doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial
condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts
only after all collection attempts have been unsuccessful.
Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which
potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas
companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the
large number of customers comprising our customer base. Below are the third-party customers that accounted for more than
10% of our segment’s revenues:
2018
2017
2016
Oil and Natural Gas:
CVR Refining, LP...................................................................................................
Valero Energy Corporation.....................................................................................
Energy Transfer Partners (formerly Sunoco Logistics Partners)............................
Drilling:
QEP Resources, Inc................................................................................................
Slawson Exploration Company, Inc........................................................................
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)...........................
Mid-Stream:
ONEOK, Inc...........................................................................................................
Range Resources Corporation................................................................................
Koch Energy Services, LLC...................................................................................
Tenaska Resources, LLC........................................................................................
14 %
10 %
3 %
16 %
10 %
3 %
45 %
7 %
6 %
4 %
2 %
9 %
10 %
26 %
6 %
7 %
36 %
9 %
8 %
6 %
— %
11 %
24 %
28 %
3 %
18 %
30 %
10 %
11 %
10 %
We had a concentration of cash of $11.0 million and $11.4 million at December 31, 2018 and 2017, respectively with one
bank.
The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms
of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance
risk in our derivative valuation at December 31, 2018 and determined there was no material risk at that time. At December 31,
2018, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity
derivative transactions are listed in the table below:
Bank of Montreal............................................................................................................................................................... $
Bank of America Merrill Lynch........................................................................................................................................
Total net assets................................................................................................................................................................... $
12/31/2018
(In millions)
9.9
2.7
12.6
Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other
property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while
repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method
based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the
equipment is idle, except when idle for greater than 48 months, then it will be depreciated at the full active rate. We use the
composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared
to total estimated remaining footage. Depreciation on our corporate building is computed using the straight-line method over
the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-
line method over the estimated useful lives of the assets ranging from 3 to 15 years.
We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth
quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable.
Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a
85
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
yy
verall changes in general market conditions. Assets are determined to be impaired if a
specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day,
declining cash margin per day, or o
forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any,
is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by
which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information
available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property
and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash
flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and
their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could cause
materially different carrying values of our assets.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs,
expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig
type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s
other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of
these rigs are retired. In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling
rigs and 12 SCR diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under
ASC 360-10-45-9. Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic
decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the
other drilling rigs that we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market
based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on
these estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax), the
fair value of the assets held for sale at December 31, 2018 is $22.5 million. When property and equipment components are
disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is
generally reflected in operations. Our contract drilling segment had no impairments in either 2016 or 2017. For dispositions of
drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, ayy re credited to accumulated depreciation.
ff
We record an asset and a liability equal to the present value of the expected future ARO associated with our oil and gas
properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We
measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase
in the carrying amount of the liability and as a corresponding accretion expense.
Capitalized Interest. During 2018, 2017, and 2016, interest of approximately $16.5 million, $15.9 million, and $15.3
million, respectively, wyy
construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a
weighted average interest rate based on our outstanding borrowings.
as capitalized based on the net book value associated with unproved properties not being amortized, the
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired.
Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has
decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing,
goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment
test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and
other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows
include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded
for the years ended December 31, 2018, 2017, or 2016. There were no additions to goodwill in 2018, 2017, or 2016. Based on
our impairment test performed as of December 31, 2018, the fair value of our drilling segment exceeded its carrying value by
37%. While the goodwill of this reporting unit is not currently impaired, there could be an impairment in the future as a result of
changes in certain assumptions. For example, the fair value could be adversely affected and result in an impairment of goodwill
if we do not realize the anticipated drilling rig utilization of the anticipated drilling rig dayrates, or if the estimated cash flows
are discounted at a higher risk-adjusted rate or market multiples decrease. Goodwill of $0.4 million is deductible for tax
purposes.
Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the
full cost method of accounting prescribed by the SEC. Accordingly, ayy ll productive and non-productive costs incurred in
connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly
related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based
on proved oil and natural gas reserves. Directly related overhead costs of $15.9 million, $14.8 million, and $15.4 million were
86
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
capitalized in 2018, 2017, and 2016, respectively. Independent petroleum engineers annually audit our internal evaluation of our
reserves. The average rates used for DD&A were $7.50, $6.00, and $6.24 per Boe in 2018, 2017, and 2016, respectively. The
calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves
and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved
properties, and equipment not placed in service. Our unproved properties and wells in progress totaling $330.2 million are
excluded from the DD&A calculation.
No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a
significant reserve amount to our total reserves is involved. Revenue from the sale of oil and natural gas is recognized when
title passes, net of royalties.
Under the full cost rules, at the end of each quarter, we r
rr
eview the carrying value of our oil and natural gas properties. The
full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties
discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the
12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise
determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized
exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess
occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an
impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $7.6 million and $10.5
million in 2016 and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We did not
have any in 2018. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million
pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters
of the year. We hWW ad no non-cash ceiling test write-downs during 2017 or 2018.
Our contract drilling segment provides drilling services for our exploration and production segment. Depending on the
timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be
associated with the acquisition of an ownership interest in the property. Ryy
evenues and expenses for these services are eliminated
in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The
contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties.
By providing drilling services for the oil and natural gas segment, we eliminated revenue of $22.5 million and $13.4 million
during 2018 and 2017, respectively, fyy rom our contract drilling segment and eliminated the associated operating expense of
$19.5 million and $11.8 million during 2018 and 2017, respectively, yyy ielding $3.0 million and $1.6 million during 2018 and
2017, respectively, as a r
expenses in our contract drilling segment during 2016.
eduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or
yy
ff
ARO. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case,
when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and
abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or
acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uff
determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical
location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and
an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any
change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding
adjustment is made to the full cost pool.
ses historical experience to
Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering
and processing of natural gas and NGLs in the period the service is provided based on contractual terms.
Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee
medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to
$1.0 million. We hWW ave purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate
exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us
against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure,
decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.
87
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value with the exception of
normal purchase and normal sales which are expected to result in physical delivery. Ayy
occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our
Consolidated Statements of Operations.
ny changes in our derivatives' fair value
We document our risk management strategy and do not engage in derivative transactions for speculative purposes.
Limited Partnerships. Unit Petroleum Company is a general partner in 13 oil and natural gas limited partnerships sold
privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share
in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The
partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.
Income Taxes.
aa
During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the
Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The
change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of
enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax
liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); the
effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where
necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year
and the change during that year in deferred tax assets and liabilities.
The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also
provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
f
Natural Gas Balancing. We
account for revenue transactions under ASC 606 for recording natural gas sales, which may
i
be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2018 balancing position
to be approximately 3.8 Bcf on under-produced properties and approximately 3.7 Bcf on over-produced properties. We have
recorded a receivable of $2.9 million on certain wells where we estimate that insufficient reserves are available for us to recover
the under-production from future production volumes. We have also recorded a liability of $3.3 million on certain properties
where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production
from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred.
Such expenses relating to the balancing position on wells in which we have imbalances are not material.
di
d
f
l
l
Employee and Director Stock Based Compensation. We recognize in our financial statements the cost of employee
services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount
of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas
segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are
recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes
option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants is based on
the closing stock price on the date of the grants.
New Accounting Standards
FF
Fair Value Measurement (Topic 820): Disclosure Frr
ramework—Changes to the Disclosur
e Rrr
equirements for Fair Value
Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were
removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after
December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and
delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our
financial statements.
Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB
issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic
718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The
amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This
amendment will not have a material impact on our financial statements.
88
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to
simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment
will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This
amendment will not have a material impact on our financial statements.
ff
Leases. The FASB has issued several accounting standards updates and amendments related to leases in the past two
years, which are codified within Topic 842. For public companies, these are effective for annual periods beginning after
December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the
commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the
lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the
lease term. Other recently issued amendments to Topic 842 have provided clarifying guidance regarding land easements, an
additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees
and lessors. The standard will not apply to leases of mineral rights.
We established an implementation team working through the provisions of the new guidance including a review of
different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes,
internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the
new guidance is substantially complete.
We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition
exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization
threshold. Our transition will utilize the modified retrospective approach to adopting the new standard, and will be applied at
the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We have elected the transition practical
expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019, and the optional transition
method to record our immaterial adoption impact through a cumulative adjustment to equity. Wyy
e eWW xpect for certain lessee asset
classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will account
for the agreements as a single lease component.
We have determined that Unit Drilling Company lessor drilling rig contracts will be accounted for under ASC 606 as the
service has been deemed the predominate component of the contract.
For both lessee and lessor practical expedients, we considered quantitative and qualitative factors when determining if an
asset class qualified for the application of the practical expedient.
The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the
consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. Upon
adoption, the Company expects to record operating lease right-of-use assets and the corresponding operating lease liabilities in
the range of approximately $3.0 million to $4.5 million, representing the present value of future lease payments under operating
leases. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its
processes. There would be no impact to the Superior credit agreement debt covenants and an immaterial impact to the Unit
credit agreement debt covenants as a result of adopting this standard.
Adopted Standards
As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other
Comprehensive Income. We adopted this amendment early and it had no material effect to our financial statements. We
previously used 37.75% to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our
Consolidated Statements of Comprehensive Income and in Note 17 - Equity.
ff
Also, as of January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606)
TT
and all later amendments that modified ASC 606. We elected to apply this standard on the modified retrospective approach
method to contracts not completed as of January 1, 2018, where the cumulative effect on adoption, which only affected our
mid-stream segment, is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to
the timing of revenue recognition for certain demand fees. Our oil and natural gas and contract drilling segments had no
retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.
The additional disclosures required by ASC 606 have been included in Note 3 – Revenue from Contracts with Customers.
Our internal control framework did not materially change because of this standard, but the existing internal controls have
been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard,
89
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU
2014-09.
NOTE 3 – REVENUE FROM CONTACTS WITH CUSTOMERS
Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our
disaggregation of revenue and how our segment revenue is reported (as reflected in Note 18 – Industry Segment Information).
Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the
contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide
drilling rigs and services over an agreed-on time period. Revenue from the mid-stream segment is derived from gathering,
transporting, and processing natural gas production and selling those commodities. We sell the hydrocarbons (from the oil and
natural gas and mid-stream segments) to mid-stream and downstream oil and gas companies.
We satisfy the performance obligation under each segment's contracts as follows: for the contract drilling and mid-stream
contracts, we satisfy the performance obligation over the agreed-on time within the contracts, and for oil and natural gas
contracts, we satisfy the performance obligation with each delivery of volumes. For oil and natural gas contracts, as it is more
feasible, we account for these deliveries monthly. Per the contracts for all segments, customers pay for the services/goods
received monthly within an agreed on number of days following the end of the month. Besides the mid-stream demand fees
discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting
pronouncement.
Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations
Typical types of revenue contracts signed by our segments are Oil Sales Contracts, Gas Purchase Agreements, North
American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the
non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract term
can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues
from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and
downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated
from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard
required no adjustment to opening retained earnings.
Certain costs—as either a deduction from revenue or as an expense—is determined based on when control of the
commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For
example, gathering, processing and transportation costs included as part of the contract price with the customer on transfer of
control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity
represent operating costs. The impact of the adoption of ASC 606 did not impact income from operations or net income for the
year ended December 31, 2018. These tables summarize the impact of the adoption of ASC 606 on revenue and operating costs
for the year ended December 31, 2018:
Oil and natural gas revenues................................................................................... $
423,059
$
(17,518) $
Oil and natural gas operating costs.........................................................................
131,675
(17,518)
Gross profit............................................................................................................. $
291,384
$
— $
As Reported
Adjustments
due to ASC 606
(In thousands)
Amounts
without the
Adoption of
ASC 606
440,577
149,193
291,384
Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically,
the contract is for a specified period (for example, a month or a year); however, each delivery under that contract can be
considered separately identifiable since each delivery provides benefits to the customer on its own. For feasibility, as accounting
for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we
conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days
following the end of the month which includes payment for all deliveries in that month. Depending on contract circumstances,
judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts and
circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers
to our purchaser.
90
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
Most of the consideration received by us for oil and gas sales is variable. Most of our contracts state the consideration is
calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation,
fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted
average sales price. These different pricing tools can change the perception of when control transfers; however, wrr
with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the
variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore,
whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to
each reporting period. An estimation and allocation of transaction price and future obligations are not required.
hen analyzed
Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations
The contracts our drilling segment uses are primarily industry standard IADC contracts model year 2003 and 2013.
Contract terms range from six months to three or more years or can be based on terms to drill a specific number of wells. The
allocation rules in ASC 606 (called the "series guidance") provide that a contract may contain a single performance obligation
composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet
the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same
method as it relates to the satisfaction of the overall performance obligation. We have determined that the delivery of drilling
services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment
of service (i.e. hour available to drill) that the drilling contractor promises to transfer represents a performance obligation that
would meet the criteria for recognizing revenue over time, and 2) the drilling contractor would use the same method for
measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At
inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable
consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned
over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and
penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under this new standard
allow us to recognize revenues associated with our drilling contacts in materially the same manner as under the previous
revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer
of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/
recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the
same method of measure used for revenue. On adoption of the standard, no adjustment to opening retained earnings was
required.
Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on
period as stated in the contract. Any mobilization and demobilization activities are not considered distinct within the context of
the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and
recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling
a well; therefore, depending on the number of wells under a contract, the contract term could be up to three years. Most of the
drilling contracts are for less than one year. Arr
company’s performance, and the company’s performance enhances an asset that the customer controls, the performance
obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the
month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The
company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or
by a set date.
s the customer simultaneously receives and consumes the benefits provided by the
All consideration received for contract drilling is variable, excluding termination fees, which we have concluded will not
apply to our contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of
days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items
under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All
variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained
or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding
certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated
the mobilization and de-mobilization charges on outstanding contracts, however, trr he impact to the financial statements was
immaterial. As of December 31, 2018, we had 32 contract drilling contracts (24 of which are term contracts) for a duration of
two months to three years.
dd
Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical
expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the
91
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority of our drilling contracts have an original term of
less than one year; however, the remaining performance obligations under the contracts that have a longer duration are not
material.
Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations
Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The
typical revenue contracts used by this segment are gas gathering and processing agreements. Contract terms range from a single
month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering,
transportation, processing) are performance obligations and meet the criteria of over time recognition which could be
considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and
processing services.
On adoption of the standard, an adjustment to opening retained earnings was made for $1.7 million ($1.3 million, net of
tax). This adjustment—related to the timing of revenue recognized on certain demand fees—impacted our Consolidated
Balance Sheet (for the periods indicated) as follows:
Balance at
December 31,
2017
Adjustments
due to ASC 606
(In thousands)
Balance at
January 1,
2018
Assets:
Other assets.......................................................................................................... $
16,230
$
10,798
$
27,028
Liabilities and shareholders' equity:
Current portion of other long-term liabilities.......................................................
Other long-term liabilities....................................................................................
Deferred income taxes..........................................................................................
Retained earnings.................................................................................................
13,002
100,203
133,477
799,402
2,748
9,737
(413)
(1,274)
15,750
109,940
133,064
798,128
At December 31, 2018:
As Reported
Adjustments
due to ASC 606
(In thousands)
Amounts
without the
Adoption of
ASC 606
Assets:
Prepaid expenses and other.................................................................................. $
11,356
$
285
$
Other assets..........................................................................................................
27,816
12,879
Liabilities and shareholders' equity:
Current portion of other long-term liabilities.......................................................
Other long-term liabilities....................................................................................
Deferred income taxes..........................................................................................
Retained earnings.................................................................................................
14,250
101,234
144,748
752,840
2,874
7,007
805
2,478
11,071
14,937
11,376
94,227
143,943
750,362
This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the
Consolidated Statement of Operations for 2018:
As Reported
Adjustments
due to ASC 606
(In thousands)
Amounts
without the
Adoption of
ASC 606
Gas gathering and processing revenues.................................................................. $
223,730
$
4,970
$
218,760
Deferred income tax benefit...................................................................................
Net income (loss)....................................................................................................
(10,865)
(39,767)
1,218
3,752
(12,083)
(43,519)
92
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The only fixed consideration related to mid-stream consideration is a demand fee calculated by multiplying an agreed-on
price by a fixed number of volumes per month over a specified term in the contract.
Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all
variable consideration to be earned with the associated contract.
Contract
Remaining
Term of
Contract
2019
2020
2021
2022
Total Remaining
Impact to
Revenue
Demand fee contracts........... 4 years
$
2,632 $
(3,781) $
(3,507) $
1,374 $
(3,282)
Before implementing ASC 606, we immediately recognized the entire demand fee since the fee was payable within the
first five years from the effective date of the contract and not over the entire term of the contract. However, as the demand fee
does not specifically relate to a distinct performance obligation, under the new standard that amount should now be recognized
over the life of the contract. Therefore, the demand fee previously recognized for $1.7 million ($1.3 million, net of tax) was
adjusted to retained earnings as of January 1, 2018 and will be recognized over the remaining term of the contract. As this
amount is fixed, recognition of the remaining portion will be stable. Besides the demand fee, there were no other contract assets
or liabilities (see above for the balance sheet line items where they are reported). For 2018, $5.0 million was recognized in
revenue for these demand fees.
December 31,
2018
January 1,
2018
Change
(In thousands)
Contract assets........................................................................................................ $
13,164
$
10,798
$
Contract liabilities...................................................................................................
9,881
12,485
Contract assets (liabilities), net............................................................................... $
3,283
$
(1,687) $
2,366
(2,604)
4,970
Our performance obligations for all contracts is to gather, transport, or process an agreed-on number of volumes as stated
in the contract. Typically, the contract will establish a period over which the company will perform the mid-stream services.
Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will
deliver or service. The term under mid-stream service contracts is typically five to ten years. Under service contracts, as the
customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the
performance obligation to gather, transport, or process occurs over time. We typically receive payment within a set number of
days following the end of the month and includes payment for all services performed that month. Our overall performance
obligation is satisfied at the end of the contract term.
Most of the consideration received under mid-stream service contracts is variable. The consideration is calculated by
multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee).
One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per
day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore,
whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known
before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes
over the course of more than one month.
Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for
contracts with an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for
“variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single
performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated
previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at
606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s
efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is
consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable
consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount
was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts.
We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of
volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in
93
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under
each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less
than one year to 15 years.
While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and
allocation of transaction price and future obligations are not required.
NOTE 4 – ACQUISITIONS AND DIVESTITURES
Acquisitions
For 2016, we had approximately $0.6 million in acquisitions.
On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo
Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million.
As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired
properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas
leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing
wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of
the transaction.
We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires
that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes
the final adjusted purchase price and the values of assets acquired and liabilities assumed.
Final Adjusted Purchase Price
Total consideration given........................................................................................................................................................... $
54,332
Final Adjusted Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties ...................................................................................................................................... $
Undeveloped oil and natural gas properties.............................................................................................................................
Total oil and natural gas properties included in the full cost pool (1)..........................................................................................
Gas gathering equipment and other............................................................................................................................................
43,745
8,650
52,395
2,340
Asset retirement obligation.........................................................................................................................................................
(403)
Fair value of net assets acquired................................................................................................................................................. $
54,332
_________________________
1. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural
gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery
rates, and risk adjusted discount rates.
The pro forma effects of this acquired business are immaterial to the results of operations.
For 2017, we had approximately $4.7 million in other acquisitions.
In December 2018, we closed on an acquisition of certain oil and natural gas assets located primarily in Custer County,
Oklahoma. The total preliminary adjusted value of consideration given was $29.6 million As of November 1, 2018, the effective
date of the acquisition, the estimated proved oil and gas reserves for the acquired properties was 2.6 MMBoe net to Unit. The
acquisition added approximately 8,667 net oil and gas leasehold acres to our Penn Sands area in Oklahoma including
approximately 44 wells. The acquisition included approximately 30 potential horizontal drilling locations which are anticipated
to have a high percentage of oil relative to the total production stream. Of the acreage acquired, approximately 82% was held by
production.
94
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires
that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes
the final adjusted purchase price and the values of assets acquired and liabilities assumed.
Preliminary Purchase Price
Total consideration given........................................................................................................................................................... $
29,633
Preliminary Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties....................................................................................................................................... $
Undeveloped oil and natural gas properties.............................................................................................................................
Total oil and natural gas properties included in the full cost pool (1)..........................................................................................
14,546
15,502
30,048
Asset retirement obligation.........................................................................................................................................................
(415)
Fair value of net assets acquired................................................................................................................................................. $
29,633
_________________________
1. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural
gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery
rates, and risk adjusted discount rates.
The pro forma effects of this acquired business are immaterial to the results of operations.
For 2018, we had approximately $0.6 million in other acquisitions.
Divestitures
Oil and Natural Gas
We had non-core asset sales with proceeds, net of related expenses, of $22.5 million, $18.6 million, and $67.2 million, in
2018, 2017, and 2016, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no
gain or loss recognized.
Contract Drilling
During December 2016, we sold one idle 1500 HP SCR drilling rig to an unaffiliated third party. The proceeds of this
sale, less costs to sell, exceeded the $1.7 million net book value of the drilling rig, resulting in a gain of $1.6 million.
We did not have any divestitures in 2017.
In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR
diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9.
Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on
our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that
we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the
estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these
estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax).
Mid-Stream
On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior. The purchaser is SP
Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a
global private markets investment manager. We received $300.0 million from this sale. A portion of the proceeds were used to
pay down our bank debt and the remainder were used to accelerate the drilling program of our upstream subsidiary, Unit
Petroleum Company and build additional BOSS drilling rigs. In connection with the sale of the interest in Superior, we took the
necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale
and have Superior released from the Indenture.
95
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Superior will be governed and managed under its Amended and Restated Limited Liability Company Agreement and the
Master Services and Operating Agreement (MSA) signed by Superior and an affiliate of Unit, as both agreements may be
amended occasionally. Further details are in Note 16 – Variable Interest Entity Arrangements.
NOTE 5 – EARNINGS (LOSS) PER SHARE
The following data shows the amounts used in computing earnings (loss) per share:
Income (Loss)
(Numerator)
Weighted
Shares
(Denominator)
(In thousands except per share amounts)
Per-Share
Amount
For the year ended December 31, 2016:
Basic loss attributable to Unit Corporation per common share..................... $
(135,624)
50,029
$
Effect of dilutive stock options, restricted stock, and SARs.........................
—
—
Diluted loss attributable to Unit Corporation per common share.................. $
(135,624)
50,029
$
For the year ended December 31, 2017:
Basic earnings attributable to Unit Corporation per common share............. $
117,848
51,113
$
Effect of dilutive stock options......................................................................
—
635
Diluted income attributable to Unit Corporation per common share............ $
117,848
51,748
$
For the year ended December 31, 2018:
Basic loss attributable to Unit Corporation per common share.....................
(45,288)
51,981
$
Effect of dilutive restricted stock...................................................................
—
—
Diluted loss attributable to Unit Corporation per common share.................. $
(45,288)
51,981
$
(2.71)
—
(2.71)
2.31
(0.03)
2.28
(0.87)
—
(0.87)
Due to the net loss for the years ended December 31, 2018 and 2016, approximately 934,000 and 509,000, respectively,
weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the
earnings per share calculation above.
The following options and their average exercise prices were not included in the computation of diluted earnings per
share because the option exercise prices were greater than the average market price of our common stock for the years ended
December 31:
2018
2017
2016
Options and SARs........................................................................................................
66,500
87,500
Average exercise price................................................................................................. $
44.42
$
51.34
$
199,755
48.79
NOTE 6 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31:
2018
2017
(In thousands)
Employee costs........................................................................................................................................... $
22,056
$
Lease operating expenses............................................................................................................................
12,756
Interest payable...........................................................................................................................................
Third-party credits......................................................................................................................................
Taxes...........................................................................................................................................................
Other............................................................................................................................................................
6,635
2,129
1,378
4,710
19,521
11,819
6,745
2,240
3,404
4,794
Total accrued liabilities............................................................................................................................... $
49,664
$
48,523
96
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 7 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Long-term debt consisted of the following as of December 31:
Unit credit agreement with average interest rate of 3.4% at December 31, 2017...................................... $
(In thousands)
— $
Superior credit agreement...........................................................................................................................
—
6.625% senior subordinated notes due 2021..............................................................................................
650,000
Total principal amount........................................................................................................................... $
650,000
$
Less: unamortized discount........................................................................................................................
Less: debt issuance costs, net......................................................................................................................
(1,623)
(3,902)
178,000
—
650,000
828,000
(2,234)
(5,490)
Total long-term debt.............................................................................................................................. $
644,475
$
820,276
2018
2017
Unit Credit Agreement. On October 18, 2018, we signed a Fifth Amendment to our Senior Credit Agreement (Unit credit
agreement) amending our existing credit agreement entered into between the Company and certain lenders on September 13,
2011, as amended September 5, 2012, as further amended April 10, 2015, as further amended on April 8, 2016, as further
amended on April 2, 2018, attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 15,
2011, September 11, 2012, April 13, 2015, April 8, 2016, and April 6, 2018, respectively, and the Company’s Current Report on
Form 8-K/A filed on April 13, 2016, and each incorporated by reference herein.
The Fifth Amendment, among other things, (i) extends the term of the Unit credit agreement to October 18, 2023, subject
to certain conditions; (ii) reduces the pricing for borrowing and non-use fees; and (iii) eliminates the requirement that the
company maintain a senior indebtedness to consolidated EBITDA ratio. The total commitment of credit and the borrowing base
both remain unchanged at $425.0 million.
Under the Unit credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment
amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit
agreement. We are charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on
the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency,
syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the Unit credit
agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total
value of our oil and gas properties.
On April 2, 2018, we signed the fourth amendment to the Unit credit agreement. The Fourth Amendment provided,
among other things, for a reduction of the maximum credit amount from $875.0 million to $425.0 million, a reduction in the
borrowing base from $475.0 million to $425.0 million, a reduction in the total commitment amount from $475.0 million to
$425.0 million; and the full release of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit
agreement. Under the amendment once the sale of the interest in Superior was completed, we were required to use part of the
proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018 and the pay down was made that
day.
On May 2, 2018, as contemplated under the Fourth Amendment, we entered into a Pledge Agreement with BOKF, NA
(dba Bank of Oklahoma), as administrative agent for the benefit of the secured parties, under which we granted a security
interest in the limited liability membership interests and other equity interests we own in Superior (which as of the date of this
report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the
Unit credit agreement.
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–
is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may
request a one time special redetermination of the borrowing base between each scheduled redetermination. In addition, we may
request a redetermination following the completion of an acquisition that meets the requirements set forth in the Unit credit
agreement.
97
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
At our election, any part of the outstanding debt under the Unit credit agreement may be fixed at a London Interbank
Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.50% to 2.50%
depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days,
whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement that cannot
be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in
whole or in part at any time, without a premium or penalty. Ayy
Unit credit agreement.
t December 31, 2018, we had no outstanding borrowings under the
We can use borrowings for financing general working capital requirements for (a) exploration, development, production
and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of
credit, (d) contract drilling services, and (e) general corporate purposes.
The Unit credit agreement prohibits, among other things:
•
•
•
•
the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income
for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions;
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except for our lenders; and
investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.
The Unit credit agreement also requires that we have at the end of each quarter:
•
•
a current ratio (as defined in the credit agreement) of not less than 1 to 1.
a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently
ended rolling four fiscal quarters of no greater than 4 to 1.
As of December 31, 2018, we were in compliance with the covenants contained in the Unit credit agreement.
Superior Credit Agreement. On May 10, 2018, Superior, a limited liability company equally owned between us and SP
ff
Investor Holdings, LLC, entered into a five-year
increase the credit amount up to $250.0 million, subject to certain conditions. The amounts borrowed under the Superior credit
agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25%
or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus
1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by,
among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.
, $200.0 million senior secured revolving credit facility with an option to
Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the
amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syy yndication,
and other related fees. These fees are being amortized over the life of the Superior credit agreement.
The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the
most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not
greater than 4.00 to 1.00. Additionally, tyy he Superior credit agreement contains a number of customary covenants that, among
other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on
its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with
affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of
December 31, 2018, Superior was in compliance with the Superior credit agreement covenants
ff
The borrowings the Superior credit agreement will be used to fund capital expenditures and acquisitions, provide general
working capital, and for letters of credit for Superior.
On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the
agreement.
Superior's credit agreement is not guaranteed by Unit.
98
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior
subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each
year. The Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees
that are being amortized as debt issuance cost over the life of the Notes.
The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association
(successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of
May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture
dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the
terms and providing for issuing the Notes. The Guarantors are our direct and indirect subsidiaries. The discussion of the Notes
in this report is qualified by and subject to the actual terms of the 2011 Indenture.
Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes
(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary
releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets
of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not
Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through
dividends, loans, advances or otherwise.
We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid
interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any
part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and
unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture
also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or
guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness;
transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with
other companies. We were in compliance with all covenants of the Notes as of December 31, 2018.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following as of December 31:
2018
2017
(In thousands)
ARO liability............................................................................................................................................... $
64,208
$
Workers’ compensation...............................................................................................................................
Capital lease obligations.............................................................................................................................
Contract liability.........................................................................................................................................
Separation benefit plans..............................................................................................................................
Deferred compensation plan.......................................................................................................................
Gas balancing liability................................................................................................................................
Less current portion....................................................................................................................................
12,738
11,380
9,881
8,814
5,132
3,331
115,484
14,250
Total other long-term liabilities.................................................................................................................. $
101,234
$
69,444
13,340
15,224
—
6,524
5,390
3,283
113,205
13,002
100,203
Estimated annual principal payments under the terms of debt and other long-term liabilities from 2019 through 2023 are
$14.2 million, $9.4 million, $692.0 million, $3.9 million, and $2.2 million, respectively.
Capital Leases
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of
seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital
lease obligations of $4.0 million is included in current portion of other long-term liabilities and the non-current portion of $7.4
million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2018.
These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases
are $4.1 million and $0.6 million, respectively at December 31, 2018. Annual payments, net of maintenance and interest,
99
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
average $4.3 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the
assets at 10% of the fair market value of the assets at that time.
Future payments required under the capital leases at December 31, 2018 are as follows:
Ending December 31,
2019.....................................................................................................................................................................
$
2020.....................................................................................................................................................................
2021.....................................................................................................................................................................
Total future payments..................................................................................................................................
Less payments related to:
Maintenance........................................................................................................................................................
Interest.................................................................................................................................................................
Present value of future minimum payments..................................................................................
$
Amount
(In thousands)
6,168
6,168
3,768
16,104
4,089
635
11,380
NOTE 8 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets
(AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are
depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period
in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of
settling these AROs. All of our AROs relate to plugging costs associated with our oil and gas wells.
The following table shows certain information about our AROs for the periods indicated:
2018
2017
(In thousands)
ARO liability, January 1:............................................................................................................................ $
69,444
$
Accretion of discount...............................................................................................................................
Liability incurred......................................................................................................................................
Liability settled.........................................................................................................................................
Liability sold............................................................................................................................................
Revision of estimates (1)...........................................................................................................................
ARO liability, December 31:......................................................................................................................
Less current portion....................................................................................................................................
2,393
2,632
(4,493)
(281)
(5,487)
64,208
1,437
Total long-term ARO liability..................................................................................................................... $
62,771
$
70,170
2,886
1,948
(2,694)
(1,735)
(1,131)
69,444
1,726
67,718
_________________________
1.
Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had
various upward and downward adjustments and changes in estimated timing of cash flows.
NOTE 9 – INCOME TAXES
During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among its many provisions, the Tax Act
reduces the federal corporate tax rate from 35% to 21%, effective January 1, 2018. The change in tax law required the Company
to revalue its existing net deferred tax liability using the lower rate in the period of enactment resulting in the recognition of an
income tax benefit of $81.3 million for the year ended December 31, 2017 related to that revaluation. As a result, the Company
recognized an overall income tax benefit of $57.7 million for the year ended December 31, 2017.
100
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss)
to our effective income tax expense (benefit) is as follows:
2018
2017
(In thousands)
2016
Income tax expense (benefit) computed by applying the statutory rate....................... $
(11,290) $
21,059
$
State income tax expense (benefit), net of federal benefit...........................................
Deferred tax liability revaluation (1).............................................................................
Restricted stock shortfall..............................................................................................
Non-controlling interest in Superior.............................................................................
Statutory depletion and other.......................................................................................
(1,882)
—
424
(1,138)
(110)
1,655
(81,307)
1,867
—
(952)
(72,386)
(5,687)
—
5,465
—
1,414
Income tax benefit................................................................................................ $
(13,996) $
(57,678) $
(71,194)
__________________________
1.
In 2017, the revaluation from the Tax Act.
For the periods indicated, the total provision for income taxes consisted of the following:
2018
2017
(In thousands)
2016
Current taxes:
Federal.................................................................................................................. $
(1,835) $
— $
State......................................................................................................................
Deferred taxes:
Federal..................................................................................................................
State......................................................................................................................
(1,296)
(3,131)
(8,741)
(2,124)
(10,865)
5
5
(62,788)
5,105
(57,683)
Total provision............................................................................................. $
(13,996) $
(57,678) $
—
15
15
(62,923)
(8,286)
(71,209)
(71,194)
Deferred tax assets and liabilities are comprised of the following at December 31:
2018
2017
(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals.............................................................................. $
27,953
$
Net operating loss carryforward.........................................................................................................
Alternative minimum tax and research and development tax credit carryforward.............................
152,112
3,574
183,639
Deferred tax liability:
Depreciation, depletion, amortization, and impairment.....................................................................
Investment in Superior........................................................................................................................
Net deferred tax liability.............................................................................................................
Current deferred tax asset...........................................................................................................................
Non-current—deferred tax liability............................................................................................................ $
(291,542)
(36,845)
(144,748)
—
(144,748) $
32,242
153,746
5,409
191,397
(324,874)
—
(133,477)
—
(133,477)
Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is
not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the
deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are
reduced. We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal
tax examinations for years before 2016 or state income tax examinations by state taxing authorities for years before 2015. At
December 31, 2018, we have federal net operating loss carryforwards of approximately $576.9 million which expire from 2021
to 2037.
101
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
NOTE 10 – EMPLOYEE BENEFIT PLANS
Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage
of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a
specified maximum, in full or on a partial basis. We made discretionary contributions under the plan of 184,203, 155,822, and
630,039 shares of common stock and recognized expense of $5.1 million, $4.4 million, and $4.0 million in 2018, 2017, and
2016, respectively.
We provide a salary deferral plan (Deferral Plan) which allows participants to defer the recognition of salary for income
tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined
unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2018 and 2017 was $5.1
million and $5.4 million, respectively. We rWW ecognized payroll expense and recorded a liability at the time of deferral.
Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible
employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of
service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of
service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in
exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior
Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally
equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the
selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special
Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest
of a participant’s reaching the age of 65 or serving 20 years with the company.
On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code
of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the
timing of payments, and the circumstances under which employees become eligible to receive benefits. On December 8, 2015,
we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the
Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized
expense of $3.6 million, $2.7 million, and $3.1 million in 2018, 2017, and 2016, respectively, fyy or benefits associated with
anticipated payments from these separation plans.
ff
We have entered into key employee change of control contracts with three of our current executive officers. These
yy
efined in the contracts, occurs during the term of
severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, uyy nless a
notice not to extend is given by us. If a change of control of the company, as d
the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally
provide that the executive’s terms and conditions for employment (including position, work location, compensation, and
benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is
terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or
the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of
control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control,
the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9
times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions
that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three
years.
ff
ff
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the
executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to
receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and
render services commensurate with his position.
NOTE 11 – TRANSACTIONS WITH RELATED PARTIES
Unit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships)
which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas
exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with
2011. Previously, tyy here were three non-employee partnerships, one that was formed in 1984 and two formed in 1986
102
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31,
2016, the two 1986 partnerships were also dissolved.
The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in
1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in
2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the
authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited
partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil
and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed.
The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one
percent.
Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general
partner are as follows:
2018
2017
(In thousands)
2016
Well supervision and other fees................................................................................... $
General and administrative expense reimbursement....................................................
158
$
—
172
$
—
254
6
Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These
costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative
reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses
allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by
management to be reasonable.
As of December 31, 2016, John Nikkel retired as director and chairman of Unit's board and is no longer considered a
related party. As of 2016, Mr. Nikkel was a 25.8% owner of Rampart Holdings, Inc. which owned 100% of Toklan Oil and Gas
Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert
Nikkel is Toklan's President, and he owned 20.0% of the company. There were no material revenues in 2016. There were no
material royalties to disclose for 2016. Toklan operates the North Custer Gathering System, an inactive (since 2009) gathering
system, under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel held an
approximate 25.0% ownership interest and in which Mr. Robert Nikkel held ownership interest of approximately 20.0%. West
Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments
from West Thomas under that contract amounted to $0.4 million for 2016 volumes purchased. Additionally, on March 10, 2016,
Mr. Nikkel purchased in the open market $0.4 million in aggregate principal amount of our outstanding 6.625% senior
subordinated notes due 2021. The notes pay interest semi-annually in cash in arrears on May 15 and November 15 of each year.
For 2016, interest payments for May and November were approximately $4,800 and $13,250, respectively.
One of our directors, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-
controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. The Company in the
ordinary course of business, paid royalties or lease bonuses, primarily due to its status as successor in interest to prior
transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr.
Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.9
million, $0.7 million, and $0.5 million during 2018, 2017, and 2016, respectively.
Our Audit Committee and the board, in accordance with our related party transaction policy, have determined that these
arrangements are in the best interest of the Company.
NOTE 12 – STOCK-BASED COMPENSATION
For restricted stock awards, we had:
Recognized stock compensation expense.................................................................... $
17.8
$
13.3
$
Capitalized stock compensation cost for our oil and natural gas properties................
Tax benefit on stock based compensation....................................................................
2.1
4.4
1.8
5.0
9.6
2.1
3.6
2018
2017
(In millions)
2015
103
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The remaining unrecognized compensation cost related to unvested awards at December 31, 2018 is approximately $16.1
million of which $1.9 million is anticipated to be capitalized. The weighted average period of time over which this cost will be
recognized is 0.8 of a year.
The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the
amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of
subsidiaries) and to non-employee directors. A total of 7,230,000 shares of the company's common stock is authorized for
issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that can
be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:
•
•
•
•
•
•
•
•
•
incentive stock options under Section 422 of the Internal Revenue Code;
non-qualified stock options;
performance shares;
performance units;
restricted stock;
restricted stock units;
stock appreciation rights;
cash based awards; and
other stock-based awards.
This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All
awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in
the award agreement.
Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise
and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation
purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States
Treasury Strips rate using the term over which it is anticipated the grant will be exercised.
SARs
Activity pertaining to SARs granted under the amended plan is as follows:
Number of
Shares
Weighted
Average
Price
Outstanding at January 1, 2016...................................................................................................................
131,770
$
46.60
Granted..................................................................................................................................................
Exercised...............................................................................................................................................
Forfeited................................................................................................................................................
Outstanding at December 31, 2016.............................................................................................................
Granted..................................................................................................................................................
Exercised...............................................................................................................................................
—
—
(40,515)
91,255
—
—
Forfeited................................................................................................................................................
(91,255)
Outstanding at December 31, 2017.............................................................................................................
— $
—
—
51.76
44.31
—
—
44.31
—
There were no SARs granted or vested during 2018, 2017, or 2016. There were no SARs exercised in 2018. The SARs
expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2018.
104
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Restricted Stock
Activity pertaining to restricted stock awards granted under the amended plan is as follows:
Number of
Time Vested
Shares
Number of
Performance
Vested Shares
Total
Number of
Shares
Weighted
Average
Price
Employees
Nonvested at January 1, 2016........................................................
Granted.....................................................................................
Vested.......................................................................................
Forfeited...................................................................................
Nonvested at December 31, 2016..................................................
Granted.....................................................................................
Vested.......................................................................................
Forfeited...................................................................................
Nonvested at December 31, 2017..................................................
Granted.....................................................................................
Vested.......................................................................................
Forfeited...................................................................................
936,662
494,078
(425,195)
(75,808)
929,737
485,799
(455,570)
(44,408)
915,558
844,498
(470,171)
(21,002)
Nonvested at December 31, 2018..................................................
1,268,883
Non-Employee Directors
277,160
152,373
—
(57,405)
372,128
173,373
(62,119)
(34,953)
448,429
390,445
(209,643)
(21,106)
608,125
1,213,822
$
646,451
(425,195)
(133,213)
1,301,865
659,172
(517,689)
(79,361)
1,363,987
1,234,943
(679,814)
(42,108)
1,877,008
$
41.29
5.62
43.47
36.87
23.32
26.07
29.87
38.87
21.25
20.52
24.30
19.80
19.70
Number of
Shares
Weighted
Average
Price
Nonvested at January 1, 2016.....................................................................................................................
42,064
$
Granted..................................................................................................................................................
Vested....................................................................................................................................................
Forfeited................................................................................................................................................
90,000
(20,248)
—
Nonvested at December 31, 2016...............................................................................................................
111,816
$
Granted..................................................................................................................................................
Vested....................................................................................................................................................
Forfeited................................................................................................................................................
49,104
(43,206)
—
Nonvested at December 31, 2017...............................................................................................................
117,714
$
Granted..................................................................................................................................................
Vested....................................................................................................................................................
Forfeited................................................................................................................................................
44,312
(54,981)
—
Nonvested at December 31, 2018...............................................................................................................
107,045
$
41.83
12.02
43.46
—
17.21
17.92
21.24
—
16.03
19.86
17.08
—
17.07
The time vested restricted stock awards granted are being recognized over a three year vesting period. During 2016, there
were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three
years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and
will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year,
over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance
measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance
criteria at December 31, 2018, the participants are estimated to receive 69% of the 2018, 99% of the 2017, and 200% of the
2016 performance based shares. The CFTA performance measurement at December 31, 2018 for the one-third vesting in 2019
was assessed to vest at 100%. The CFTA performance measurement for future years was assessed to vest at target or 100%.
The fair value of the restricted stock granted in 2018, 2017, and 2016 at the grant date was $24.7 million, $17.4 million,
and $4.5 million, respectively. The aggregate intrinsic value of the 734,795 shares of restricted stock that vested in 2018 on
their vesting date was $15.0 million. The aggregate intrinsic value of the 1,984,053 shares of restricted stock outstanding
subject to vesting at December 31, 2018 was $28.3 million with a weighted average remaining life of 1.1 of a year.
105
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Non-Employee Directors' Stock Option Plan
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each
annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an
employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The
option price for each stock option was the fair market value of the common stock on the date the stock options were granted.
The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six
months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this
plan, the remaining available shares were transferred over to the new plan and no further awards were made under the non-
employee director option plan.
Activity pertaining to the Directors’ Plan is as follows:
Number of
Shares
Weighted
Average
Exercise
Price
Outstanding at January 1, 2016...................................................................................................................
129,500
$
54.15
Granted..................................................................................................................................................
Exercised...............................................................................................................................................
Forfeited................................................................................................................................................
Outstanding at December 31, 2016.............................................................................................................
Granted..................................................................................................................................................
Exercised...............................................................................................................................................
Forfeited................................................................................................................................................
Outstanding at December 31, 2017.............................................................................................................
Granted..................................................................................................................................................
Exercised...............................................................................................................................................
—
—
(21,000)
108,500
—
—
(21,000)
87,500
—
—
Forfeited................................................................................................................................................
(21,000)
Outstanding at December 31, 2018.............................................................................................................
66,500
$
—
—
62.40
52.56
—
—
57.63
51.34
—
—
73.26
44.42
There were no options exercised in 2018.
Weighted Average Exercise Price
Outstanding and Exercisable
Options at December 31, 2018
Weighted
Average
Remaining
Contractual
Life
Weighted
Average
Exercise Price
Number
of Shares
$31.30 - $41.21............................................................................................................
$53.81 - $73.26............................................................................................................
38,500
28,000
0.9 years $
2.3 years $
37.58
53.81
There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2018. The remaining
weighted average remaining contractual term is 1.5 years.
NOTE 13 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil
production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will
receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract
106
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
are based, in part, on our view of current and future market conditions. As of December 31, 2018, our derivative transactions
consisted of the following types of hedges:
•
•
•
•
Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the
counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or
from the counterparty.
Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the
commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge
the price risk between NYMEX and its physical delivery points.
Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike
price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is
between the call and the put strike price, no payments are due from either party.
Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put) and a
fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price
and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due
from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike
price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the
difference between the floor and subfloor strike prices and pay the market price.
We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage
in derivative transactions for speculative purposes. All derivatives are recognized on the balance sheet and measured at fair
value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are
reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
At December 31, 2018, the following non-designated hedges were outstanding:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Jan’19 – Mar'19
Natural gas – swap
Apr'19 – Dec'19
Natural gas – swap
50,000 MMBtu/day
40,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
20,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
10,000 MMBtu/day
Jan’19 – Dec'19
Natural gas – basis swap
30,000 MMBtu/day
Jan’20 – Dec'20
Natural gas – basis swap
30,000 MMBtu/day
$3.440
$2.900
$(0.659)
$(0.625)
$(0.265)
$(0.275)
IF – NYMEX (HH)
IF – NYMEX (HH)
PEPL
NGPL MIDCON
NGPL TEXOK
NGPL TEXOK
Jan’19 – Dec'19
Natural gas – collar
20,000 MMBtu/day
$2.63 - $3.03
IF – NYMEX (HH)
Jan'19 – Mar'19
Natural gas – three-way collar
30,000 MMBtu/day
$3.17 - $2.92 - $4.32
IF – NYMEX (HH)
Jan’19 – Dec'19
Crude oil – three-way collar
4,000 Bbl/day
$61.25 - $51.25 - $72.93
WTI – NYMEX
After December 31, 2018, the following non-designated hedges were entered into:
Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Apr'19 – Oct'19
Natural gas – swap
20,000 MMBtu/day
$2.900
IF – NYMEX (HH)
The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated
Balance Sheets at December 31:
Balance Sheet Location
2018
2017
(In thousands)
Derivative Assets
Fair Value
Commodity derivatives:
Current...................................................................... Current derivative assets
Long-term................................................................. Non-current derivative assets
Total derivative assets.......................................................
$
$
12,870
$
—
12,870
$
721
—
721
107
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Balance Sheet Location
Derivative Liabilities
Fair Value
2018
2017
(In thousands)
Commodity derivatives:
Current...................................................................... Current derivative liabilities
Long-term................................................................. Non-current derivative liabilities
Total derivative liabilities.................................................
$
$
— $
293
293
$
7,763
—
7,763
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our
Consolidated Balance Sheets.
Effect of derivative instruments on the Consolidated Statements of Operations for the year ended December 31:
Derivatives Instruments
Location of Gain or (Loss)
Recognized in Income on
Derivative
Commodity derivatives .................................... Gain (loss) on derivatives (1)
Total..................................................................
_________________________
1.
Amounts settled during the periods are a loss of $22,803 and a gain of $173, respectively.
NOTE 14 – FAIR VALUE MEASUREMENTS
Amount of Gain or (Loss)
Recognized in Income on
Derivative
2018
2017
(In thousands)
$
$
(3,184) $
(3,184) $
14,732
14,732
The estimated fair value of our available-for-sale securities, reflected on our Condensed Consolidated Balance Sheets as
Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:
Cost
Gross
Unrealized
Gains
Gross
Unrealized
Losses
Estimated Fair
Value
(In thousands)
Equity Securities:
December 31, 2018................................................................... $
December 31, 2017................................................................... $
830
830
$
$
— $
102
$
636
$
— $
194
932
During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a
long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost
is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge
will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-
temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the
extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent
and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. These securities
would be classified as Level 2.
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in
an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level
hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given
to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:
•
Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.
108
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
•
•
Level 2—significant observable pricing inputs other than quoted prices included within level 1 that are either directly
or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are
derived principally from or corroborated by observable market data.
Level 3—generally unobservable inputs which are developed based on the best information available and may
include our own internal data.
The inputs available to us determine the valuation technique we use to measure the fair values of our financial
instruments.
The following tables set forth our recurring fair value measurements:
December 31, 2018
Level 2
Level 3
Effect of
Netting
Total
(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets...................................................................................... $
3,225
$
10,964
$
(1,319) $
12,870
Liabilities................................................................................
(1,278)
(334)
1,319
(293)
$
1,947
$
10,630
$
— $
12,577
December 31, 2017
Level 2
Level 3
Effect of
Netting
Total
(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets...................................................................................... $
2,137
$
3,344
$
(4,760) $
Liabilities................................................................................
(8,973)
(3,550)
4,760
$
(6,836) $
(206) $
— $
721
(7,763)
(7,042)
All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of
the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our
counterparties and no collateral has been posted as of December 31, 2018.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table
above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).
Level 2 Fair Value Measurements
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal
discounted cash flow calculations based on the NYMEX futures index.
Level 3 Fair Value Measurements
Commodity Derivatives. The fair values of our natural gas and crude oil collars are estimated using internal discounted
cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes
obtained from counterparties to the agreements.
109
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following tables are reconciliations of our level 3 fair value measurements:
Net Derivatives
For the Year Ended,
December 31, 2018 December 31, 2017
(In thousands)
Beginning of period....................................................................................................................... $
(206) $
(7,122)
Total gains or losses:
Included in earnings (1)........................................................................................................
Settlements..........................................................................................................................
End of period................................................................................................................................. $
Total gains for the period included in earnings attributable to the change in unrealized loss
relating to assets still held at end of period............................................................................... $
4,159
6,677
10,630
10,836
$
$
7,791
(875)
(206)
6,916
_________________________
1.
Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2018:
Commodity (1)
Fair Value
(In thousands)
Valuation Technique
Unobservable Input
Range
Oil three-way collar................... $
10,592
Discounted cash flow
Forward commodity price curve
$0.00 - $19.44
Natural gas collars..................... $
Natural gas three-way collar...... $
(334)
372
Discounted cash flow
Forward commodity price curve
$0.00 - $0.38
Discounted cash flow
Forward commodity price curve
$0.00 - $0.43
_________________________
1.
The commodity contracts detailed in this category include non-exchange-traded crude and natural gas three-way collars and natural gas collars that are
valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.
Based on our valuation at December 31, 2018, we determined that the non-performance risk with regard to our
counterparties was immaterial.
Fair Value of Other Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting
guidance for financial instruments. We have determined the estimated fair values by using available market information and
valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value.
The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value
amounts.
At December 31, 2018, the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as
Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because
of their short term nature.
Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and
also considering the risk of our non-performance, long-term debt under our credit agreements would approximate its fair value.
This debt would be classified as Level 2. At December 31, 2018, we did not have any outstanding debt under our credit
agreements.
The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes
reported in the Consolidated Balance Sheets at December 31, 2018 and December 31, 2017 were $644.5 million and $642.3
million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2018 and
December 31, 2017 were $600.5 million and $649.7 million, respectively. These Notes would be classified as Level 2.
Fair Value of Non-Financial Instruments
The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal
estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the
110
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented
in Note 8 – Asset Retirement Obligations.
Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived
assets and goodwill. During 2016 and 2018, we recorded non-cash impairment charges discussed further in Note 2 – Summary
of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as
Level 3.
NOTE 15 – COMMITMENTS AND CONTINGENCIES
We lease office space or yards in Edmond and Oklahoma City, Oyy
klahoma; Houston, Texas; Englewood, Colorado;
yy
Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021.
Additionally, we h
drilling rig equipment and production inventory. Fyy uture minimum rental payments under the terms of the leases are
approximately $4.6 million, $1.7 million, and $0.4 million in 2019 through 2021, respectively. Total rent expense incurred was
$9.9 million, $8.8 million, and $11.1 million in 2018, 2017, and 2016, respectively.
ave several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess
TT
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of
seven years. Future capital lease payments under the terms are approximately $6.2 million each year through 2020 and
approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $4.1 million and $0.6
million, respectively at December 31, 2018. Annual payments, net of maintenance and interest, average $4.3 million annually
through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market
value of the assets at that time.
The employee oil and gas limited partnerships require, on the election of a limited partner, trr hat we repurchase the limited
partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20%
of the units outstanding. We made repurchases of approximately $1,700, $2,900, $5,000 in 2018, 2017, and 2016, respectively.
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and
assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our
environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the
liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental
direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount
of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent
of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the
property to our satisfaction, or agree to assume liability for the remediation of the property.
ff
We have not historically experienced any environmental liability while being a contract driller since the greatest portion
of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is
on the location and the cost has been included in the direct cost of drilling the well.
For 2019, we have committed to purchase approximately $9.2 million of new drilling rig components.
We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the
elieve the reasonably possible losses from such matter,
elieve the probable final outcome of such matters will not
results of litigation and claims cannot be predicted with certainty, we b
individually and in the aggregate, are not material. Additionally, we b
have a material adverse effect on our results of operations, financial position, or cash flows.
yy
yy
NOTE 16 – VARIABLE INTEREST ENTITY ARRANGEMENTS
VV
On April 3, 2018 we sold 50% of the ownership interest in Superior. Trr
he 50% interest in Superior we sold was acquired
by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners
Group, a global private markets investment manager. Srr uperior will be governed and managed under the Amended and Restated
Limited Liability Company Agreement and the MSA. The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (the
Operator) and Superior. The Operator is owned 100% by Unit Corporation. Under the guidance in ASC 810, Consolidation, we
have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in
Superior and the MSA. The MSA houses the power to direct the activities that most significantly impact Superior's operating
performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant
111
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
activities; reciprocally the equity investors lack the power to direct the activities that most significantly impact the entity’s
economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary
beneficiary as of December 31, 2018.
As the primary beneficiary of this VIE, we consolidate in the financial statements the financial position, results of
operations and cash flows of this VIE, and all intercompany balances and transactions between us and the VIE are eliminated in
the consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are
allocated to the equity owners as specified in the relevant agreements.
On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant
agreements.
As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human
resources to Superior for a monthly service fee of $250,000. Superior's creditors have no recourse to our general credit.
Superior's credit agreement is not guaranteed by Unit. The obligations under Superior's credit agreement are secured by, among
other things, mortgage liens on certain of Superior’s processing plants and gathering systems.
The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in
the consolidated balance sheets were as follows:
Current assets:
Cash and cash equivalents........................................................................................................................................... $
Accounts receivable....................................................................................................................................................
Prepaid expenses and other.........................................................................................................................................
Total current assets.................................................................................................................................................
Property and equipment:
Gas gathering and processing equipment....................................................................................................................
Transportation equipment...........................................................................................................................................
Less accumulated depreciation, depletion, amortization, and impairment.................................................................
Net property and equipment..................................................................................................................................
Other assets.......................................................................................................................................................................
Total assets........................................................................................................................................................................ $
Current liabilities:
Accounts payable........................................................................................................................................................ $
Accrued liabilities.......................................................................................................................................................
Current portion of other long-term liabilities..............................................................................................................
Total current liabilities...........................................................................................................................................
Long-term debt less debt issuance costs...........................................................................................................................
Other long-term liabilities................................................................................................................................................
Total liabilities.................................................................................................................................................................. $
December 31,
2018
(In thousands)
5,841
33,207
2,693
41,741
767,388
3,086
770,474
364,740
405,734
15,907
463,382
32,214
3,688
6,875
42,777
—
14,687
57,464
112
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 17 – EQUITY
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may
offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up
to an aggregate offering price of $100.0 million. We intended to use the net proceeds from these sales to fund (or offset costs of)
acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate
purposes.
On May 2, 2018, we terminated the Distribution Agreement. The Distribution Agreement was terminable at will on
written notification by us with no penalty. As of the date of termination, we had sold 787,547 shares of our common stock under
the Distribution Agreement resulting in net proceeds of approximately $18.6 million. We paid the sales agent a commission of
2.0% of the gross sales price per share sold. As a result of the termination, there will be no more sales of our common stock
under the Distribution Agreement.
Accumulated Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income (loss) were as follows for the years ended December 31:
2018
2017
2016
(In thousands)
Unrealized appreciation (depreciation) on securities, before tax................................. $
Tax benefit (expense) (1)...............................................................................................
(738) $
181
Unrealized appreciation (depreciation) on securities, net of tax.................................. $
(557) $
102
$
(39)
63
$
—
—
—
_______________________
1.
In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.
Changes in accumulated other comprehensive income (loss) by component, net of tax, for the years ended December 31
are as follows:
Net Gains on Equity Securities
2018
2017
2016
—
—
—
—
—
—
—
(In thousands)
$
— $
—
—
63
—
63
63
$
Balance at December 31:.............................................................................................. $
Adjustment due to ASU 2018-02 (1)........................................................................
Balance at January 1:....................................................................................................
Unrealized appreciation (depreciation) before reclassifications (1).........................
Amounts reclassified from accumulated other comprehensive income..................
Net current-period other comprehensive income (loss)...............................................
63
13
76
(557)
—
(557)
Balance at December 31:.............................................................................................. $
(481) $
_______________________
1.
In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.
113
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATTT EMENTS— (Continued)
NOTE 18 – INDUSTRY SRR
EGMENT INFORMATION
We have three main business segments offering different products and services:
•
•
Oil and natural gas,
Contract drilling, and
• Mid-stream
The oil and natural gas segment is engaged in the development, acquisition, and production of oil, NGLs, and natural gas
properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream
segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.
We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less
operating expenses and depreciation, depletion, amortization, and impairment. Our oil and natural gas production outside the
United States is not significant.
114
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following table provides certain information about the operations of each of our segments:
Oil and
Natural Gas
Contract
Drilling
Mid-stream
Other
Eliminations
Total
Consolidated
Year Ended December 31, 2018
(In thousands)
Revenues: (1)
Oil and natural gas............................... $
423,059
$
— $
Contract drilling...................................
Gas gathering and processing...............
—
—
218,982
—
Total revenues..............................
423,059
218,982
— $
—
312,417
312,417
Expenses:
Operating costs:
Oil and natural gas..........................
136,870
Contract drilling..............................
Gas gathering and processing.........
—
—
—
150,834
—
Total operating costs..................
136,870
150,834
Depreciation, depletion, and
amortization...................................
Impairments (2)...................................
133,584
—
Total expenses...............................
270,454
General and administrative................
Gain on disposition of assets.............
—
(139)
57,508
147,884
356,226
—
(425)
Income (loss) from operations...
152,744
(136,819)
Loss on derivatives............................
Interest expense, net..........................
Other..................................................
—
—
—
—
—
—
—
—
251,328
251,328
44,834
—
296,162
—
(110)
16,365
—
(1,214)
—
— $
— $
423,059
—
—
—
—
—
—
—
7,679
—
7,679
38,707
(30)
(46,356)
(3,184)
(32,280)
22
(22,490)
(88,687)
(111,177)
196,492
223,730
843,281
(5,195)
(19,449)
(83,492)
(108,136)
—
—
(108,136)
—
—
(3,041)
—
—
—
131,675
131,385
167,836
430,896
243,605
147,884
822,385
38,707
(704)
(17,107)
(3,184)
(33,494)
22
Income (loss) before income taxes....... $
152,744
$
(136,819) $
15,151
$
(81,798) $
(3,041) $
(53,763)
Identifiable assets:
Oil and natural gas (3)......................... $
1,357,779
$
— $
Contract drilling.................................
Gas gathering and processing............
Total identifiable assets (4)...............
Corporate land and building..............
Other corporate assets (5)....................
—
—
806,696
—
1,357,779
806,696
—
—
—
—
— $
—
466,851
466,851
—
—
— $
(6,949) $
1,350,830
—
—
—
55,505
25,566
(85)
(5,023)
806,611
461,828
(12,057)
2,619,269
—
(2,287)
55,505
23,279
Total assets................................. $
1,357,779
$
806,696
$
466,851
$
81,071
$
(14,344) $
2,698,053
Capital expenditures:......................... $
367,335
$
75,510
$
44,810
$
1,125
$
— $
488,780
_______________________
1.
The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
2.
3.
4.
5.
Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.
Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
Identifiable assets are those used in Unit’s operations in each industry segment.
Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
115
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Oil and
Natural Gas
Contract
Drilling
Mid-stream
Other
Eliminations
Total
Consolidated
Year Ended December 31, 2017
(In thousands)
Revenues:
Oil and natural gas............................... $
357,744
$
— $
Contract drilling...................................
Gas gathering and processing..............
—
—
188,172
—
Total revenues..............................
357,744
188,172
— $
—
277,049
277,049
Expenses:
Operating costs:
Oil and natural gas.........................
135,532
Contract drilling.............................
Gas gathering and processing.........
—
—
—
134,432
—
Total operating costs.................
135,532
134,432
Depreciation, depletion and
amortization..................................
Total expenses...........................
General and administrative...............
(Gain) loss on disposition of assets...
101,911
237,443
—
(228)
56,370
190,802
—
776
—
—
220,613
220,613
43,499
264,112
—
(25)
Income (loss) from operations..
120,529
(3,406)
12,962
Gain on derivatives...........................
Interest expense, net..........................
Other..................................................
—
—
—
—
—
—
—
—
—
— $
— $
357,744
—
—
—
—
—
—
—
7,477
7,477
38,087
(850)
(44,714)
14,732
(38,334)
21
(13,452)
(69,873)
(83,325)
(4,743)
(11,832)
(65,130)
(81,705)
—
(81,705)
—
—
(1,620)
—
—
—
174,720
207,176
739,640
130,789
122,600
155,483
408,872
209,257
618,129
38,087
(327)
83,751
14,732
(38,334)
21
Income (loss) before income taxes...... $
120,529
$
(3,406) $
12,962
$
(68,295) $
(1,620) $
60,170
Identifiable assets:
Oil and natural gas (1)........................ $ 1,134,080
$
— $
Contract drilling................................
Gas gathering and processing...........
Total identifiable assets (2)..............
Corporate land and building.............
Other corporate assets (3)...................
—
—
933,063
—
1,134,080
933,063
—
—
—
—
— $
—
439,369
439,369
—
—
— $
(6,180) $
1,127,900
—
—
—
56,854
25,064
—
(798)
933,063
438,571
(6,978)
2,499,534
—
—
56,854
25,064
Total assets................................ $ 1,134,080
$
933,063
$
439,369
$
81,918
$
(6,978) $
2,581,452
Capital expenditures:........................ $
270,443
$
36,148
$
22,168
$
3,521
$
— $
332,280
_______________________
1.
Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
2.
3.
Identifiable assets are those used in Unit’s operations in each industry segment.
Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
116
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Oil and
Natural Gas
Contract
Drilling
Mid-stream
Other
Eliminations
Total
Consolidated
Year Ended December 31, 2016
Revenues:
Oil and natural gas.............................. $
294,221
$
— $
Contract drilling..................................
Gas gathering and processing.............
—
—
122,086
—
Total revenues.............................
294,221
122,086
Expenses:
Operating costs:
Oil and natural gas.........................
126,739
Contract drilling.............................
Gas gathering and processing........
—
—
Total operating costs................
126,739
Depreciation, depletion and
amortization..................................
Impairments (1).................................
Total expenses.............................
General and administrative..............
(Gain) loss on disposition of assets..
113,811
161,563
402,113
—
324
Income (loss) from operations.
(108,216)
Gain on derivatives..........................
Interest expense, net.........................
Other.................................................
—
—
—
(In thousands)
— $
—
237,785
237,785
—
—
182,969
182,969
45,715
—
—
—
—
—
—
—
—
1,835
—
1,835
33,337
18
(35,190)
(22,813)
(39,829)
307
—
88,154
—
88,154
46,992
—
135,146
228,684
—
(3,184)
(9,876)
—
—
—
—
302
8,799
—
—
—
— $
— $
294,221
—
(51,915)
(51,915)
(6,555)
—
(45,360)
(51,915)
—
—
(51,915)
—
—
—
—
—
—
122,086
185,870
602,177
120,184
88,154
137,609
345,947
208,353
161,563
715,863
33,337
(2,540)
(144,483)
(22,813)
(39,829)
307
Income (loss) before income taxes..... $
(108,216) $
(9,876) $
8,799
$
(97,525) $
— $
(206,818)
Identifiable assets:
Oil and natural gas (2)....................... $
970,238
$
— $
Contract drilling...............................
Gas gathering and processing...........
Total identifiable assets (3).............
Corporate land and building.............
Other corporate assets (4)..................
—
—
941,676
—
970,238
941,676
—
—
—
—
— $
—
462,330
462,330
—
—
— $
(5,079) $
965,159
—
—
—
58,188
52,680
—
(730)
941,676
461,600
(5,809)
2,368,435
—
—
58,188
52,680
Total assets............................... $
970,238
$
941,676
$
462,330
$
110,868
$
(5,809) $
2,479,303
Capital expenditures:........................ $
89,562
$
19,134
$
16,796
$
16,663
$
— $
142,155
_______________________
1. We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).
2.
3.
4.
Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
Identifiable assets are those used in Unit’s operations in each industry segment.
Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
117
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 19 – SELECTED QUARTERLY FINANCIAL INFORMATION
Summarized unaudited quarterly financial information is as follows:
Three Months Ended
March 31
June 30
September 30
December 31
(In thousands except per share amounts)
2017
Revenues............................................................................... $
Gross income (1)..................................................................... $
Net income attributable to Unit Corporation........................ $
175,724
32,657
15,929
Net income attributable to Unit Corporation per common
share:
Basic.............................................................................. $
Diluted (2)....................................................................... $
0.32
0.31
2018
Revenues............................................................................... $
Gross income (loss) (1)........................................................... $
Net income attributable to Unit Corporation........................ $
Net income (loss) attributable to Unit Corporation per
common share:
Basic.............................................................................. $
Diluted........................................................................... $
205,132
38,833
7,865
0.15
0.15
$
$
$
$
$
$
$
$
$
$
170,581
24,462
9,059
0.18
0.17
203,303
40,915
5,788
0.11
0.11
$
$
$
$
$
$
$
$
$
$
188,488
27,181
3,705
0.07
0.07
220,058
49,216
18,899
0.36
0.36
$
$
$
$
$
$
$
$
$
$
204,847
37,211
89,155
1.74
1.71
214,788
(108,068)
(77,840)
(1.49)
(1.49)
_________________________
1.
Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income
taxes, and other income (loss).
2.
The earnings per share for the year's four quarters does not equal annual income per share.
NOTE 20 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
We have no significant assets or operations other than our investments in our subsidiaries. Our wholly owned subsidiaries
are the guarantors of our Notes. On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior
and that company and its subsidiaries are no longer guarantors of the Notes. Instead of providing separate financial statements
for each subsidiary issuer and guarantor, we have included the accompanying unaudited condensed consolidating financial
statements based on Rule 3-10 of the SEC's Regulation S-X.
For purposes of the following footnote:
•
•
•
we are referred to as "Parent",
the direct subsidiaries are 100% owned by the Parent and the guarantee is full and unconditional and joint and
several and referred to as "Combined Guarantor Subsidiaries", and
Superior and its subsidiaries and the Operator are referred to as "Non-Guarantor Subsidiaries."
The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate
accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor
Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods
indicated.
118
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Balance Sheets
Parent
Combined
Guarantor
Subsidiaries
December 31, 2018
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Current assets:
ASSETS
Cash and cash equivalents........................................................ $
403
$
208
$
5,841
$
— $
6,452
Accounts receivable, net of allowance for doubtful accounts
of $2,531 (Guarantor of $1,326 and Parent of $1,205)........
Materials and supplies..............................................................
Current derivative asset............................................................
Current income tax receivable..................................................
Assets held for sale...................................................................
Prepaid expenses and other......................................................
Total current assets.......................................................
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties................................................................
Unproved properties not being amortized..........................
Drilling equipment...................................................................
Gas gathering and processing equipment.................................
Saltwater disposal systems.......................................................
Corporate land and building.....................................................
Transportation equipment.........................................................
Other.........................................................................................
Less accumulated depreciation, depletion, amortization, and
impairment...........................................................................
Net property and equipment.........................................
Intercompany receivable................................................................
Goodwill.........................................................................................
2,539
—
12,870
243
—
5,103
21,158
—
—
—
—
—
—
9,273
28,584
37,857
27,504
10,353
950,916
—
Investments.....................................................................................
1,160,444
Other assets....................................................................................
5,115
94,526
36,676
(14,344)
119,397
473
—
1,811
22,511
3,560
123,089
6,018,568
330,216
1,284,419
—
68,339
59,081
17,165
28,923
—
—
—
—
2,693
45,210
—
—
—
767,388
—
—
3,086
—
7,806,711
770,474
5,790,481
2,016,230
—
62,808
1,500
5,293
364,741
405,733
—
—
—
15,908
—
—
—
—
—
473
12,870
2,054
22,511
11,356
(14,344)
175,113
—
—
—
—
—
—
—
—
—
—
—
(950,916)
—
(1,160,444)
—
6,018,568
330,216
1,284,419
767,388
68,339
59,081
29,524
57,507
8,615,042
6,182,726
2,432,316
—
62,808
1,500
26,316
Total assets..................................................................................... $
2,147,986
$
2,208,920
$
466,851
$
(2,125,704) $
2,698,053
119
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Parent
Combined
Guarantor
Subsidiaries
December 31, 2018
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable..................................................................... $
8,697
$
122,610
$
32,214
$
(13,576) $
149,945
Accrued liabilities....................................................................
Current portion of other long-term liabilities...........................
Total current liabilities..................................................
Intercompany debt..........................................................................
28,230
812
37,739
—
Bonds payable less debt issuance costs..........................................
644,475
Non-current derivative liabilities....................................................
Other long-term liabilities..............................................................
Deferred income taxes....................................................................
293
13,134
60,983
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares
authorized, none issued........................................................
—
Common stock, $.20 par value, 175,000,000 shares
authorized, 54,055,600 shares issued...................................
Capital in excess of par value...................................................
Contributions from Unit...........................................................
Accumulated other comprehensive loss...................................
10,414
628,108
—
—
16,409
6,563
145,582
948,707
—
—
73,713
83,765
—
—
5,493
6,875
44,582
2,209
—
—
14,687
—
—
—
(468)
—
(14,044)
(950,916)
—
—
(300)
—
—
—
45,921
197,042
(242,963)
—
(481)
49,664
14,250
213,859
—
644,475
293
101,234
144,748
—
10,414
628,108
—
(481)
792
—
4,976
202,810
202,563
405,373
(792)
—
(916,689)
752,840
(1,160,444)
1,390,881
—
202,563
(1,160,444)
1,593,444
Retained earnings.....................................................................
752,840
911,713
Total shareholders’ equity attributable to Unit
Corporation..............................................................
1,391,362
957,153
Non-controlling interests in consolidated subsidiaries.............
—
—
Total shareholders' equity.............................................
1,391,362
957,153
Total liabilities and shareholders’ equity........................................ $
2,147,986
$
2,208,920
$
466,851
$
(2,125,704) $
2,698,053
120
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Parent
Combined
Guarantor
Subsidiaries
December 31, 2017
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Current assets:
ASSETS
Cash and cash equivalents........................................................ $
510
$
191
$
— $
— $
701
89,622
28,714
(6,978)
111,512
—
—
—
877
—
—
—
—
29,591
(6,978)
Accounts receivable, net of allowance for doubtful accounts
of $2,450 (Guarantor of $1,245 and Non-Guarantor of
$1,205).................................................................................
Materials and supplies..............................................................
Current derivative asset............................................................
Current income tax receivable..................................................
Prepaid expenses and other......................................................
Total current assets.......................................................
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties................................................................
Unproved properties not being amortized..........................
Drilling equipment...................................................................
Gas gathering and processing equipment.................................
Saltwater disposal systems.......................................................
Corporate land and building.....................................................
Transportation equipment.........................................................
Other.........................................................................................
Less accumulated depreciation, depletion, amortization, and
impairment...........................................................................
Net property and equipment.........................................
154
—
721
610
2,925
4,371
—
—
—
—
—
—
9,270
28,039
37,309
21,268
16,041
Intercompany receivable................................................................
1,155,725
Goodwill.........................................................................................
—
Investments.....................................................................................
1,044,709
Other assets....................................................................................
5,373
505
—
—
2,370
92,688
5,712,813
296,764
1,593,611
—
62,618
59,080
17,423
25,400
—
—
—
726,236
—
—
2,938
—
7,767,709
729,174
5,807,757
1,959,952
—
62,808
1,500
6,328
322,425
406,749
—
—
—
3,029
505
721
61
6,172
119,672
5,712,813
296,764
1,593,611
726,236
62,618
59,080
29,631
53,439
8,534,192
6,151,450
2,382,742
—
62,808
1,500
14,730
—
—
—
—
—
—
—
—
—
—
—
(1,155,725)
—
(1,044,709)
—
Total assets..................................................................................... $
2,226,219
$
2,123,276
$
439,369
$
(2,207,412) $
2,581,452
121
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Parent
Combined
Guarantor
Subsidiaries
December 31, 2017
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable..................................................................... $
13,124
$
87,514
$
18,988
$
(6,978) $
112,648
Accrued liabilities....................................................................
Current derivative liability........................................................
Current portion of other long-term liabilities...........................
Total current liabilities............................................
Intercompany debt..........................................................................
Long-term debt...............................................................................
Bonds payable less debt issuance costs..........................................
Other long-term liabilities..............................................................
Deferred income taxes....................................................................
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares
authorized, none issued........................................................
Common stock, $.20 par value, 175,000,000 shares
authorized, 52,880,134 shares issued...................................
Capital in excess of par value...................................................
Accumulated other comprehensive income.............................
26,165
7,763
657
47,709
—
178,000
642,276
11,257
1,480
—
10,280
535,815
—
Retained earnings.....................................................................
799,402
Total shareholders’ equity attributable to Unit
Corporation..............................................................
1,345,497
Non-controlling interests in consolidated subsidiaries.............
—
Total shareholders' equity.............................................
1,345,497
19,134
—
8,501
115,149
870,582
—
—
77,566
85,443
—
—
45,921
63
928,552
974,536
—
974,536
3,224
—
3,844
26,056
—
—
—
48,523
7,763
13,002
(6,978)
181,936
285,143
(1,155,725)
—
—
—
—
—
—
(61,470)
—
—
178,000
642,276
100,203
133,477
—
10,280
535,815
63
—
—
11,380
46,554
—
—
15,549
—
54,687
(983,239)
799,402
70,236
(1,044,709)
1,345,560
—
—
—
70,236
(1,044,709)
1,345,560
Total liabilities and shareholders’ equity........................................ $
2,226,219
$
2,123,276
$
439,369
$
(2,207,412) $
2,581,452
Condensed Consolidating Statements of Operations
Year Ended December 31, 2018
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Revenues........................................................................................ $
— $
642,041
$
312,417
$
(111,177) $
843,281
Expenses:
Operating costs.........................................................................
Depreciation, depletion, and amortization...............................
Impairments..............................................................................
General and administrative.......................................................
Gain on disposition of assets....................................................
Total operating expenses....................................................
Income (loss) from operations........................................................
Interest, net...............................................................................
Loss on derivatives...................................................................
Other.........................................................................................
Income (loss) before income taxes.................................................
Income tax expense (benefit).........................................................
Equity in net earnings from investment in subsidiaries, net of
taxes...........................................................................................
Net loss...........................................................................................
Less: net income attributable to non-controlling interest.........
—
7,679
—
—
(30)
7,649
(7,649)
(32,280)
(3,184)
22
(43,091)
(12,707)
(14,904)
(45,288)
—
287,704
191,092
147,884
36,083
(564)
662,199
(20,158)
—
—
—
(20,158)
(3,319)
—
(16,839)
—
251,328
44,834
—
2,624
(110)
298,676
13,741
(1,214)
—
—
12,527
2,030
—
10,497
5,521
(108,136)
—
—
—
—
(108,136)
(3,041)
—
—
—
(3,041)
—
14,904
11,863
—
430,896
243,605
147,884
38,707
(704)
860,388
(17,107)
(33,494)
(3,184)
22
(53,763)
(13,996)
—
(39,767)
5,521
Net loss attributable to Unit Corporation....................................... $
(45,288) $
(16,839) $
4,976
$
11,863
$
(45,288)
122
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Year Ended December 31, 2017
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Revenues........................................................................................ $
— $
545,916
$
277,049
$
(83,325) $
739,640
Expenses:
Operating costs.........................................................................
Depreciation, depletion, and amortization...............................
General and administrative.......................................................
(Gain) loss on disposition of assets..........................................
Total operating expenses....................................................
Income (loss) from operations........................................................
Interest, net...............................................................................
Gain on derivatives...................................................................
Other.........................................................................................
Income (loss) before income taxes.................................................
Income tax benefit..........................................................................
Equity in net earnings from investment in subsidiaries, net of
taxes...........................................................................................
Net income.....................................................................................
Less: net income attributable to non-controlling interest.........
—
7,477
—
(850)
6,627
(6,627)
(37,645)
14,732
21
(29,519)
(12,599)
134,768
117,848
—
269,964
158,281
29,440
548
458,233
87,683
—
—
—
87,683
(20,881)
—
108,564
—
220,613
43,499
8,647
(25)
272,734
4,315
(689)
—
—
3,626
(24,198)
—
27,824
—
(81,705)
—
—
—
(81,705)
(1,620)
—
—
—
(1,620)
—
(134,768)
(136,388)
—
408,872
209,257
38,087
(327)
655,889
83,751
(38,334)
14,732
21
60,170
(57,678)
—
117,848
—
Net income attributable to Unit Corporation.................................. $
117,848
$
108,564
$
27,824
$
(136,388) $
117,848
Year Ended December 31, 2016
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Revenues........................................................................................ $
— $
416,307
$
237,785
$
(51,915) $
602,177
Expenses:
Operating costs.........................................................................
Depreciation, depletion, and amortization...............................
Impairments..............................................................................
General and administrative.......................................................
(Gain) loss on disposition of assets..........................................
Total operating expenses.................................................
Income (loss) from operations........................................................
Interest, net...............................................................................
Loss on derivatives...................................................................
Other.........................................................................................
Income (loss) before income taxes.................................................
Income tax expense (benefit).........................................................
Equity in net earnings from investment in subsidiaries, net of
taxes...........................................................................................
Net loss...........................................................................................
Less: net income attributable to non-controlling interest.........
—
1,835
—
—
18
1,853
(1,853)
(38,995)
(22,813)
—
(63,661)
(24,031)
(95,994)
(135,624)
—
214,892
160,803
161,563
26,158
(2,860)
560,556
(144,249)
—
—
307
(143,942)
(48,654)
—
(95,288)
—
182,970
45,715
—
7,179
302
(51,915)
—
—
—
—
236,166
(51,915)
1,619
(834)
—
—
785
1,491
—
(706)
—
—
—
—
—
—
—
95,994
95,994
—
345,947
208,353
161,563
33,337
(2,540)
746,660
(144,483)
(39,829)
(22,813)
307
(206,818)
(71,194)
—
(135,624)
—
Net loss attributable to Unit Corporation....................................... $
(135,624) $
(95,288) $
(706) $
95,994
$
(135,624)
123
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year Ended December 31, 2018
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Net loss........................................................................................... $
(45,288) $
(16,839) $
10,497
$
11,863
$
(39,767)
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax (($181)).....................
—
Comprehensive loss........................................................................
(45,288)
(557)
(17,396)
Less: Comprehensive income attributable to non-
controlling interests..............................................................
—
—
—
10,497
5,521
—
11,863
(557)
(40,324)
—
5,521
Comprehensive loss attributable to Unit Corporation.................... $
(45,288) $
(17,396) $
4,976
$
11,863
$
(45,845)
Year Ended December 31, 2017
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Net income..................................................................................... $
117,848
$
108,564
$
27,824
$
(136,388) $
117,848
Other comprehensive income, net of taxes:
Unrealized gain on securities, net of tax ($39).........................
—
Comprehensive income..................................................................
117,848
63
108,627
Less: Comprehensive income attributable to non-
controlling interests..............................................................
—
—
—
27,824
—
—
63
(136,388)
117,911
—
—
Comprehensive income attributable to Unit Corporation.............. $
117,848
$
108,627
$
27,824
$
(136,388) $
117,911
Year Ended December 31, 2016
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
Net loss........................................................................................... $
(135,624) $
(95,288) $
(706) $
95,994
$
(135,624)
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax ($0)...........................
—
—
Comprehensive loss........................................................................
(135,624)
(95,288)
Less: Comprehensive income attributable to non-
controlling interests..............................................................
—
—
—
(706)
—
—
95,994
—
—
(135,624)
—
Comprehensive loss attributable to Unit Corporation.................... $
(135,624) $
(95,288) $
(706) $
95,994
$
(135,624)
124
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2018
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities..... $
(120,317) $
327,075
$
12,129
$
128,872
$
347,759
INVESTING ACTIVITIES:
Capital expenditures.................................................................
Producing properties and other acquisitions............................
Proceeds from disposition of property and equipment.............
Net cash provided by (used in) investing activities......
236
—
30
266
FINANCING ACTIVITIES:
Borrowings under credit agreements........................................
97,100
Payments under credit agreements...........................................
(275,100)
(400,990)
(29,970)
25,777
(405,183)
—
—
Intercompany borrowings (advances), net...............................
204,809
78,125
Payments on capitalized leases................................................
—
Proceeds from investments of non-controlling interest............
102,958
Contributions from Unit...........................................................
—
Transaction costs associated with sale of non-controlling
interest..................................................................................
Book overdrafts........................................................................
(2,503)
(7,320)
—
—
—
—
—
Net cash provided by financing activities....................
119,944
78,125
Net increase in cash and cash equivalents......................................
Cash and cash equivalents, beginning of period............................
Cash and cash equivalents, end of period...................................... $
(107)
510
403
$
17
191
208
(45,528)
—
103
(45,425)
2,000
(2,000)
(154,854)
(3,843)
197,042
792
—
—
39,137
5,841
—
—
—
—
—
—
—
(128,080)
—
—
(792)
—
—
(446,282)
(29,970)
25,910
(450,342)
99,100
(277,100)
—
(3,843)
300,000
—
(2,503)
(7,320)
(128,872)
108,334
5,751
701
6,452
$
5,841
$
— $
Year Ended December 31, 2017
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities..... $
(1,683) $
224,446
$
43,193
$
— $
265,956
INVESTING ACTIVITIES:
Capital expenditures.................................................................
(3,594)
Producing properties and other acquisitions............................
Proceeds from disposition of property and equipment.............
Other.........................................................................................
—
964
—
(233,254)
(58,026)
20,674
(1,500)
(18,705)
—
75
—
Net cash used in investing activities............................
(2,630)
(272,106)
(18,630)
FINANCING ACTIVITIES:
Borrowings under credit agreement.........................................
Payments under credit agreement.............................................
Intercompany borrowings (advances), net...............................
Payments on capitalized leases................................................
Proceeds from common stock issued, net of issue costs..........
Book overdrafts........................................................................
Net cash provided by (used in) financing activities.....
343,900
(326,700)
(26,606)
—
18,623
(4,911)
4,306
—
—
47,475
—
—
—
—
—
(20,869)
(3,694)
—
—
47,475
(24,563)
Net increase in cash and cash equivalents......................................
Cash and cash equivalents, beginning of period............................
Cash and cash equivalents, end of period...................................... $
(7)
517
510
$
(185)
376
191
125
—
—
$
— $
— $
(255,553)
(58,026)
21,713
(1,500)
(293,366)
343,900
(326,700)
—
(3,694)
18,623
(4,911)
27,218
(192)
893
701
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Year Ended December 31, 2016
Parent
Combined
Guarantor
Subsidiaries
Combined
Non-
Guarantor
Subsidiaries
(In thousands)
Consolidating
Adjustments
Total
Consolidated
OPERATING ACTIVITIES:
Net cash provided by operating activities.................... $
1,781
$
197,132
$
41,217
$
— $
240,130
INVESTING ACTIVITIES:
Capital expenditures.................................................................
(3,927)
(158,983)
(23,239)
Producing properties and other acquisitions............................
Proceeds from disposition of property and equipment.............
Other.........................................................................................
—
13
750
Net cash provided by (used in) investing activities......
(3,164)
FINANCING ACTIVITIES:
Borrowings under credit agreement.........................................
251,398
Payments under credit agreement.............................................
(371,600)
(564)
74,694
—
(84,853)
—
—
Intercompany borrowings (advances), net...............................
126,797
(112,228)
—
116
169
(22,954)
—
—
(14,569)
(3,694)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(186,149)
(564)
74,823
919
(110,971)
251,398
(371,600)
—
(3,694)
(376)
(4,829)
(129,101)
58
835
893
—
—
—
51
325
376
(112,228)
(18,263)
$
— $
— $
Payments on capitalized leases................................................
Tax expense from stock compensation.....................................
Book overdrafts........................................................................
Net cash used in financing activities............................
Net increase in cash and cash equivalents......................................
Cash and cash equivalents, beginning of period............................
Cash and cash equivalents, end of period...................................... $
—
(376)
(4,829)
1,390
7
510
517
$
126
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
Our oil and gas operations are substantially located in the United States. The capitalized costs at year end and costs
incurred during the year were as follows:
2018
2017
(In thousands)
2016
Capitalized costs:
Proved properties................................................................................................. $
6,018,568
$
5,712,813
$
5,446,305
Unproved properties.............................................................................................
330,216
6,348,784
296,764
6,009,577
314,867
5,761,172
Accumulated depreciation, depletion, amortization, and impairment.................
(5,124,257)
(4,996,696)
(4,900,304)
Net capitalized costs..................................................................................... $
1,224,527
$
1,012,881
$
860,868
Cost incurred:
Unproved properties acquired.............................................................................. $
57,430
$
47,029
$
Proved properties acquired...................................................................................
Exploration...........................................................................................................
Development........................................................................................................
Asset retirement obligation..................................................................................
15,158
15,907
280,692
(7,629)
47,638
14,811
160,941
(3,613)
Total costs incurred...................................................................................... $
361,558
$
266,806
$
21,675
564
17,325
80,582
(30,906)
89,240
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2018,
by the year in which such costs were incurred:
Unproved properties acquired and wells in
progress....................................................... $
60,372
$
46,986
$
21,947
$
200,911
$
330,216
2018
2017
2016
(In thousands)
2015 and Prior
Total
Unproved properties not subject to amortization relates to properties which are not individually significant and consist
primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and
therefore, the company is unable to estimate when these costs will be included in the amortization calculation.
The results of operations for producing activities are as follows:
2018
2017
(In thousands)
2016
Revenues...................................................................................................................... $
429,119
$
347,285
$
282,742
Production costs...........................................................................................................
Depreciation, depletion, amortization, and impairment...............................................
Income tax (expense) benefit.......................................................................................
(131,328)
(132,923)
164,868
(42,915)
(113,344)
(101,326)
132,615
(52,078)
(103,568)
(274,155)
(94,981)
32,696
Results of operations for producing activities (excluding corporate overhead and
financing costs)........................................................................................................ $
121,953
$
80,537
$
(62,285)
127
Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved
developed and undeveloped oil, NGLs, and natural gas reserves were as follows:
Oil
Bbls
NGLs
Bbls
Natural Gas
Mcf
Total
MBoe
(In thousands)
2016
Proved developed and undeveloped reserves:
Beginning of year.........................................................................................
Revision of previous estimates (1).........................................................................
Extensions and discoveries..........................................................................
Infill reserves in existing proved fields........................................................
Purchases of minerals in place.....................................................................
Production....................................................................................................
Sales.............................................................................................................
End of year...................................................................................................
Proved developed reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
Proved undeveloped reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
2017
Proved developed and undeveloped reserves:
Beginning of year.........................................................................................
Revision of previous estimates (1).........................................................................
Extensions and discoveries..........................................................................
Infill reserves in existing proved fields........................................................
Purchases of minerals in place.....................................................................
Production....................................................................................................
Sales.............................................................................................................
End of year...................................................................................................
Proved developed reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
Proved undeveloped reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
2018
Proved developed and undeveloped reserves:
Beginning of year.........................................................................................
Revision of previous estimates....................................................................
Extensions and discoveries..........................................................................
Infill reserves in existing proved fields........................................................
Purchases of minerals in place.....................................................................
Production....................................................................................................
Sales.............................................................................................................
End of year...................................................................................................
Proved developed reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
Proved undeveloped reserves:
Beginning of year.........................................................................................
End of year...................................................................................................
16,735
(549)
1,816
663
114
(2,974)
(109)
15,696
14,679
12,724
2,056
2,972
15,696
730
2,235
1,632
2,019
(2,715)
(84)
19,513
12,724
14,862
2,972
4,651
19,513
180
3,250
1,898
701
(2,874)
(110)
22,558
14,862
15,192
4,651
7,366
_________________________
1.
Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.
37,687
(2,473)
1,588
2,724
43
(5,014)
(73)
34,482
31,218
28,502
6,469
5,980
34,482
4,325
4,520
5,779
1,197
(4,737)
(80)
45,486
28,502
33,358
5,980
12,128
45,486
(1,368)
5,149
2,795
856
(4,925)
(197)
47,796
33,358
33,515
12,128
14,281
484,868
(31,670)
13,720
24,704
630
(55,735)
(30,938)
405,579
416,395
347,121
68,473
58,458
405,579
38,330
49,321
52,270
15,313
(51,260)
(903)
508,650
347,121
388,446
58,458
120,204
508,650
(17,859)
75,806
23,778
6,897
(55,627)
(5,682)
535,963
388,446
377,216
120,204
158,747
135,233
(8,300)
5,690
7,504
262
(17,277)
(5,338)
117,774
115,296
99,079
19,937
18,695
117,774
11,444
14,975
16,123
5,768
(15,996)
(314)
149,774
99,079
112,961
18,695
36,813
149,774
(4,165)
21,033
8,656
2,707
(17,070)
(1,254)
159,681
112,961
111,576
36,813
48,105
128
Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning
monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the
uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production
and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is,
therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural
gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have
been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of
estimated future cash flows.
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and
year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future
income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:
2018
2017
(In thousands)
2016
Future cash flows......................................................................................................... $
3,980,369
$
3,347,396
$
2,030,925
Future production costs................................................................................................
(1,479,744)
(1,308,244)
Future development costs.............................................................................................
Future income tax expenses.........................................................................................
(442,984)
(307,916)
(369,560)
(234,152)
Future net cash flows...................................................................................................
1,749,725
1,435,440
10% annual discount for estimated timing of cash flows............................................
(766,047)
(628,270)
(861,625)
(173,446)
(141,752)
854,102
(335,892)
Standardized measure of discounted future net cash flows relating to proved oil,
NGLs, and natural gas reserves................................................................................ $
983,678
$
807,170
$
518,210
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
2018
2017
(In thousands)
2016
Sales and transfers of oil and natural gas produced, net of production costs............... $
(297,791) $
(239,953) $
(173,920)
Net changes in prices and production costs.................................................................
Revisions in quantity estimates and changes in production timing.............................
Extensions, discoveries, and improved recovery, less related costs.............................
Changes in estimated future development costs..........................................................
Previously estimated cost incurred during the period..................................................
Purchases of minerals in place.....................................................................................
Sales of minerals in place.............................................................................................
Accretion of discount...................................................................................................
Net change in income taxes..........................................................................................
Other—net....................................................................................................................
Net change....................................................................................................................
Beginning of year.........................................................................................................
120,062
(33,282)
234,172
19,535
63,557
23,416
(5,004)
89,753
(31,674)
(6,236)
176,508
807,170
236,126
87,239
102,965
(5,194)
36,044
51,686
(1,447)
57,517
(33,389)
(2,634)
288,960
518,210
End of year................................................................................................................... $
983,678
$
807,170
$
(94,026)
(51,979)
84,738
70,976
16,602
2,652
(17,248)
69,069
44,241
(22,381)
(71,276)
589,486
518,210
Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed
below. We believe this information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived
from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does
not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining
present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the
future, variations from the expected production rate could result from factors outside of our control, such as unintentional
delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes
that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the
amount of cash eventually realized.
129
The December 31, 2018, future cash flows were computed by applying the unescalated 12-month average prices of
$65.56 per barrel for oil, $37.68 per barrel for NGLs, and $3.10 per Mcf for natural gas (then adjusted for price differentials)
relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the
extent provided by contractual arrangements in existence at year-end.
ff
Future production and development costs are computed by estimating the expenditures to be incurred in developing and
producing the proved oil, NGLs, and natural gas reserves at the end of the year, brr
conditions.
ased on continuation of existing economic
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net
cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax
expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural
gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years,
the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to
occur.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), does not expect that
our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934,
as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (as defined in Rules 13a -
15(f) and 15d - 15(f) of the Exchange Act) (ICFR) will prevent or detect all errors and all fraud. A control system, no matter
how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system
are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of
controls can provide absolute assurance that all control issues and instances of fraud, if any, wyy
detected. These inherent limitations include the realities that judgments in decision-making can be faulty, ayy nd that breakdowns
can occur because of a simple error or mistake. Additionally, cyy ontrols can be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls
also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will
succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective
control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and
ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified
as systems change, and conditions warrant.
ithin the company have been
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the
participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our
Disclosure Controls under the Exchange Act in providing reasonable assurance that the information required to be disclosed in
the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported, within the time
periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management,
including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
r
Based on that evaluation, our CEO and CFO concluded that our Disclosure Controls were not effective as of December
31, 2018 due to a material weakness in ICFR that was identified during the second quarter of 2018 as described below.
Notwithstanding the material weakness, management has concluded that our consolidated financial statements included in
this Form 10-K are fairly stated in all material respects in accordance with generally accepted accounting principles in the
United States of America for each of the periods presented.
130
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as
defined in Exchange Act Rule 13a-15(f). Our management, including our CEO and CFO, conducted an evaluation of the
effectiveness of our internal control over financial reporting based on the Internal Control—Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this
evaluation, our management concluded that our internal control over financial reporting was not effective as of December 31,
2018 due to the material weakness discussed below.
A material weakness is a deficiency, or c
yy
ombination of deficiencies, in ICFR, such that there is a reasonable possibility
that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a
timely basis.
We did not design and maintain effective controls to verify the proper presentation and disclosure of the interim and
annual consolidated financial statements. Specifically, our controls were not sufficiently precise to allow for the effective
review of the underlying information used in the preparation of the consolidated financial statements, nor verify that
transactions were appropriately presented. The material weakness resulted in the revision of the Company's consolidated
financial statements as of and for the year ended December 31, 2017, the restatement of the Company’s condensed consolidated
financial statements for the quarter ended March 31, 2018 and immaterial adjustments related to the classification of accounts
receivable and accounts payable for the quarters ended June 30, 2018 and September 30, 2018. This material weakness could
result in a material misstatement of the annual or interim consolidated financial statements or disclosures that would not be
prevented or detected.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2018, has been audited by
PricewaterhouseCoopers LLP, an i
Item 8.
PP
ndependent registered public accounting firm, as stated in their report which appears under
Plan for Remediation of Material Weakness in Internal Control Over Financial Reporting
Since the second quarter of 2018, management has dedicated significant time and resources that we believe will address
the underlying cause of the material weakness, including:
•
•
•
•
•
engaged a consultant specializing in internal controls to assist with the remediation efforts;
recruited, added, and trained an additional staff pff
osition in the financial reporting department;
redesigned and enhanced controls related to the preparation and review of the consolidated financial statements;
provided additional training to financial reporting personnel with respect to the preparation and review of the
consolidated financial statements;
recruiting an additional staff pff
osition specifically over compliance of internal controls; and
Management believes the measures described above will remediate the material weakness that we have identified. This
material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of
time. As management continues to evaluate and improve internal control over financial reporting, we may decide to take
additional measures to address this control deficiency or determine to modify certain of the remediation measures.
Changes in Internal Control Over Financial Reporting
There were no other changes in our ICFR, as defined in Rule 13a – 15(f) under the Exchange Act, during the quarter
ended December 31, 2018, that materially affected our ICFR or are reasonably likely to materially affect it.
Item 9B. Other Information
None.
131
Item 10. Directors, Executive Officers, and Corporate Governance
PART III
In accordance with Instruction G(3) of Form 10-K, the information required by this item is incorporated in this report by
reference to the Proxy Statement, except for the information regarding our executive officers which is presented below. The
Proxy Statement will be filed before our annual shareholders’ meeting scheduled to be held on May 1, 2019.
Our Code of Ethics and Business Conduct applies to all directors, officers, and employees, including our Chief Executive
Officer, our Chief Financial Officer, and our Controller. You can find our Code of Ethics and Business Conduct on our internet
website, www.unitcorp.com. We will post any amendments to the Code of Ethics and Business Conduct, and any waivers that
are required to be disclosed by the rules of either the SEC or the NYSE, on our internet website.
Because our common stock is listed on the NYSE, our Chief Executive Officer was required to make, and he has made,
an annual certification to the NYSE stating that he was not aware of any violation by us of the NYSE corporate governance
listing standards. Our Chief Executive Officer made his annual certification to that effect to the NYSE as of May 7, 2018. In
addition, we have filed, as exhibits to this Annual Report on Form 10-K, the certifications of our Chief Executive Officer and
Chief Financial Officer required under Section 302 of the Sarbanes-Oxley Act of 2002 to be filed with the SEC regarding the
quality of our public disclosure.
Executive Officers
The table below and accompanying text sets forth certain information as of February 12, 2019 concerning each of our
executive officers and certain officers of our subsidiaries. There were no arrangements or understandings between any of the
officers and any other person(s) under which the officers were elected.
NAME
Larry D. Pinkston.....
Mark E. Schell.........
David T. Merrill.......
AGE
POSITION HELD
64 Chief Executive Officer since April 1, 2005, Director since January 15, 2004, President since August 1,
2003, Chief Operating Officer from February 24, 2004 to August 28, 2017, Vice President and Chief
Financial Officer from May 1989 to February 24, 2004
61
Senior Vice President since December 2002, General Counsel and Corporate Secretary since January 1987
58 Chief Operating Officer since August 28, 2017, Senior Vice President from May 2, 2012 to November 27,
2017, Chief Financial Officer and Treasurer from February 24, 2004 to November 27, 2017, Vice
President of Finance from August 2003 to February 24, 2004
Les Austin................
David P. Dunham.....
53
39
Senior Vice President and Chief Financial Officer since November 27, 2017
Senior Vice President of Business Development since August 28, 2017, Vice President of Corporate
Planning from January 2012 to August 28, 2017, Director of Corporate Planning from November 2007 to
January 2012
John Cromling..........
Robert Parks.............
Frank Young.............
71 Executive Vice President, Unit Drilling Company since April 15, 2005
64 Manager and President, Superior Pipeline Company, L.L.C. since June 1996
49
Senior Vice President Exploration and Production Midcontinent of Unit Petroleum Company since 2012,
Vice President - Central Division from June 2007, when he joined Unit Company, until 2012.
Mr. Pinkston joined the company in December 1981. He had served as Corporate Budget Director and Assistant
Controller before being appointed Controller in February, 1985. In December, 1986 he was elected Treasurer of the company
and was elected to the position of Vice President and Chief Financial Officer in May, 1989. In August, 2003, he was elected to
the position of President. He was elected a director of the company by the Board in January, 2004. In February, 2004, in
addition to his position as President, he was elected to the office of Chief Operating Officer and held this position until August
2017. In April 2005, he also began serving as Chief Executive Officer. Mr. Pinkston holds the offices of President and Chief
Executive Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma.
Mr. Schell joined the company in January 1987, as its Secretary and General Counsel. In 2003, he was promoted to Senior
Vice President. From 1979 until joining Unit Corporation, Mr. Schell was Counsel, Vice President, and a member of the Board
of Directors of C & S Exploration Inc. He received a Bachelor of Science degree in Political Science from Arizona State
University and his Juris Doctorate degree from the University of Tulsa College of Law. He is a member of the Oklahoma Bar
Association. He is also a member of the State Chamber of Oklahoma board of directors and serves on the board of advisors for
the Greater Oklahoma City Chamber.
132
errill
MM
Mr. Mrr
joined the company in August 2003 and served as its Vice President of Finance until February 2004 when he
was elected to the position of Chief Financial Officer and Treasurer. In May 2012, he was promoted to Senior Vice President, a
position he held until November 2017. In August 2017, he was promoted to Chief Operating Officer. From May 1999 through
August 2003, Mr. Merrill served as Senior Vice President, Finance with TV Guide Networks, Inc. From July 1996 through May
1999 he was a Senior Manager with Deloitte & Touche LLP
Reporting and Special Projects for MAPCO, Inc. He began his career as an auditor with Deloitte, Haskins & Sells in 1983.
Mr. Merrill received a Bachelor of Business Administration Degree in Accounting from the University of Oklahoma and is a
Certified Public Accountant.
. FPP rom July 1994 through July 1996 he was Director of Financial
TT
Mr. Arr ustin joined the company in November 2017 as Senior Vice President and Chief Financial Officer of the company.
Prior to coming to Unit, he served as Senior Vice President and Chief Financial Officer of Cypress Energy Partners, L.P.. From
2008 to 2011, he was the Senior Vice President and Chief Financial Officer of Ram Energy Resources, Inc. In 2011, he was
promoted to Chief Operating Officer where he served until its sale in 2012. Before joining Ram Energy Resources, Inc., Mr.
Austin was the Vice President of Finance and Chief Financial Officer of Matrix Service Company. He has also held various
managerial and financial positions at Flint Energy Construction Co. and Ernst & Young, LLP
degree in accounting from Oklahoma State University and is a Certified Public Accountant.
r. Austin has a bachelor's
. MPP
YY
Mr. Drr
unham joined the company in November 2007 as its Director of Corporate Planning. He was promoted to Vice
President of Corporate Planning in January 2012. In August 2017, he was promoted to Senior Vice President of Business
unham worked for Williams Power, serving as Manager of Structured
Development. From 2004 to November 2007, Mr. Dr
Products. He worked for Leggett & Platt from 2003 to 2004, serving as a Mergers & Acquisitions Analyst. He received his
Bachelor of Arts degree in Psychology from Northwestern University, hyy is Master of Science in Finance degree from the
University of Tulsa, and his MBA from the Wharton School of the University of Pennsylvania.
Mr. Crr
roCC mling joined Unit Drilling Company in 1997 as a Vice-President and Division Manager
VV
. Irr n April 2005, he was
promoted to the position of Executive Vice-President of Drilling for Unit Drilling Company. In 1
980, he formed Cromling
Drilling Company which managed and operated drilling rigs until 1987. From 1987 to 1997, Cromling Drilling Company
provided engineering consulting services and generated and drilled oil and natural gas prospects. Prior to this, he was employed
by Big Chief Drilling for 11 years and served as Vice-President. Mr. Cromling graduated from the University of Oklahoma with
a degree in Petroleum Engineering.
yy
Mr. Prr
arks founded Superior Pipeline Company, Lyy
.L.C. in 1996. When Superior was acquired by the company in July
2004, he continued with Superior as one of its managers and as its President. From April 1992 through April 1996 Mr. Parks
served as Vice-President—Gathering and Processing for Cimarron Gas Companies. From December 1986 through March 1992,
he served as Vice-President—Business Development for American Central Gas Companies. Mr. Prr
engineer with Cities Service Company in 1978. He received a Bachelor of Science degree in Chemical Engineering from Rice
University and his M.B.A. from the University of Texas at Austin.
arks began his career as an
YY
Mr. Yrr oung
joined Unit Petroleum Company in June 2007 as Vice President - Central Division. In 2012, he was promoted
to Senior Vice President of Exploration and Production over Unit’s Midcontinent assets and, in 2017, to Executive Vice
President of Exploration and Production over Unit Petroleum Company. Byy
Anadarko Petroleum Corporation. He began his career with Anadarko in 1991 as a Production Engineer and, in 1994, began
working as a Reservoir Engineer. In 1
development of Anadarko’s North African oil fields. In 1999, he was moved into a Senior Completions / Operations
Engineering role responsible for development of gas fields in East Texas. In 2000, he was promoted to Division Engineer
responsible for operations within Anadarko’s Permian Division in West Texas. In 2002, he was promoted to Planning Manager
for North America. In 2004, he was promoted to General Manager of Central Gulf of Mexico responsible for delineation and
development of various Deepwater fields. Mr. Yrr
YY
Tech University and a Master of Business Administration degree from Texas A&M University.
996, he was promoted to a Senior Asset Engineering role responsible for delineation and
a Bachelor of Science degree in Petroleum Engineering from Texas
YY
efore joining Unit, Mr. Young was employed by
oung holds
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Item 11. Executive Compensation
In accordance with Instruction G(3) of Form 10-K, the information required by this Item is incorporated into this report
by reference to the Proxy Statement (see Item 10 above).
133
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table provides information for all equity compensation plans as of the fiscal year ended December 31,
2018, under which our equity securities were authorized for issuance:
Number of
Securities to be
Issued Upon
Exercise of
Outstanding
Options,
Warrants and
Rights
(a)
Weighted Average
Exercise Price of
Outstanding
Options,
Warrants and
Rights
(b)
Number of
Securities
Remaining
Available for
Future Issuance
Under Equity
Compensation
Plans (Excluding
Securities Reflected
in Column (a)) (c)
66,500 (2) $
—
66,500
$
44.42
—
44.42
2,953,686 (3)
—
2,953,686
Plan Category
Equity compensation plans approved by security holders (1)..
Equity compensation plans not approved by security
holders.................................................................................
Total........................................................................................
_________________________
1.
Shares awarded under all above plans may be newly issued, from our treasury, or acquired in the open market.
2.
3.
This number includes 66,500 stock options outstanding under the Non-Employee Directors’ Stock Option Plan.
This number reflects the shares available for issuance under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan
effective May 6, 2015 (the amended plan). The amended plan allows us to grant stock-based compensation to our employees and non-employee directors.
A total of 7,230,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan. No more than
2,000,000 of the shares available under the amended plan may be issued as “incentive stock options” and all of the shares available under this plan may be
issued as restricted stock. In addition, shares related to grants that are forfeited, terminated, canceled, expire unexercised, or settled in such manner that all
or some of the shares are not issued to a participant shall immediately become available for issuance.
In accordance with Instruction G(3) of Form 10-K, the information required by this Item is incorporated into this report
by reference to the Proxy Statement (see Item 10 above).
Item 13. Certain Relationships and Related Transactions, and Director Independence
In accordance with Instruction G(3) of Form 10-K, the information required by this Item is incorporated into this report
by reference to the Proxy Statement (see Item 10 above).
Item 14. Principal Accounting Fees and Services
In accordance with Instruction G(3) of Form 10-K, the information required by this Item is incorporated into this report
by reference to the Proxy Statement (see Item 10 above).
134
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
Included in Part II of this report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the years ended December 31, 2018, 2017, and 2016
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2018, 2017, and 2016
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2016, 2017, and 2018
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017, and 2016
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Included in Part IV of this report for the years ended December 31, 2018, 2017, and 2016:
Schedule II—Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or notes thereto.
3. Exhibits:
The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of
a
Item 601 of Regulation S-K.
3.1
3.1.1
3.2
4.1
4.2
4.3
4.4
10.1
10.2
Restated Certificate of Incorporation of Unit Corporation (incorporated by reference to Exhibit 3.1 of Unit's Form 8-K, dated
June 29, 2000).
Certificate of Amendment of Amended and Restated Certificate of Incorporation of the Company (filed as Exhibit 3.1 to
Unit’s Form 8-K, dated May 9, 2006 which is incorporated herein by reference).
By-laws of Unit Corporation, as amended and restated on June 17, 2014 (filed as Exhibit 3.3 to our Registration Statement on
Form S-3 (File No. 333-202956), and incorporated by reference herein).
Form of Common Stock Certificate (filed as Exhibit 4.1 to Unit’s Form S-3 (File No. 333-83551), which is incorporated
herein by reference).
Indenture dated as of May 18, 2011, by and between the Company and Wilmington Trust FSB, as trustee (filed as Exhibit 4.1
to Unit’s Form 8-K dated May 18, 2011, which is incorporated herein by reference).
rr
First Supplemental Indenture (including form of note) dated as of May 18, 2011, by and among the Company, as i
ssuer, the
Subsidiary Guarantors (as defined therein), as guarantors and Wilmington Trust FSB as trustee (filed as Exhibit 4.2 to Unit’s
Form 8-K dated May 18, 2011, which is incorporated herein by reference).
yy
rr
Second Supplemental Indenture (including form of note) dated as of January 7, 2013, by and among the Registrant, as issuer,
the Subsidiary Guarantors (as defined therein), as guarantors and Wilmington Trust, National Association as trustee (filed as
Exhibit 4.10 to Unit’s Post-Effective Amendment No.1 to the Registration Statement on Form S-3 dated February 16, 2016,
which is incorporated herein by reference).
rr
Amended and Restated Key Employee Change of Control Contract dated August 19, 2008 (filed as Exhibit 10.1 to Unit’s
Form 8-K dated August 25, 2008, which is incorporated herein by reference).
Senior Credit Agreement dated September 13, 2011 by and among the Company and the subsidiaries named therein (as
borrowers), BOKF, NA DBA Bank of Oklahoma, as Administrative Agent, and the institutions named therein (as lenders)
(filed as Exhibit 10.1 to Unit’s Form 8-K dated September 13, 2011, which is incorporated herein by reference).
135
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
First Amendment and Consent, dated September 5, 2012, to the Senior Credit Agreement by and among the Company and the
subsidiaries named therein (as borrowers), BOKF, NFF A DBA Bank of Oklahoma, as Administrative Agent, and the institutions
named therein (as lenders) (filed as exhibit 10.1 to Unit's Form 8-K dated September 5, 2012, which is incorporated herein by
reference).
Second Amendment and Consent, dated April 10, 2015, to the Senior Credit Agreement by and among the Company and the
subsidiaries named therein (as borrowers), BOKF, NFF A DBA Bank of Oklahoma, as Administrative Agent, and the institutions
named therein (as lenders) (filed as exhibit 10.1 to Unit's Form 8-K dated April 10, 2015, which is incorporated herein by
reference).
Third Amendment and Consent, dated April 8, 2016, to the Senior Credit Agreement by and among the Company and the
subsidiaries named therein (as borrowers), BOKF, NFF A DBA Bank of Oklahoma, as Administrative Agent, and the institutions
named therein (as lenders) (filed as exhibit 10.1 to Unit's Form 8-K dated April 8, 2016, which is incorporated herein by
reference).
Fourth Amendment, dated April 2, 2018, to the Senior Credit Agreement by and among the Company and the subsidiaries
named therein (as borrowers), BOKF, NA DBA Bank of Oklahoma, as Administrative Agent, and the institutions named
therein (as lenders) (filed as exhibit 10.1 to Unit’s Form 8-K dated April 6, 2018, which is incorporated herein by reference).
Fifth Amendment, dated October 18, 2018, to the Senior Credit Agreement by and among the Company and the subsidiaries
named therein (as borrowers), BOKF, NA DBA Bank of Oklahoma, as Administrative Agent, and the institutions named
therein (as lenders) (filed as exhibit 10.1 to Unit’s Form 10-Q dated November 6, 2018, which is incorporated herein by
reference).
Credit Agreement dated May 10, 2018, by and among Superior Pipeline Company, Lyy
Oklahoma, as Administrative Agent, and the institutions named therein (as lenders) (filed as Exhibit 10.1 to Unit’s Form 8-K
dated May 16, 2018, which is incorporated herein by reference).
.L.C. and BOKF, NA DBA Bank of
Gas Purchase Agreement dated November 21, 2011 by and between Superior Pipeline Company, Lyy
Company, Lyy
reference).
.L.C. (filed as Exhibit 10.1 to Unit’s Form 8-K dated November 21, 2011, which is incorporated herein by
.L.C. and Sullivan and
Unit Corporation Employees’ Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated
herein by reference).
Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan dated May 6, 2015 (filed as Exhibit
10 to Unit's Form 8-K dated May 8, 2015, which is incorporated herein by reference).
Amendment Number 1 to the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan (filed
as Exhibit 10.1 to Unit's Form 8-K dated May 4, 2017, which is incorporated herein by reference).
Unit Corporation Salary Deferral Plan (filed as an Exhibit to Unit’s Annual Report under cover of Form 10-K for the year
ended December 31, 1993, which is incorporated herein by reference).
Annual Bonus Performance Plan entered into October 21, 2008 (filed as Exhibit 10.1 to Unit’s Form 8-K dated October 23,
2008, which is incorporated herein by reference).
Form of Indemnification Agreement entered into between the Company and its executive officers and directors (filed as an
Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 2016).
Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan as Amended and Restated August 25, 2004 (as amended
on May 29, 2009 and filed as Exhibit 10.1 to Unit’s Form 8-K dated May 29, 2009, which is incorporated herein by
reference).
Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan as Amended and Restated August 25, 2004 (as amended
on May 29, 2009 and filed as Exhibit 10.1 to Unit’s Form 8-K dated May 29, 2009, which is incorporated herein by
reference).
Special Separation Benefit Plan as amended December 8, 2015 (filed as Exhibit 10.2 to Unit’s Form 8-K dated December 14,
2015, which is incorporated herein by reference).
Separation Benefit Plan for Senior Management as amended December 31, 2008 (filed as Exhibit 10.3 to Unit’s Form 8-K
dated January 6, 2009, which is incorporated herein by reference).
Unit Consolidated Employee Oil and Gas Limited Partnership Agreement (filed as an Exhibit to Unit’s Annual Report under
cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
Unit 2000 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (incorporated by reference to Exhibit
10 of Unit’s Annual Report on Form 10-K for the year ended December 31, 1999).
Unit 2001 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under the cover of Form 10-K for the year ended December 31, 2000).
136
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.3
10.31
10.32
10.33
21
23.1
23.2
31.1
31.2
32
99.1
Unit 2002 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2001).
Unit 2003 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2002).
Unit 2004 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2003).
Unit 2005 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2004).
Unit 2006 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2005).
Unit 2007 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2006).
Unit 2008 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2007).
Unit 2009 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2008).
Unit 2010 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2009).
Unit 2011 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit’s Annual
Report under cover of Form 10-K for the year ended December 31, 2010).
Purchase and sale agreement, dated March 28, 2018, by and between Unit Corporation and SP Investor Holdings, LLC (filed
as Exhibit 10.1 to Unit's Form 10-Q dated May 3, 2018, which is incorporated herein by reference).
Subsidiaries of the Registrant (filed herein).
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (filed herein).
Consent of Ryder Scott Company, Lyy
.P. (PP filed herein).
Certification of Chief Executive Officer under Rule 13a - 14(a) of the Exchange Act (filed herein).
Certification of Chief Financial Officer under Rule 13a - 14(a) of the Exchange Act (filed herein).
Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a-14(a) of the Exchange Act and 18 U.S.C.
Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002 (filed herein).
Ryder Scott Company, Lyy
.P. SPP ummary Report (filed herein).
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
* Indicates a management contract or compensatory plan identified under the requirements of Item 15 of Form 10-K.
Item 16. Form 10-K Summary
Not applicable.
137
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Description
Balance at
Beginning
of Period
Additions
Charged to
Costs &
Expenses
Deductions
& Net
Write-Offs
Balance at
End of
Period
Year ended December 31, 2018.................................................... $
Year ended December 31, 2017.................................................... $
Year ended December 31, 2016.................................................... $
2,450
3,773
5,199
$
$
$
(In thousands)
81
348
785
$
$
$
— $
(1,671) $
(2,211) $
2,531
2,450
3,773
138
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
DATE: February 26, 2019
By:
UNIT CORPORATION
/s/ LARRY D. PINKSTON
LARRY D. PINKSTON
President and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the Registrant and in the capacities indicated on the 26th day of February, 2019.
Name
Title
/s/
J. MICHAEL ADCOCK
J. Michael Adcock
/s/ LARRY D. PINKSTON
Larry D. Pinkston
/s/ LES AUSTIN
Les Austin
/s/ DON A. HAYES
Don A. Hayes
/s/ GARY CHRISTOPHER
Gary Christopher
Chairman of the Board and Director
President and Chief Executive Officer and Director
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer
(Principal
Financial Officer)
Vice President, Controller
(Principal Accounting Officer)
Director
/s/ STEVEN B. HILDEBRAND
Director
Steven B. Hildebrand
/s/ CARLA S. MASHINSKI
Carla S. Mashinski
/s/ WILLIAM B. MORGAN
William B. Morgan
/s/ LARRY C. PAYNE
Larry C. Payne
/s/ G. BAILEY PEYTON IV
G. Bailey Peyton IV
/s/ ROBERT SULLIVAN, JR.
Robert Sullivan, Jr.
Director
Director
Director
Director
Director
139
[THIS PAGE INTENTIONALLY LEFT BLANK]
CORPORATE INFORMATION
BOARD OF DIRECTORS
J. MICHAEL ADCOCK
Chairman of the Board
Shawnee, Oklahoma
GARY R. CHRISTOPHER
Investments
Tulsa, Oklahoma
STEVEN B. HILDEBRAND
Investments
Tulsa, Oklahoma
CARLA S. MASHINSKI
Chief Financial Officer
Cameron LNG
Houston, Texas
WILLIAM B. MORGAN
Investments
Scottsdale, Arizona
LARRY C. PAYNE
President and CEO of LESA
and Associates, LLC
Tulsa, Oklahoma
G. BAILEY PEYTON IV
President, Peyton Holdings
Canadian, Texas
LARRY D. PINKSTON
Chief Executive Officer and President
Tulsa, Oklahoma
COMPENSATION
COMMITTEE
CARLA S. MASHINSKI
Chair
J. MICHAEL ADCOCK
WILLIAM B. MORGAN
STEVEN B. HILDEBRAND
GARY R. CHRISTOPHER
NOMINATING &
GOVERNANCE
COMMITTEE
WILLIAM B. MORGAN
Chair
LARRY C. PAYNE
ROBERT J. SULLIVAN JR.
AUDIT COMMITTEE
STEVEN B. HILDEBRAND
Chair
J. MICHAEL ADCOCK
GARY R. CHRISTOPHER
STOCK LISTING
Our common stock trades on the New York
Stock Exchange under the symbol: “UNT.”
During 2018, our average daily trading
volume on the NYSE was 403,744 shares.
Approximately 54.1 million shares were
outstanding at the end of 2018.
Annual Meeting of Shareholders
May 1, 2019, 11:00 a.m. Central Time
Unit Corporation Headquarters,
8200 S. Unit Drive,
Tulsa, Oklahoma 74132
INVESTOR RELATIONS
The Form 10-Q reports are available in May,
August, and November. The Form 10-K and
Form 10-Q are available for viewing on our
website at www.unitcorp.com. Copies of
the Forms 10-K, 10-Q, and Annual Report,
filed with the Securities and Exchange
Commission, are available without charge on
written request to:
Investor Relations Department
8200 South Unit Drive
Tulsa, Oklahoma 74132
918.493.7700
WILLIAM B. MORGAN
INDEPENDENT REGISTERED PUBLIC
ROBERT J. SULLIVAN, JR.
Manager of Sullivan and Company LLC
Tulsa, Oklahoma
LARRY C. PAYNE
CARLA S. MASHINSKI
ACCOUNTING FIRM
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
INDEPENDENT
PETROLEUM
ENGINEERS
TRANSFER AGENT
& REGISTRAR
Communications concerning the transfer
Ryder Scott Company, L.P.
of shares, lost certificates and changes of
address should be directed to:
American Stock Transfer & Trust Co.
6201 15th Avenue
Brooklyn, NY 11219
800.710.0929
www.astfinancial.com
DIRECTOR EMERITUS
KING P. KIRCHNER
Co-founder, Unit Corporation
Tulsa, Oklahoma
MANAGEMENT
J. MICHAEL ADCOCK
Chairman of the Board
LARRY D. PINKSTON
Chief Executive Officer
and President
DAVID T. MERRILL
Chief Operating Officer
MARK E. SCHELL
Senior Vice President,
General Counsel, and Secretary
G. LES AUSTIN
Senior Vice President and
Chief Financial Officer
NYSE: UNT
www.unitcorp.com