CorporaTe profile
Unit Corporation is a diversified energy company engaged
through its subsidiaries in the exploration for and production
of oil, natural gas, and natural gas liquids, the contract drilling
of onshore oil and natural gas wells, and the gathering and
processing of natural gas. Operations are principally located in
the Mid-Continent region, including the Anadarko and Arkoma
Basins, with additional activity in the Permian, Rocky Mountain,
Appalachia, and Gulf Coast Basins.
Table of ConTenTs
Areas of Operations .....................................................1
5-Year Financials..........................................................1
Letter to Shareholders .................................................2
Operational Highlights ..................................................5
Segment Highlights .....................................................6
Form 10-K .................................................................11
Corporate Information .......................Inside Back Cover
Casper office
Mississippian basin
Tulsa
Headquarters
arKoMa basin
oklahoma City
office
anaDarKo basin
perMian basin
Contract Drilling
Oil & Natural Gas
Midstream
Houston office
GUlf CoasT basin
oVerVieW of operaTions
5-Year finanCial inforMaTion
Year ended December 31, ($ in thousands)
Total revenues
Capital expenditures 1
Total assets
long-Term Debt
shareholders’ equity
Total Capitalization
$
$
$
$
$
$
2013
2012
2011
2010
2009
1,351,850
$
1,315,123
$
1,207,503
$
870,671
$
707,188
703,984
$
1,360,866
$
778,564
$
576,309
$
316,660
4,022,390
$
3,761,120
$
3,256,720
$
2,669,240
$
2,228,399
645,696
$
716,359
$
300,000
$
163,000
$
30,000
2,173,392
$
1,974,301
$
1,947,017
$
1,710,617
$
1,565,810
2,819,088
$
2,690,660
$
2,247,017
$
1,873,617
$
1,595,810
1 Capital expenditures (cash basis) including acquisitions.
UNIT CORPORATION
1
1
UNIT CORPORATION To oUr sHareHolDers
During 2013, we celebrated our 50 year anniversary, a
milestone event in the energy industry. We continue to be driven
by the long-term outlook for our business. We are focused on
corporate goals geared to position us for many more years of
consistent growth and strong performance – all to the end of
adding value for our shareholders.
Each of our three business segments are executing on strategies
for sustainable growth. Our oil and natural gas segment is
positioned in resource plays where we have experience and
expertise. Among our core areas, we have identified many
years’ worth of potential drilling locations thus enabling us
to achieve consistent growth and commodity mix objectives.
Our contract drilling segment has designed a new 1,500
horsepower A/C drilling rig of proprietary design, the BOSS
rig (Box on Box Self-Rising Substructure), which we believe
will set a new standard as the energy industry continues to
transition into the development stage. Before the completion
of our first BOSS drilling rig, we have received commitments
for two additional BOSS rigs both to be delivered mid-2014.
As the BOSS drilling rigs are deployed, we are optimistic that
the design and capabilities of this drilling rig will be quickly
adopted by new customers and result in the recapture of market
share. We have made substantial investments in our midstream
segment over the last few years, positioning that segment for
significant growth. We have also focused on increasing its fee-
based contract mix to reduce commodity price exposure and to
provide a more stable, sustainable cash flow growth trajectory.
All in all, the strategic initiatives that we have been focusing
on have moved our company in a direction that will become
increasingly evident in the years to come. We have and will
continue to position the company for sustainable growth.
2013 YEAR IN REVIEW
2013 was an active year for our oil and natural gas segment as
we integrated additional Granite Wash acreage and nearly 600
possible drilling locations, which we acquired in 2012, into our
overall operations program. Likewise, we also spent a great
deal of time and effort understanding, delineating and creating
a multi-pay zone exploration and development program for our
Wilcox play in South Texas. Together these two areas were the
primary focus of our 2013 operations, complimented by our
Marmaton oil projects and our continuing exploration work in
the Mississippian Lime play.
The strength of our exploration and production asset base is
illustrated by the 18% growth in our production for the year.
Mid-year, we raised our production guidance range to between
15% to 18%, and we were able to achieve the upper-end of
that range even though we spent less capital in 2013 than in
2012. I think this result highlights both the experience and
expertise of our oil and natural gas segment personnel and,
equally important, the strength of our asset base.
For our contract drilling segment, the market has been
challenging for the past several years, a result of lower natural
gas prices from 2009-2013. The past few years have forced
operators to seek out lower cost, higher efficiency drilling
solutions. These efficiencies have reduced the overall number
of drilling rigs operating in the United States. Although we
have not been immune to these effects, we were able to
maintain an average per day operating margin of $7,796,
before the elimination of intercompany drilling rig profit, during
2013. In addition, during the past year we sold five of our
idle drilling rigs for $32.4 million and retired one drilling rig,
bringing our fleet at year end to 121. After year end, we sold
2
2013 ANNUAL REPORT bY THe nUMbers
Oil & Natural Gas Segment
proved reserves
(Mboe)
production
(Mboe)
Wells Drilled
180,000
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
09
10
11
12
13
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
09
10
11
12
13
180
160
140
120
100
80
60
40
20
0
09
10
11
12
13
Contract Drilling Segment
Midstream Segment
Consolidated
Total footage Drilled
(000’s)
Volume of natural Gas
processed (Mcf/Day)
Total revenue
($000’s)
12,000
10,000
8,000
6,000
4,000
2,000
0
09
10
11
12
13
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
1,500,000
1,200,000
900,000
600,000
300,000
09
10
11
12
13
0
09
10
11
12
13
UNIT CORPORATION
3
3
UNIT CORPORATION four additional drilling rigs, bringing our current fleet to 117.
The drilling rigs sold were those we had identified as not well
suited for future market demand.
a rising tide raises all boats, and we have positioned each of
Unit Corporation’s three business segments to contribute to
continuing corporate growth in 2014 and beyond.
We have planned a 2014 operating capital expenditure program
of $928 million, 33% higher than in 2013, with 78% allocated
to exploration and production, 14% to contract drilling and 8%
to our midstream operations. The bulk of our 2014 capital
program will be funded with internally-generated cash flows
based upon budgeted realized prices of $90.08 per barrel oil,
$29.45 per barrel of natural gas liquids, and $3.77 per Mcf
natural gas. The combination of attractive high-working interest
drilling projects, coupled with a potential increase in rig fleet
demand, and increasing capacity in our midstream segment,
reflects great growth opportunities in the future.
As energy investors are well aware, the independent oil and gas
sector has faced many challenges since 2009 ranging from the
capital markets crisis to consistently lower commodity prices
to a fundamentally more challenging regulatory environment.
We have endured these challenges and consistently delivered
growth in our production and reserves, while increasing
cash flows and maintaining a disciplined and conservative
financial structure.
In closing, I believe that the longevity and success of our
company over the decades has come down to the skills of our
people and our focus on delivering results. I believe we have
once again delivered strong, positive results in 2013, and we
are working diligently every day on behalf of our shareholders to
grow our business in 2014 and beyond.
Larry D. Pinkston
President and Chief Executive Officer
February 25, 2014
During 2013, we finished designing and started building our
new BOSS rig, which is a purpose-built, 1,500 horsepower
AC drilling rig designed from the ground up by our engineers.
Our concept is to combine the best technological innovations
from recent high-tech drilling rig designs into a single unique
drilling rig that meets the demands of today’s market, such as
the need to have a quick assembly substructure which can
be moved in smaller, lighter loads, reducing the number of
permits needed to move the drilling rig to a new location. Our
goal was to design an AC drilling rig that would contribute
to our customers’ efficiencies in a number of ways, and we
believe we have an industry-leading design to offer to our
customers. The first BOSS rig will begin operating in the
Granite Wash for our oil and natural gas segment during the
first quarter of 2014.
As excited as we are about the BOSS rig for the future of our
company, we still operate and maintain one of the largest land
rig drilling fleets in the United States, and are active in each of
the major producing basins. We believe the area of greatest
potential in the current horizontal drilling rig market is in the
750 horsepower to 1,700 horsepower drilling rig category.
Drilling rigs in this category comprised 70% of our total rig
fleet at year end, so we are very well-positioned to continue
to capitalize on the trend in the industry of drilling horizontal
wells almost exclusively. However, as we deploy the BOSS
rigs in to our fleet, we will continue to evaluate the make-up
of our fleet with the objective of maximizing our rig utilization.
Our midstream segment and wholly-owned subsidiary,
Superior Pipeline Company, increased its per day gas
gathered volumes by 24% in 2013, an indication of the strong
performance from this segment. We anticipate that the effort
spent over the past several years building the infrastructure
of this operation has positioned it well for future growth. We
are continuing our initiative to increase the percentage of fee-
based contract volumes and margins in order to continue the
trajectory of moving to more stable and higher cash flows.
LOOKING AHEAD
Moving ahead, I think 2014 will be a bellwether year in that I
believe oil prices will remain consistent within their current
pricing bands, and we are beginning to see evidence of
sustained increases in natural gas prices. As the saying goes,
4
2013 ANNUAL REPORT operaTional HiGHliGHTs
Year ended December 31, ($ in thousands except average price amounts)
Oil And Natural Gas Operations Data:
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:
natural Gas (MMcf)
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
2013
2012
2011
2010
2009
$ 1,791,903
$ 1,475,792
$ 1,578,422
$ 1,284,925
$ 775,358
$ 1,225,976
$ 1,079,956
$ 1,087,909
$ 855,086
$ 546,335
581,784
555,647
442,135
420,486
419,061
21,765
41,205
21,998
35,166
20,255
22,087
17,494
16,117
159,934
149,772
116,031
103,692
56,757
3,360
3,914
16,734
48,930
3,279
2,796
14,230
44,104
2,511
2,239
12,101
40,756
1,521
1,549
9,863
$
$
$
$
3.32
95.06
31.79
37.77
$
$
$
$
3.37
92.60
31.58
39.14
$
$
$
$
4.26
87.18
43.64
41.71
$
$
$
$
5.62
69.52
37.04
39.78
$
$
$
$
149
143
96%
171
169
99%
160
144
90%
167
151
90%
11,669
14,653
96,165
44,063
1,286
1,488
10,118
5.59
56.33
22.81
34.86
95
89
94%
2013
2012
2011
2010
2009
Producing Well Count:
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
natural Gas
oil
Total
6,705
2,991
9,696
2,182
599
2,781
6,986
2,937
9,923
2,213
564
2,777
5,915
2,759
8,674
1,541
460
2,001
5,180
2,656
7,836
1,225
415
1,641
5,048
2,655
7,703
Net
1,161
409
1,570
Year ended December 31, ($ in thousands except average price amounts)
2013
2012
2011
2010
2009
Contract Drilling Operations Data:
number of Drilling rigs at Year end
Wells Drilled
121
793
127
773
Total footage Drilled (feet in 1,000’s)
10,578
10,551
average number of Drilling rigs Utilized
average Utilization
Mid-Stream Operations Data:
natural Gas Gathered (Mcf/Day)
natural Gas processed (Mcf/Day)
liquids sold (Gallons/Day)
65.0
52%
309,554
140,584
543,602
73.9
58%
250,290
133,987
542,578
127
742
9,749
76.1
61%
121
593
7,961
61.4
50%
130
409
4,627
38.9
30%
188,569
92,940
412,064
159,885
65,740
271,360
159,991
60,726
243,492
UNIT CORPORATION
5
5
UNIT CORPORATION seGMenT HiGHliGHTs
OIL AND NATURAL GAS SEGMENT
At the end of 2013, our total proved reserves were 160
MMBoe, or 960 Bcfe, a 7% increase over 2012. We replaced
approximately 161% of our 2013 production. Estimated proved
reserves were 13% oil, 26% natural gas liquids (NGLs), and
61% natural gas.
Our strategy of drilling oil or NGLs rich wells is evident in our
production results. Liquids production for the fourth quarter
of 2013 increased 178% since the first quarter of 2009 when
we began focusing almost entirely on increasing our liquids
production. Total production for all of 2013 was 16.7 MMBoe,
an increase of 18% over the 14.2 MMBoe produced during
2012. Our production guidance for 2014 is approximately 19.2
to 19.7 MMBoe, an increase of 15% to 18% over 2013.
Our 2013 oil and natural gas revenues increased 14% to $649.7
million. The price we received for our natural gas averaged
$3.32 per Mcf, a decrease of 1% from 2012, while our average
oil price received increased 3% to $95.06 per barrel. Our NGLs
price received averaged $31.79 per barrel, up 1% from 2012.
In the Texas Panhandle District, which consists primarily of
Granite Wash (GW) wells and to a lesser degree Cleveland
wells, production for 2013 increased approximately 28% over
2012. We had first sales on 23 horizontal GW wells, having
an average peak 30 day IP rate of 5.2 MMcfe per day and an
average working interest of 85%. We also had first sales on
three Cleveland wells with an average peak 30 day rate of 3.9
MMcfe per day at an average working interest of 80%. We
recently completed drilling operations on three separate well
pads located in different sections of the Buffalo Wallow GW
field. Each pad has three wells resulting in nine total wells that
will target five different GW sand intervals. Six of the wells
have been fracture stimulated and the remaining three wells
are scheduled to be fracture stimulated in the first quarter
2014. We plan to monitor production from these three pads for
approximately 90 days prior to resuming pad drilling in the field.
At the conclusion of the testing phase, we will report the results
from all nine wells. We plan to run three to five Unit rigs in the
GW play and one Unit rig in the Cleveland play during 2014.
The Wilcox play in southeast Texas continues to deliver strong
results. Production for 2013 increased 21% as compared to
2012. For 2013, we completed six vertical and one horizontal
liquids rich Wilcox gas wells and drilled one dry hole. We own
100% working interest in all eight wells. Our first horizontal
Wilcox well was completed in late November 2013 at an
initial rate of approximately 4.4 MMcf per day and 73 barrels
of condensate per day from approximately 1,500 feet of Basal
Wilcox lateral. The initial results are encouraging, but additional
production data is needed to better estimate the ultimate
reserves of this well. There are currently two Unit rigs drilling in
our Wilcox play with plans to add a third rig in the second half of
the year, which should result in approximately 10 to 12 vertical
wells and two to four horizontal wells drilled in this play in 2014.
In our Mississippian play in south central Kansas, production
for 2013 increased 218% as compared to 2012. We had first
sales on eight Mississippian wells during 2013 with an average
30 day IP rate of 222 Boe per day consisting of an average of
approximately 53% oil, 11% NGLs, and 36% natural gas with a
100% average working interest. The last four wells completed
in the fourth quarter of 2013 had a significantly higher liquids
cut consisting of approximately 79% oil, 6% NGLs, and 15%
natural gas with an average 30 day IP rate of approximately 231
Boe per day. We are currently considering altering our drilling
program in this play in 2014 to drill extended lateral wells and
6
2013 ANNUAL REPORT to test different fracture stimulation designs. We are currently
running two Unit rigs in the play.
In the Marmaton horizontal oil play in Beaver County, Oklahoma,
we had first sales on 41 horizontal wells during 2013 with an
average 30 day IP rate of 371 Boe per day with an approximate
average working interest of 75%. Two additional potential
horizontal targets in the play are scheduled to be tested in 2014.
We had two Unit rigs drilling in the play and plan to continue
with this two rig drilling program.
During 2013, we completed sales of certain non-core oil and
natural gas assets, with total proceeds of $78.8 million with the
most significant portion coming from the sale of the majority of
our non-operated Bakken assets.
CONTRACT DRILLING SEGMENT
Our contract drilling segment operated in a soft drilling
market throughout 2013; however, the market is showing
some improvement into 2014. During 2013, we maintained
consistent utilization and drilling rig rates throughout the year.
We initiated a comprehensive evaluation of our drilling rig fleet
that included a review regarding the possible realignment of
our fleet’s capabilities and efficiencies. In view of the current
demand for drilling rigs using new technologies, we determined
to sell several of our older and larger drilling rigs that have not
worked for some time. During the year, we sold four idle 2,000
horsepower drilling rigs, one idle 3,000 horsepower drilling
rig, and retired one 700 horsepower drilling rig, bringing our
fleet’s year-end total to 121 drilling rigs. Proceeds from the
sale of the drilling rigs totaled $32.4 million. The sale of four
additional idle 3,000 horsepower drilling rigs was completed
after year end. The proceeds from these sales will be used
in our new drilling rig program, a program we launched to
design and build a new proprietary drilling rig, the BOSS
rig. We anticipate this drilling rig, coupled with continued
enhancements to our existing fleet, will position us to continue
to meet the demands of our existing customers as well as
allowing us to compete for the work of new customers. Our
first BOSS drilling rig will go to work for our oil and natural gas
segment during the first quarter of 2014.
In 2013, our drilling revenues decreased 22% to $414.8 million,
while average day rates for the year decreased 2% to $19,646.
For 2013, we averaged 65.0 drilling rigs working, a decrease of
12% from 73.9 drilling rigs working during 2012.
As the industry has shifted its focus from dry natural gas
exploration to oil and liquids-rich gas exploration, we have
responded to this shift by refurbishing our drilling rig fleet to
accommodate horizontal drilling to reach these resources.
Since 2009, we have refurbished or upgraded 48 drillings rigs
in our fleet to meet our customer demand. Currently, 97% of
our contracted drilling rigs are drilling horizontal wells.
Unit ended the year with 121 drilling rigs. With the recent sale of
four additional drilling rigs, our fleet’s total is currently 117, 69 of
which are contracted. Long-term contracts (contracts with original
terms ranging from six months to three years in length) are in
place for 23 of those 69 drilling rigs. Of these contracts, seven
are up for renewal during the first quarter of 2014, 10 during the
second quarter of 2014, five during the fourth quarter of 2014,
and one in 2015.
We have 32 drilling rigs in our Rocky Mountain operations, 71 in
our Anadarko Basin operations, three drilling rigs in the Permian
Basin and 11 in our Gulf Coast operations. Our new BOSS rig
will be operational in the first quarter of 2014, and two additional
BOSS drilling rigs are contracted to third party operators and are
anticipated to be placed into service by the end of 2014.
MIDSTREAM SEGMENT
Our midstream operations serve a strong customer base
of mostly independent producers located in Oklahoma,
Texas, Kansas, Pennsylvania and West Virginia. We
operate three natural gas treatment plants, 15 natural
gas processing plants, 38 active gathering systems and
approximately 1,500 miles of pipeline.
Revenues for our midstream operations increased 32% in
2013 to $287.4 million. For 2013, processing volumes
increased 5% to 140,584 Mcf per day, while gathering
volumes increased 24% to 309,554 Mcf per day. Liquids
sold volumes remained relatively unchanged at 543,602
gallons per day.
After relocating two processing plants from our Hemphill
County, Texas facility to our new Reno County, Kansas
facility, we now have the capacity to process 135 MMcf
per day of our own and third party Granite Wash natural
gas production at our Hemphill facility. We completed two
pipeline extension projects for a total cost of approximately
$5.7 million in the fourth quarter of 2013, which will allow
us to connect additional production from our oil and natural
gas segment to this system.
We have completed construction of a new gathering and
processing facility in Reno County, Kansas. This new
system consists of approximately 20 miles of gathering
pipeline and two processing plants that were relocated
from our Hemphill facility which included a five MMcf per
7
UNIT CORPORATION
day refrigerated JT plant skid and a 20 MMcf per day turbo
expander plant skid.
We began gathering gas at this facility during the second quarter
of 2013 and processing gas in the third quarter of 2013.
In the Mississippian play in north central Oklahoma, our
Bellmon system consists of approximately 185 miles of
pipeline, which includes a 26-mile extension to connect our
existing Remington facility, a 20-mile NGL line and two owned
natural gas processing plants. In the first quarter of 2013, we
completed the installation of a 30 MMcf per day cryogenic
processing plant. Due to anticipated increased volumes, we
also completed the installation of a new 60 MMcf per day
processing plant in the first quarter of 2014. We now have
capacity to process 90 MMcf per day at this facility.
In the Appalachian region, construction on the first phase
of our Pittsburgh Mills gathering facility in Allegheny and
Butler Counties, Pennsylvania is complete and consists
of approximately 14 miles of gathering pipeline. In the
first quarter of 2013, the related compressor station was
completed and operational. We currently have 19 wells
connected to this gathering system with plans to continue
to add wells as they are drilled. Preliminary activity is
underway for the planned expansion of this pipeline into
Butler County, Pennsylvania scheduled to begin in the
second quarter of 2014. This expansion is expected to
be completed by the end of 2014. We completed the
construction of the Brookfield gathering system, a new
gathering system in north central Pennsylvania. It became
operational in the second quarter of 2013.
Our midstream segment has seen solid volume growth
over the past nine years. We believe we are well positioned
to take advantage of growth opportunities in all areas of
these operations.
MEET THE NEW BOSS
8
2013 ANNUAL REPORT In February we celebrated the completion
of our first BOSS drilling rig at our
Oklahoma City Yard.
Customers,
friends and employees
attended this event on a cold Oklahoma
day, but the weather did not matter.
Everyone was excited and interested to
tour this newly designed drilling rig that
we believe will set a new standard in
the industry. We would like to thank
everyone who joined with us as we
proudly commissioned it into service.
9
UNIT CORPORATION FORM 10-K
10
2013 ANNUAL REPORT 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, 2013
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.)
7130 South Lewis, Suite 1000
Tulsa, Oklahoma
(Address of principal executive offices)
74136
(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
Name of each exchange on which registered
Common Stock, par value $.20 per share
Rights to Purchase Series A Participating
Cumulative Preferred Stock
NYSE
NYSE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Securities registered pursuant to Section 12(g) of the Act: None
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 and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted 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 and post 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]
Accelerated filer [ ]
Non-accelerated filer [ ]
Smaller reporting company [ ]
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, 2013, 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, 2013) held by non-affiliates was approximately $1,080,689,810 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.
Class
Common Stock, $0.20 par value per share .........................................................
Outstanding at February 14, 2014
49,232,860 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 7, 2014. The Proxy Statement shall 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 119
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.
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
Item 15.
Exhibits and Financial Statement Schedules ...............................................................................................
Signatures .............................................................................................................................................................................
Exhibit Index ........................................................................................................................................................................
Page
1
22
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38
40
41
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112
112
112
113
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119
DEFINITIONS
The following are explanations of some of the terms used in this report.
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
ASU – Accounting Standards Update.
Bcf – Billion cubic feet of natural gas.
Bcfe – Billion cubic feet of natural gas equivalent. 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 terms of gas volumes. Btu is used to refer to the amount of 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 which are
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. 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. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf
of natural gas.
Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NGPL-TXOK – Natural Gas Pipeline Co. of America/Texok zone.
DEFINITIONS — (Continued)
NYMEX – The New York Mercantile Exchange.
OPIS – Oil Price Information Service.
PEPL – Panhandle East Pipeline Co.
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.
Proved developed reserves – Reserves that can be 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 – from a given date forward, from
known reservoirs and under existing economic conditions, operating methods, and government regulations – prior to the time at
which 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.
Proved undeveloped reserves – Proved reserves that are 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 (in regards to reserves) – If deterministic methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability
that the quantities actually 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 in order to produce economically.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a 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 conservation measure. Well
spacing is normally accomplished by order of the appropriate regulatory conservation commission.
Workovers – Operations on a producing well to restore or increase production.
WTI – West Texas Intermediate, the benchmark crude oil in the United States.
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2013
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 and, as appropriate, one or more of Unit Corporation and its subsidiaries.
Our executive offices are at 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136; 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 made available in print, free of charge, 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). Materials we file with the SEC may
be read and copied at the SEC’s Public Reference Room at 100 F. Street, N.E. Room 1580, N.W., Washington, D.C. 20549.
Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC
also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other
information regarding our company that we file electronically with the SEC.
In addition, 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 free of charge on our website or in print to any shareholder who requests them. We may
from time to time 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. Today, in addition to 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. This segment explores, develops,
acquires, and produces oil and natural gas properties for our own account.
• Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts
to drill onshore oil and natural gas wells for others, and for our own account.
• Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment
buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.
Each of these companies may conduct operations through subsidiaries of their own.
The following table provides certain information about us as of February 14, 2014:
Completed gross wells in which we own an interest .............................................................................................
Number of drilling rigs we own .............................................................................................................................
Number of natural gas treatment plants we own....................................................................................................
Number of processing plants we own ....................................................................................................................
Number of natural gas gathering systems we own.................................................................................................
9,842
117
3
15
38
1
2013 SEGMENT OPERATIONS HIGHLIGHTS
Oil and Natural Gas
• Attained net proved oil, NGLs, and natural gas reserves of 159.9 million barrels of oil equivalents (MMBoe), a 7%
increase over 2012 reserves.
•
Increased net proved oil and NGLs reserves by 10% over 2012.
• Total production of 16.7 MMBoe or an 18% increase over 2012.
•
•
Participated in the drilling of 149 wells.
Sold non-core assets with proceeds of $78.8 million for the year.
Contract Drilling
•
Sold five 2,000-3,000 horsepower electric drilling rigs to unaffiliated third-parties.
• Launched our new drilling program to design and build new proprietary 1,500 horsepower AC electric drilling rigs,
called the BOSS drilling rig. The first BOSS drilling rig is expected to be completed and put into service for our oil
and natural gas segment during the first quarter of 2014.
• Moved two rigs into the Permian Basin of West Texas.
Mid-Stream
• Gas gathered increased from 250,290 Mcf per day in 2012 to 309,554 Mcf per day in 2013, a 24% increase.
• Gas processed increased from 133,987 Mcf per day in 2012 to 140,584 Mcf per day in 2013, a 5% increase.
• Added 155 miles of pipeline (approximately a 12% increase) and connected 150 new wells to our various gathering
systems.
• Completed construction of a new gathering and processing facility in south central Kansas, known as the Reno
system, and the related installation of two gas processing plants which provide 25 MMcf per day total processing
capacity.
• Completed the installation of a 30 MMcf per day plant at our Bellmon facility increasing our total processing
capacity to 55 MMcf per day.
•
Purchased a new 60 MMcf per day gas processing plant for our Bellmon system and began installation of this plant
which was completed in February 2014.
• Completed the installation and upgrade of the Dove Creek processing plant at our Perkins facility increasing our
processing capacity by 8 MMcf per day.
• Completed construction of a new gathering system in north-central Pennsylvania, known as the Brookfield system.
•
Increased the contract mix as a percent of volume for fee-based contracts to 62% in 2013 from 39% in 2012.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 17 of our Notes to Consolidated Financial Statements in Item 8 of this report for information with respect to
each of our segment’s revenues, profits or losses, and total assets.
2
OIL AND NATURAL GAS
General. We began to develop our exploration and production operations in 1979. Today, our wholly owned subsidiary,
Unit Petroleum Company, conducts our exploration and production activities. Our producing oil and natural gas properties,
unproved properties, and related assets are in the following locations:
Division
Location
Western and Southern Texas, Colorado, Wyoming, Montana, North Dakota, New
West division .............................
Mexico, Southern Louisiana, and Mississippi
East division .............................. East Texas, Eastern Oklahoma, Pennsylvania, Arkansas, and Northern Louisiana
Central division ......................... Western Oklahoma, Texas Panhandle and Kansas
When we are the operator of a property, we generally attempt to use a drilling rig owned by our contract drilling
segment, and we use our mid-stream segment to gather our gas if it is economical for us to develop a system in the area.
The following table presents certain information regarding our oil and natural gas operations as of December 31, 2013:
Our Divisions/Area
West division.....................................
East division......................................
Central division.................................
Total...........................................
Number
of
Gross
Wells
3,119
1,484
5,238
9,841
Number
of Net
Wells
515.39
475.59
1,840.83
2,831.81
Number
of Gross
Wells in
Process
Number
of Net
Wells in
Process
2013 Average
Net Daily Production
Natural
Gas
(Mcf)
35,787
25,755
93,956
0.75
0.03
9.63
10.41
155,498
Oil
(Bbls)
NGLs
(Bbls)
1,889
45
7,273
9,207
2,720
66
7,937
10,723
2
5
14
21
As of December 31, 2013, we did not have any significant water floods, pressure maintenance operations, or any other
material operations that were in process.
Description and Location of Our Core Operations
West division. In our Wilcox play, located primarily in Polk, Tyler, and Hardin Counties, Texas, we operated and
completed eight gross wells in 2013 with an average working interest of 100% and a success rate of 88%. Five of the eight
wells were completed in our “Gilly” Basal Wilcox field bringing the total number of wells completed in that field to ten at year
end 2013. Production for 2013 increased 21% as compared to 2012. Our first horizontal Wilcox well was completed in the
fourth quarter of 2013 at an initial daily rate of approximately 4.4 MMcf per day and 73 barrels of condensate per day from
approximately 1,500 feet of Basal Wilcox lateral. There are currently two Unit rigs drilling in our Wilcox play with plans to add
a third rig in the second half of the year, which should result in approximately 10 to 12 gross vertical wells and two to four
horizontal wells at an approximate net cost of $112 million for 2014.
East division. Over the last several years, activity in our East Division has been limited due to low gas prices since this
area does not generally have oil or NGLs associated with the gas.
Central division. In our Mississippian play in south central Kansas, the average daily production for 2013 increased
approximately 218% as compared to 2012. We had first sales on eight Mississippian wells during 2013 with an average 30 day
IP rate of 222 Boe per day consisting of an average of approximately 53% oil, 11% NGLs, and 36% natural gas with a 100%
average working interest. The last four wells completed in the fourth quarter of 2013 had a significantly higher liquids cut
consisting of approximately 79% oil, 6% NGLs, and 15% natural gas with an average 30 day IP rate of approximately 231 Boe
per day. Two potential enhancements we may make to wells drilled in the play during 2014 are drilling extended lateral wells
and testing different fracture stimulation designs. We have leased approximately 143,000 net acres in the play and are currently
running two Unit drilling rigs and expect to spend approximately $111 million in 2014.
3
In the Marmaton horizontal oil play in Beaver County, Oklahoma, we had first sales on 41 horizontal wells during 2013
with an average 30 day IP rate of 371 Boe per day with an approximate average working interest of 75%. The average daily
production for 2013 increased approximately 25% as compared to 2012. A decision from the Oklahoma Legislature to allow
drilling extended lateral wells in the play is anticipated by May 2014. Two additional potential horizontal targets in the play are
scheduled to be tested in 2014. We have leases on approximately 119,000 net acres and have two Unit rigs drilling in the play
with current plans to spend approximately $70 million.
In the Texas Panhandle District, which consists primarily of Granite Wash (GW) wells and to a lesser degree Cleveland
wells, the average daily production for 2013 increased approximately 28% over 2012. We had first sales on 23 horizontal GW
wells, having an average peak 30 day IP rate of 5.2 MMcfe per day and an average working interest of 85%. We also had first
sales on three Cleveland wells with an average peak 30 day rate of 3.9 MMcfe per day at an average working interest of 80%.
We recently completed drilling operations on three separate well pads located in different sections of the Buffalo Wallow GW
field. Each pad has three wells resulting in nine total wells that will target five different GW sand intervals. Six of the wells
have been fracture stimulated and the remaining three wells are scheduled to be fracture stimulated in the first quarter 2014.
We plan to monitor production from these three pads for approximately 90 days prior to resuming pad drilling in the field. We
plan to run three to five drilling Unit rigs in the GW play and one Unit rig in the Cleveland play for 2014 with plans to spend
approximately $174 million.
Dispositions and Acquisitions. There were no material dispositions during 2011. In September 2012, we sold our
interest in certain Bakken properties (located in North Dakota). The proceeds, net of related expenses, were $226.6 million. In
addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties,Texas, for approximately $44.1
million. In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1
million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013.
Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
On July 20, 2011, we acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in
cash, after post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver,
Harper, and Ellis Counties, Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved
properties and $3.9 million for acreage. The acquisition also included in excess of 12,000 net acres held by production
available for future development.
On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash from an unaffiliated
seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and
Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The acquisition also included
approximately 55,000 net acres of which 96% was held by production.
On September 17, 2012, we acquired certain oil and natural gas assets from Noble. After final closing adjustments, the
acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in
western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6 million.
As of the effective date of the Noble acquisition (April 1, 2012), the estimated proved reserves of the acquired properties
were 44 MMBoe, The acquisition added approximately 24,000 net leasehold acres to our Granite Wash core area in the Texas
Panhandle with significant potential including approximately 600 possible future horizontal drilling locations. The total
acreage acquired in other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres and was
characterized by high working interest and operatorship, 95% of which was held by production. We also received four
gathering systems as part of the transaction, as well as other miscellaneous assets.
4
Well and Leasehold Data. The following tables identify certain information regarding our oil and natural gas
exploratory and development drilling operations:
Year Ended December 31,
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
Wells drilled:
Exploratory:
Oil:
West division...................
East division ....................
Central division ...............
Total oil.........................
Natural gas:
West division...................
East division ....................
Central division ...............
Total natural gas............
Dry:
West division...................
East division ....................
Central division ...............
Total dry........................
Total exploratory......
Development:
Oil:
West division...................
East division ....................
Central division ...............
Total oil.........................
Natural gas:
West division...................
East division ....................
Central division ...............
Total natural gas............
Dry:
West division...................
East division ....................
Central division ...............
Total dry........................
Total development....
Total wells drilled
—
—
—
—
2
—
—
2
—
—
—
—
2
1
—
93
94
9
1
37
47
3
—
3
6
147
149
—
—
—
—
2.00
—
—
2.00
—
—
—
—
2.00
0.08
—
51.33
51.41
8.60
—
26.00
34.60
1.35
—
1.78
3.13
89.14
91.14
5
1
—
1
2
3
—
—
3
1
—
—
1
6
29
—
71
100
7
2
55
64
1
—
—
1
165
171
1.00
—
1.00
2.00
2.49
—
—
2.49
1.00
—
—
1.00
5.49
4.10
—
34.04
38.14
4.44
0.76
30.45
35.65
0.80
—
—
0.80
74.59
80.08
—
—
—
—
5
—
—
5
7
—
—
7
12
21
—
56
77
9
9
44
62
3
1
5
9
148
160
—
—
—
—
4.13
—
—
4.13
6.50
—
—
6.50
10.63
4.57
—
32.81
37.38
6.26
4.65
18.32
29.23
2.03
1.00
2.15
5.18
71.79
82.42
Wells producing or capable
of producing:
Oil:
West division..............
East division ...............
Central division ..........
Total oil.............
Natural gas:
West division..............
East division ...............
Central division ..........
Total natural gas
Total...........
Year Ended December 31,
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
2,058
42
891
2,991
1,004
1,435
4,266
6,705
9,696
170.49
1.91
426.75
599.15
326.79
472.68
1,382.62
2,182.09
2,781.24
2,076
54
807
2,937
1,109
1,632
4,245
6,986
9,923
178.43
3.17
382.34
563.94
330.19
519.62
1,362.87
2,212.68
2,776.62
2,074
54
631
2,759
1,182
1,636
3,097
5,915
8,674
183.50
3.17
273.31
459.98
335.90
522.15
683.08
1,541.13
2,001.11
As of February 14, 2014, we are currently drilling or participating in 13 gross (9.66 net) wells started during 2014.
Cost incurred for development drilling includes $136.7 million, $123.4 million, and $111.4 million in 2013, 2012, and
2011, respectively, to develop booked proved undeveloped oil and natural gas reserves.
The following table summarizes our leasehold acreage at December 31, 2013:
Developed
Year Ended December 31, 2013
Undeveloped
Total
Gross
Net
Gross
Net (1)
West division................
East division .................
Central division ............
282,448
225,054
857,022
Total.......................
1,364,524
94,918
87,908
334,472
517,298
166,432
57,707
300,560
524,699
112,403
17,811
236,567
366,781
Gross
448,880
282,761
1,157,582
1,889,223
Net
207,321
105,719
571,039
884,079
_________________________
(1) Approximately 90% (West – 83%; East – 48%; and Central – 97%) of the net undeveloped acres are covered by leases that will expire in the years 2014—
2016 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.
6
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:
Average sales price per barrel of oil produced:
Price before hedging ................................................................................ $
Effect of hedging......................................................................................
Price including hedging ........................................................................... $
Average sales price per barrel of NGLs produced:
Price before hedging ................................................................................ $
Effect of hedging......................................................................................
Price including hedging ........................................................................... $
Average sales price per Mcf of natural gas produced:
Price before hedging ................................................................................ $
Effect of hedging......................................................................................
Price including hedging ........................................................................... $
Year Ended December 31,
2013
2012
2011
95.18
(0.12)
95.06
31.79
—
31.79
3.33
(0.01)
3.32
$
$
$
$
$
$
90.19
2.41
92.60
30.70
0.88
31.58
2.53
0.84
3.37
$
$
$
$
$
$
93.49
(6.31)
87.18
44.44
(0.80)
43.64
3.78
0.48
4.26
7
Oil production (MBbls):
West division............................................................................................
East division.............................................................................................
Central division:.......................................................................................
Mendota field....................................................................................
All other central division fields ........................................................
Total central division...............................................................
Total oil production (MBbls) ...........................................
NGLs production (MBbls):
West division............................................................................................
East division.............................................................................................
Central division:.......................................................................................
Mendota field....................................................................................
All other central division fields ........................................................
Total central division...............................................................
Total NGLs production (MBbls)......................................
Natural gas production (MMcf):
West division............................................................................................
East division.............................................................................................
Central division:.......................................................................................
Mendota field....................................................................................
All other central division fields ........................................................
Total central division...............................................................
Total natural gas production (MMcf)...............................
Total production (MBoe):
West division............................................................................................
East division.............................................................................................
Central division:.......................................................................................
Mendota field....................................................................................
All other central division fields ........................................................
Total central division...............................................................
Total production (MBoe) .................................................
Average production cost per equivalent Bbl (1) ............................................... $
_______________________
(1) Excludes ad valorem taxes and gross production taxes.
Year Ended December 31,
2013
2012
2011
690
16
412
2,242
2,654
3,360
993
24
1,050
1,847
2,897
3,914
13,062
9,401
9,138
25,156
34,294
56,757
3,860
1,607
2,985
8,282
11,267
16,734
1,071
16
497
1,695
2,192
3,279
858
23
1,128
787
1,915
2,796
11,831
11,906
8,957
16,236
25,193
48,930
3,901
2,023
3,118
5,188
8,306
14,230
7.63
$
7.00
$
893
12
262
1,344
1,606
2,511
798
5
691
745
1,436
2,239
11,774
12,768
4,887
14,675
19,562
44,104
3,653
2,145
1,768
4,535
6,303
12,101
6.90
Our Mendota field, located in the Granite Wash play, includes 18%, 19%, and 22%, respectively of our total proved
reserves in 2013, 2012, and 2011, respectively, expressed on an oil equivalent barrels basis, and is the only field that is greater
than 15% of our proved reserves.
8
Oil, NGLs, and Natural Gas Reserves. The following table identifies our estimated proved developed and undeveloped
oil, NGLs, and natural gas reserves:
Proved developed:
West division.................................................................
East division..................................................................
Central division.............................................................
Total proved developed .........................................
Proved undeveloped:
West division.................................................................
East division..................................................................
Central division.............................................................
Total proved undeveloped .....................................
Total proved......................................................
Year Ended December 31, 2013
Oil
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
Proved
Reserves
(MBoe)
3,244
38
12,312
15,594
325
—
5,846
6,171
21,765
5,981
28
24,428
30,437
599
—
10,169
10,768
41,205
79,760
97,891
286,583
464,234
8,121
9,428
100,001
117,550
581,784
22,518
16,381
84,504
123,403
2,278
1,571
32,682
36,531
159,934
Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of oil, NGLs, and natural gas reserves require
extensive judgments of reservoir engineering data and are generally less precise than other estimates made in connection with
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 for
over seventy years. 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 reserve and income projections prepared by us as of December 31, 2013 and
comprised 84% of the total proved developed discounted future net income and 91% of the total proved undeveloped
discounted future net income (based on the unescalated pricing policy of the SEC).
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 sources including geological, production engineering, marketing, production, land, and accounting departments. The
engineers are responsible for reviewing this information for accuracy as it is incorporated into the reservoir engineering
database. Our internal audit group reviews the controls to help provide assurance all the data has been provided. New well
reserve estimates are provided to management as well as the respective operational divisions for additional scrutiny. Major
reserve changes on existing wells are reviewed on a regular basis with the operational divisions to confirm correctness and
accuracy. As the external audit is being completed by Ryder Scott, the reservoir department performs a final review of all
properties for accuracy of forecasting.
Technical Qualifications
Ryder Scott – Mr. Fred P. Richoux is the primary technical person in charge on behalf of Ryder Scott for their audit of our
reserves.
Mr. Richoux, an employee of Ryder Scott since 1978, is the President and member of the Board of Directors at Ryder
Scott. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir
evaluation studies worldwide as well as other administrative functions at the Company. Before joining Ryder Scott, Mr.
Richoux served in a number of engineering positions with Phillips Petroleum Company.
Mr. Richoux earned a Bachelor of Science degree in Electrical Engineering from the University of Louisiana at Lafayette
and is a registered Professional Engineer in the State of Texas and the Province of Alberta. He is also a member of the Society of
Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
9
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers
requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics,
which Mr. Richoux fulfills.
Based on his educational background, professional training and more than 45 years of practical experience in the
estimation and evaluation of petroleum reserves, Mr. Richoux has attained the professional qualifications as a Reserves
Estimator (requires appropriate degree and/or is registered as Professional Engineer and has a minimum of 3 years experience
in the estimation and evaluation of reserves) and Reserves Auditor (requires appropriate degree and/or is registered as
Professional Engineer and has a minimum of 10 years experience in the estimation and evaluation of reserves of which at least
5 years of such experience is being in responsible charge of the estimation and evaluation of reserves) set forth in Article III of
the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of
Petroleum Engineers as of February 19, 2007. For more information regarding Mr. Richoux’s geographic and job specific
experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.
The Company – Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers
Trenton Mitchell and Robert Lyon.
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 was the Outside Operated Engineer and since 2003 he has served in the
capacity of Reservoir Engineer and in 2010 he was promoted to Manager of Reservoir Engineering. Before joining Unit, he
served in a number of 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 and has been a member of Society of Petroleum Engineers (SPE) since 1991.
Mr. Lyon received a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa in 1972 and has
spent 34 of his 41 years in the industry directly involved in reserve calculation work. Included in this time were 15 years
working for petroleum consulting firms Raymond F. Kravis and Associates and Southmayd and Associates performing
independent reserve appraisals and audits for corporations and individuals. He joined Unit in 1996 and has shared responsibility
for preparation of the company’s reserve report since that time. Mr. Lyon is a registered professional engineer in the State of
Oklahoma and a member of the SPE.
As part of the continuing education requirement for maintaining their professional licenses Mr. Mitchell and Mr. Lyon
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
economically producible – from a given date forward, from known reservoirs and under existing economic conditions,
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 fluid contacts, if any, and
• Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and
to contain economically producible oil or gas on the basis of available geosciences and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as
seen in a well penetration unless geosciences, engineering or performance data and reliable technology establishes 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.
10
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 in 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 is the average price during the 12-month period before the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the first day of month price for each month within the period, unless
prices are defined by contractual arrangements, excluding escalations based on future conditions.
Proved undeveloped oil, NGLs, and natural gas reserves are proved reserves that are 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 that are 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 any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved
effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology
establishing reasonable certainty.
Proved Undeveloped Reserves. As of December 31, 2013, we had approximately 180 gross proved undeveloped wells
all of which we plan to develop within five years of initial disclosure at a net estimated cost of approximately $508.3 million.
The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United
States for the years 2014—2017, as disclosed in our December 31, 2013 oil and natural gas reserve report, are $238.3 million,
$185.4 million, $25.1 million, and $59.5 million, respectively. Our proved undeveloped reserves reported at December 31, 2013
did not include reserves that we did not expect to develop within five years of initial disclosure of those reserves. During 2013,
we added new PUD reserves through extensions and discoveries representing 4.1 MMBls of oil, 5.0 MMBls of NGLs, and 52.7
Bcf of natural gas. We converted 47 proved undeveloped wells into proved developed wells at a cost of approximately $136.7
million. The proved undeveloped reserves that were converted to proved developed reserves during 2013, represented 1.8
MMBls of oil, 2.6 MMBls of NGLs, and 21.6 Bcf of natural gas. There were no other material changes to the PUD reserves.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at
December 31, 2013, 2012, and 2011, 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 included in Item 8 of this report.
Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices in accordance
with arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines as well
as to 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 of them are market sensitive.
Customers. During 2013, sales to Valero Energy Corporation accounted for 25% of our oil and natural gas revenues.
There was no other company that accounted for more than 10% of our oil and natural gas revenues. During 2013, our mid-
stream segment purchased $83.0 million of our natural gas and NGLs production and provided gathering and transportation
services of $8.0 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 2012 and 2011, we
eliminated intercompany revenues of $73.3 million and $76.1 million, respectively, attributable to the intercompany purchase of
our production of natural gas and NGLs as well as gathering and transportation services.
11
CONTRACT DRILLING
General. Our contract drilling business is conducted through Unit Drilling Company and its subsidiary Unit Texas
Drilling L.L.C. Through these companies we drill onshore oil and natural gas wells for our own account as well as other oil and
natural gas companies. Our drilling operations are located in Oklahoma, Texas, Louisiana, Kansas, Wyoming, Colorado, Utah,
Montana, and North Dakota.
The following table identifies certain information concerning our contract drilling operations:
Number of drilling rigs owned at year end .....................................................
Average number of drilling rigs owned during year.......................................
Average number of drilling rigs utilized.........................................................
Utilization rate (1).............................................................................................
Average revenue per day (2)............................................................................. $
Total footage drilled (feet in 1,000’s)..............................................................
Number of wells drilled ..................................................................................
Year Ended December 31,
2012
2011
2013
121.0
125.4
65.0
127.0
127.4
73.9
127.0
123.7
76.1
52%
58%
61%
$
17,486
10,578
793
$
19,774
10,551
773
17,520
9,749
742
_________________________
(1) Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs owned during the year.
(2) Represents the total revenues minus rental revenue from our contract drilling operations divided by the total number of days our drilling rigs were used
minus the rental days 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, pumps to circulate the drilling fluid, blowout preventers, and
drill pipe. As a result of the normal wear and tear from operating 24 hours a day, several of the major components, like engines,
mud pumps, and drill pipe, must be replaced or rebuilt on a periodic basis. Other major components, like the substructure, mast,
and drawworks, can be used for extended periods of time with proper maintenance. We also own additional equipment used in
the operation of our drilling rigs, including top drives, skidding systems, large air compressors, trucks, and other support
equipment.
The maximum depth capacities of our various drilling rigs range from 5,000 to 40,000 feet. In 2013, 78 of our 121
drilling rigs were used in drilling services.
The following table shows certain information about our drilling rigs (including their distribution) as of February 14,
2014:
Divisions
Mid-Continent .....................................................................
Woodward............................................................................
Panhandle ............................................................................
Gulf Coast............................................................................
Rocky Mountain ..................................................................
Totals............................................................................
Contracted
Rigs
Non-
Contracted
Rigs
Total
Rigs
23
12
9
8
15
67
6
4
17
6
17
50
Average
Rated
Drilling
Depth
(ft)
17,879
13,719
12,885
17,929
17,188
16,017
29
16
26
14
32
117
Drilling rig utilization steadily increased throughout 2011 and through the first quarter of 2012. It began declining from
the second quarter of 2012 and throughout the remainder of 2012 with utilization remaining relatively flat throughout 2013.
Factors contributing to the fluctuating utilization include drilling efficiencies attained by operators, more acreage in certain
12
plays being held by production, and weakness in commodity prices. Our active drilling rig count at the start of 2011 was 72
drilling rigs. It decreased to 62 rigs at the end of 2012 and finished out 2013 at 65.
Mid-Continent, Woodward, and Panhandle – We have long held a strong position and market presence in the mid-
continent area of Oklahoma and the Texas Panhandle. This area is commonly referred to as the Anadarko Basin, which also
encompasses portions of Kansas. Historically, the Anadarko Basin has been known as a gas producing area, but it is also rich in
oil and NGL production. During the last several years operators have focused their operations in this basin on the Cana
Woodford, Granite Wash, Marmaton, and Mississippian horizontal plays. Three of our divisions work in this basin. During
2013, our Mid-Continent, Panhandle, and Woodward divisions averaged 22.0, 9.5, and 10.3 drilling rigs operating, respectively.
Gulf Coast – Our Gulf Coast division provides drilling rigs to the onshore areas of Louisiana, Texas Gulf Coast, East
Texas, South Texas. Recently two drilling rigs were moved into the Permian Basin of West Texas. During 2013, this division
averaged 6.7 drilling rigs operating. Within this division, our largest drilling rig, Rig 201, a 4,000 horsepower rig rated to drill
to 40,000 feet, drilled an ultra-deep exploration well for a major oil company in south Louisiana, establishing the record for the
deepest onshore well in the state of Louisiana.
Rocky Mountains – Our Rocky Mountain division covers several states, including Colorado, Utah, Wyoming, Montana,
and North Dakota. This vast area has produced a number of conventional and unconventional oil and gas fields. This division
operated an average of 16.5 drilling rigs during 2013. We had six drilling rigs operating in the Pinedale Anticline of western
Wyoming and ten drilling rigs operating in the Bakken Shale of North Dakota at the end of 2013.
At any given time the number of drilling rigs we can work depends on a number of conditions besides demand, including
the availability of qualified labor and the availability of needed drilling supplies and equipment. The impact of these conditions
tends to increase with increased demand for our drilling rigs. Our average utilization rate for 2011, 2012, and 2013 was 61%,
58%, and 52%, respectively.
The following table shows the average number of our drilling rigs working by quarter for the years indicated:
First quarter .....................................................................................................
Second quarter.................................................................................................
Third quarter ...................................................................................................
Fourth quarter..................................................................................................
2013
2012
2011
66.3
65.2
63.5
65.0
81.5
76.7
73.4
64.0
70.0
73.1
78.9
82.1
Drilling Rig Fleet. The following table summarizes the changes made to our drilling rig fleet in 2013. A more complete
discussion of the changes follows the table:
Drilling rigs owned at December 31, 2012 ............................................................................................................
Drilling rigs sold.....................................................................................................................................................
Drilling rigs removed from service ........................................................................................................................
Drilling rigs purchased ...........................................................................................................................................
Drilling rigs constructed.........................................................................................................................................
Total drilling rigs owned at December 31, 2013....................................................................................................
127
(5)
(1)
—
—
121
Dispositions, Acquisitions, and Construction. During 2011, we were awarded two new build drilling rig contracts for
1,500 horsepower, diesel-electric drilling rigs. One was placed into service during the fourth quarter of 2011 and the other was
placed in service during the first quarter of 2012, both in Wyoming.
During the first quarter of 2012, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third-party. In
the second quarter we placed a new 1,500 horsepower, diesel-electric drilling rig to work in North Dakota under a three year
contract.
13
During the third quarter of 2012, we had a fire on one of our drilling rigs located in the mid-continent region. The net
book value of the damaged equipment was $3.2 million. All of the net book value of the damaged equipment was recovered
from insurance proceeds. No personnel were injured in this incident.
In the second quarter of 2013, we sold one of our 2,000 horsepower electric drilling rigs. During the third and fourth
quarters of 2013, we sold three additional 2,000 horsepower and one 3,000 horsepower electric drilling rigs. All of these sales
were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party in
the first quarter of 2014 all of which were classified as assets held for sale at December 31, 2013. The proceeds from these
various sales will be used in our new drilling rig program we launched to design and build a new proprietary 1,500 horsepower,
AC electric drilling rig, called the BOSS rig. We anticipate the BOSS drilling rig will position us to more effectively meet the
demands of our existing customers as well as allowing us to compete for the work of new customers.
The first BOSS drilling rig will be operational the first quarter of 2014 and will work initially for our oil and natural gas
segment. Two additional BOSS drilling rigs are contracted to third party operators and are anticipated to be placed into service
in the second and third quarters of 2014.
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
subject to negotiation on a contract by contract basis.
The type of contract used determines our compensation. Contracts are generally one of three types: daywork; footage; or
turnkey. Additional compensation may be acquired for special risks and unusual conditions. 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. Footage contracts usually require us to bear some of
the drilling costs in addition to providing the drilling rig. We are paid on completion of the well at a negotiated rate for each
foot drilled. We did not have any footage or turnkey contracts in 2013, 2012, or 2011.
Under turnkey contracts we drill the well to a specified depth for a set amount and provide most of the required
equipment and services. We bear the risk of drilling the well to the contract depth and are paid when the contract provisions are
completed. We may incur losses if we underestimate the costs to drill the well or if unforeseen events occur that increase our
costs or result in the loss of the well. All of our work during the last three years was under daywork contracts. Because market
demand for our drilling rigs as well as the desires of our customers determine the types of contracts we use, we cannot predict
when and if a part of our drilling will be conducted under footage or turnkey contracts.
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 2013, QEP Resources, Inc. and Kodiak Oil and Gas Corp. were our largest drilling customers
accounting for approximately 18% and 10%, respectively, of our total contract drilling revenues. Our work for these customers
was under multiple contracts and our business was not substantially dependent on any of these individual contracts.
Consequently, none of these individual contracts were considered to be 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 2013, 2012, and
2011, our contract drilling segment drilled 105, 78, and 81 wells, respectively, or 13%, 10%, and 11%, respectively, of the total
wells drilled for our oil and natural gas 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. Revenues and expenses for these services are eliminated in our income statement, 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 $64.3 million, $49.6 million, and $52.2 million during 2013, 2012, and 2011, respectively,
from our contract drilling segment and eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6
14
million during 2013, 2012, and 2011, respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012,
and 2011, respectively, as a reduction to the carrying value of our oil and natural gas properties.
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, 15 processing plants, 38 active gathering systems, and approximately 1,500 miles of pipeline. Superior and its
subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
The following table presents certain information regarding our mid-stream segment for the years indicated:
Gas gathered—Mcf/day ..................................................................................
Gas processed—Mcf/day ................................................................................
NGLs sold—gallons/day.................................................................................
Year Ended December 31,
2013
2012
2011
309,554
140,584
543,602
250,290
133,987
542,578
188,569
92,940
412,064
Dispositions and Acquisitions. This segment did not have any significant dispositions or acquisitions during 2011 or
2013.
Included within the previously discussed acquisition of certain oil and natural gas assets from Noble were four gathering
systems. These systems were transferred into our mid-stream segment. The cost for the systems was $18.7 million.
Subsequently in 2013, one of these gathering systems was transferred to our oil and natural gas segment.
In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system in conjunction with the
shut down of this system.
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 do have
some short-term contracts as well. Our customer agreements include the following types of contracts:
• Fee-Based Contracts. These contracts provide for a set fee for gathering and transporting raw natural gas. Our mid-
stream’s revenue is a function of the volume of natural gas that is gathered or transported and is not directly
dependent on the value of the natural gas. For the year ended December 31, 2013, 62% of our mid-stream segment’s
total volumes and 37% of its operating margins (as defined below) were under fee-based contracts.
• Percent of Proceeds Contracts (POP). These contracts provide for our mid-stream segment to retain a negotiated
percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being
paid to the producer. In this arrangement, Superior and the producer each own a portion of the commodity and are
directly dependent on the volume and value of the commodity both of which fluctuate. For the year ended
December 31, 2013, 36% of our mid-stream segment’s total volumes and 59% of operating margins (as defined
below) were under POP contracts.
• Percent of Index Contracts (POI). Under these contracts our mid-stream segment, as the processor, purchases raw
well-head natural gas from the producer at a stipulated index price and, after processing the natural gas, sells the
processed residual gas and the produced NGLs to third parties. Our mid-stream segment is subject to the economic
risk (processing margin risk) that the aggregate proceeds from the sale of the processed natural gas and the NGLs
could be less than the amount paid for the unprocessed natural gas. For the year ended December 31, 2013, 2% of our
mid-stream segment’s total volumes and 4% of operating margins (as defined below) were under POI contracts.
For each of the above contracts, operating margin is defined as total operating revenues less operating expenses and does
not include depreciation and amortization, general and administrative expenses, interest expense, or income taxes.
Customers. During 2013, ONEOK, Inc. and Tenaska Resources, LLC accounted for approximately 50% and 16%,
respectively, of our mid-stream revenues. We believe that if we lost one or both of these identified customers, there are other
15
customers available to purchase our gas and NGLs. During 2013, 2012, and 2011 this segment purchased $83.0 million, $68.2
million, and $71.5 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided
gathering and transportation services of $8.0 million, $5.1 million, and $4.6 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.
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for oil, NGLs, and natural gas significantly affect our revenues, operating results, cash flow as well
as our ability to grow our operations. Historically, oil, NGLs, and natural gas prices have been volatile and we expect them to
continue to be so. For each of the periods indicated, the following 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 taking into account the effect of our hedging
activity:
Quarter
2013
Fourth .................... $
Third...................... $
Second ................... $
First ....................... $
2012
Fourth .................... $
Third...................... $
Second ................... $
First ....................... $
2011
Fourth .................... $
Third...................... $
Second ................... $
First ....................... $
Oil Price per Bbl
High
Low
NGLs Price per Bbl
Low
High
Natural Gas Price per Mcf
High
Low
97.34
104.25
92.85
93.89
87.01
90.04
100.63
104.32
97.26
96.90
107.87
99.77
$
$
$
$
$
$
$
$
$
$
$
$
91.15
101.70
89.97
90.80
84.39
82.69
76.35
97.31
86.63
85.68
95.78
86.14
$
$
$
$
$
$
$
$
$
$
$
$
36.33
33.14
32.17
37.97
34.82
24.07
34.65
39.77
46.16
47.08
49.43
41.66
$
$
$
$
$
$
$
$
$
$
$
$
31.92
24.78
28.94
33.14
32.42
18.02
24.65
36.04
40.57
45.44
44.60
38.35
$
$
$
$
$
$
$
$
$
$
$
$
3.36
3.33
4.04
3.20
3.57
2.78
2.34
2.80
3.46
4.30
4.04
4.11
$
$
$
$
$
$
$
$
$
$
$
$
3.08
2.79
3.73
3.04
2.54
2.19
1.65
2.17
3.16
3.68
3.83
3.53
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 a variety of additional factors that are
beyond our control, including:
•
•
•
•
•
•
•
•
political conditions in oil producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries to agree on prices and their ability
to maintain production quotas;
actions taken by foreign oil and natural gas producing nations;
the price of foreign oil imports;
imports and exports of 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 natural gas;
• weather conditions;
•
domestic and foreign government regulations;
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•
•
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 impact our operations.
Our contract drilling operations are dependent 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 can also be volatile.
Our mid-stream operations provide us greater flexibility in delivering our (and other 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 are
dependent 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 are highly dependent on the volume and Btu content of the
natural gas and NGLs gathered.
It is possible that the current industry shift in drilling for oil and NGLs may at some point impact future natural gas
availability as well as prices for natural gas. In addition, the increasing availability of oil and NGLs may impact the price for
these products if supply was to exceed demand.
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, 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
of these 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 continued drilling success and the success of 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 extremely intense, particularly when the industry is experiencing favorable conditions.
Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with
various producers, other major pipeline companies, as well as 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 16 oil and natural gas limited partnerships. Three of these
partnerships were formed in 1984 and 1986 for investment by third parties and 13 (the employee partnerships) were formed
each year beginning with 1984 and ending with 2011 to allow our employees and directors the opportunity to participate with
Unit Petroleum Company in its operations.
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 own 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.
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Under the terms of our partnership agreements, the general partner has broad discretionary authority to manage the
business and operations of the partnership, including the authority to make decisions regarding the partnership’s participation in
a drilling location or a property acquisition, the partnership’s expenditure of funds, and the distribution of funds to partners.
Because the business activities of the limited partners and the general partner are not the same, conflicts of interest will exist
and it is not possible to entirely eliminate these conflicts. Additionally, conflicts 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 and conditions 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.
These partnerships are further described in Notes 2 and 10 to the Consolidated Financial Statements in Item 8 of this
report.
EMPLOYEES
As of February 14, 2014, we had approximately 1,901 employees in our contract drilling segment, 351 employees in our
oil and natural gas segment, 132 employees in our mid-stream segment, and 79 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
Our business depends on the demand for services from the oil and natural gas exploration and development industry, and
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.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the FERC) regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas. The FERC’s jurisdiction over interstate natural gas
sales has been substantially modified by the Natural Gas Policy Act under which the 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, the 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. The FERC’s jurisdiction
over interstate natural gas transportation is not affected by the Decontrol Act.
Our sales of natural gas will be affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the
FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes
are intended by the FERC to foster competition by, among 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 is
required to divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other
merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the subsequent 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, the FERC expanded the impact of open access regulations to certain aspects of intrastate
commerce.
FERC has pursued other policy initiatives that have 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 the
use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a
timely basis 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
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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 upon the pipeline’s demonstration of lack of market control in
the relevant service market.
As a result of these changes, independent sellers and buyers of natural gas have gained direct access to the particular
pipeline services they need and are better able to conduct business with a larger number of counter parties. We believe these
changes generally have improved the access to markets for natural gas while, at the same time, substantially increasing
competition in the natural gas marketplace. However, we cannot predict what new or different regulations the FERC and other
regulatory agencies may adopt or what effect subsequent 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 in favor of deregulation and the promotion of competition in the natural gas industry. Thus, in addition to
“first sales” 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. At the present time, it is impossible to predict what proposals, if any, might actually
be enacted by Congress or the various state legislatures and what effect, if any, these proposals might have on the production
and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry,
whether 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.
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, the 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 tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual
adjustments could result in decreased rates in a given year. These regulations have generally been approved on judicial review.
Every five years, the FERC will examine the relationship between the annual change in the applicable index and the actual cost
changes experienced by the oil pipeline industry and make any necessary adjustment in the index to be used during the ensuing
five years. We are not able to predict with certainty what effect, if any, the periodic review of the index by the FERC will have
on us.
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 the filing of reports concerning 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 the regulation of 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 are unable to predict the future cost or impact of complying with those laws.
Our operations are subject to increasingly stringent 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 are required to 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 who are considered responsible for
the release of hazardous substances into the environment. Such liability, which may be imposed for the conduct of others and
for conditions others have caused, includes the cost of remedial action as well as damages to natural resources.
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The federal Endangered Species Act, referred to as 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. For instance, the American Burying Beetle and the Lesser Prairie-Chicken
both have habitat in some areas where we operate or provide services. The U.S. Fish and Wildlife Service (“FWS”) identified
the Lesser Prairie-Chicken as candidate for listing in 1998 and initiated the process to list it as “threatened” or “endangered” in
November 2012. Its habitat is found in Colorado, Kansas, New Mexico, Oklahoma and Texas, and it is listed as “threatened”
by the State of Colorado. On December 17, 2013 the FWS stated that it would make a decision “on its final listing
determination no later than March 30, 2014.” The sage grouse and certain wildflower species, among others, are also species
that have been or are being considered for protected status under the ESA and whose range can coincide with oil and natural gas
production activities. 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, adversely affect our results of operations and financial position.
Climate Regulation. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” or GHGs, may be contributing to warming of the Earth’s atmosphere. As a result there have been a variety
of regulatory developments, proposals or requirements, and legislative initiatives that have been introduced in the United States
(as well as other parts of the World) that are focused on restricting the emission of carbon dioxide, methane, and other
greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an
“air pollutant” under the federal Clean Air Act if it represents a health hazard to the public. On December 7, 2009, the U.S.
Environmental Protection Agency (“EPA”) responded to the Massachusetts, et al. v. EPA decision and issued a finding that the
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 issued 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 occurring in 2010. During 2010, the EPA proposed revisions to these reporting
requirements to apply to all oil and gas production, transmission, processing, and other facilities exceeding certain emission
thresholds. In September and November 2013, the EPA proposed further revisions to record keeping and reporting
requirements. Which likely will be finalized in 2014. The adoption and implementation of any regulations imposing reporting
obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to
reduce emissions of GHGs associated with our operations or could adversely affect demand for the crude oil we gather,
transport, store or otherwise handle in connection with our services. In addition, both President Obama and the Administrator of
the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework
for a clean energy economy, with the Obama Administration supporting an emission allowance system. Past proposed
legislation in Congress has included an economy wide cap and trade program to reduce U.S. greenhouse gas emissions. Some
states are also looking at similar types of laws and regulations.
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. The EPA, has commenced a study of the potential
environmental impacts of hydraulic fracturing, including the impact on drinking water sources and public health, and a
committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices.
Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require
disclosure of the chemicals used in the fracturing process. On November 20, 2013 the U.S. House of Representatives passed a
bill, H.R. 2728, that would block the Department of Interior from regulating hydraulic fracturing in states that already have
their own regulations in place; however, it is uncertain that it will ever be enacted and if enacted, it would likely be subject to a
Presidential veto. In addition, certain states in which we operate, including Texas, Oklahoma, and Wyoming have adopted, and
other states as well as 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, waste disposal, and well
construction requirements on these operations, and possibly even restrict or ban hydraulic fracturing in certain circumstances.
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Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, or
increased operating costs or third party or governmental claims, and could result in additional burdens that could serve to delay
or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations or
increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from
shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could
also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Further, after reviewing extensive comments and making a number of changes to its previously July 28, 2011 proposed
rules, on April 17, 2012 the EPA issued its final rules that subject a wide range of oil and gas operations (production,
processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (NSPS) and
National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs (with the NSPS and NESHAPS published in
the Federal Register on August 16, 2012). The EPA revised the NSPS for volatile organic compounds (VOCs) from leaking
components at onshore gas processing plants and the NSPS for sulfur dioxide emissions from natural gas processing plants.
The EPA also established standards for certain oil and gas operations not covered by existing standards, which will regulate
VOC emissions from gas wells, centrifugal and reciprocating compressors, pneumatic controllers, and storage vessels over a
certain size. The EPA also made revisions to the existing leak detection and repair requirements for the oil and gas production
source category and the natural gas transmission source category and established action limits reflecting most achievable
control for certain previously uncontrolled emission sources. There also are additional testing and related notification, record
keeping and reporting requirements. These changes were effective October 15, 2012.
The EPA regulations also result in the first federal air standards for natural gas wells that are hydraulically fractured.
Refractured gas wells that use the “green completions” will not be considered affected from a federal standpoint. Operators
may choose to flare for now from refractured wells and phase in green completions by January 1, 2015, but any such
refractured well will be considered an affected facility for permitting purposes.
The EPA will be designating nonattainment areas for ozone standards for outdoor quality. These areas will include those
areas with significant oil and gas activities. Nonattainment areas will be required to submit state implementation plans in 2015
and to attain the standard by 2015 and 2018 for areas classified as “Marginal” and “Moderate,” respectively. Areas classified as
“Serious” must attain by 2021. The federal NSPS constitute a federally required minimum level of control. States have the
flexibility to put their own program in place or implement existing programs as long as they are at least as protective as the
federal NSPS.
Consequently, while we have been in the process of assessing and implementing the new EPA requirements as required, at
this time we do not know and cannot predict with any degree of certainty what areas the EPA will designate nonattainment and
what classification will be applied nor what the states may implement for such nonattainment areas which may affect our
business segments and use of hydraulic fracturing practices.
We do not know and cannot predict whether there will be any further proposed legislation or regulations It is possible that
such future laws, regulations, and/or ordinances could result in increasing our compliance costs or additional operating
restrictions as well as those of our customers. It is also possible that such future developments could curtail the demand for
fossil fuels which could adversely affect the demand for our services, which in turn could adversely affect our future results of
operations. Likewise we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation
patterns as a result 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 noted above in connection with our discussion of the regulation of
GHGs and 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.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
Revenues from our Canadian operations during the last three fiscal years, as well as information relating to long-lived
assets attributable to those operations are immaterial. We have no other international operations.
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Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENT 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
activities, events or developments which we expect or anticipate will or may occur in the future, are forward-looking
statements. The words “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 that we file with the SEC in the future will automatically update and supersede
information contained in this report.
These forward-looking statements include, among others, such things as:
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•
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•
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•
•
•
•
•
•
•
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•
•
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•
•
the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
the number of wells we plan to drill or rework;
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;
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 impacting our costs and increasing operating
restrictions or delays as well as other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets; and
the number of wells our oil and natural gas segment plans to drill during the year.
These statements are based on certain assumptions and analyses made by us in light of our experience and our perception
of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in
the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to a
number of risks and uncertainties any one or combination of which could cause our actual results to differ materially from our
expectations and predictions, including:
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•
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 that we pursue;
demand for our land drilling services;
changes in laws or regulations;
decreases or increases in commodity prices; and
other factors, most of which are beyond our control.
You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim
any current 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 the occurrence
of unanticipated events.
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In order to help provide you with a more thorough understanding of the possible effects of some of these influences on
any forward-looking statements made by us, the following discussion outlines some (but not all) of the factors that could in the
future 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.
Contract Drilling Customer Demand. With the exception of the drilling we do for our own account, the demand for our
contract drilling services depends entirely on the needs of third parties. Based on past history, these parties’ requirements are
subject to a number of factors, independent of any subjective factors that directly impact the demand for our drilling rigs,
including the availability of funds to carry out their drilling operations. For many of these parties, even if they have available
funds, their decision to spend those funds is often based on the then current price for oil, NGLs, and natural gas. Other factors
that affect our ability to work our drilling rigs are: the weather which, under certain circumstances, can delay or even cause the
abandonment of a project by an operator; the competition we face in securing the award of drilling contracts; our lack of prior
history in and recognition in a new market area; and the availability of labor to operate our drilling rigs.
Oil, NGLs, and Natural Gas Prices. The prices we receive for our oil, NGLs, and natural gas production have a direct
impact on our revenues, profitability, and cash flow as well as our ability to meet our projected financial and operational goals.
The prices for oil, NGLs, and natural gas are determined on a number of factors beyond our control, including:
•
•
•
•
the demand for and supply of oil, NGLs, and natural gas;
current weather conditions in the continental United States (which can greatly influence the demand and prices for
natural gas at any given time);
the amount and timing of liquid natural gas and liquefied petroleum gas imports and exports; and
the ability of current distribution systems in the United States to effectively meet the demand for oil, NGLs, and
natural gas at any given time, particularly in times of peak demand which may result because of adverse weather
conditions.
Oil prices are extremely sensitive to influences domestic and foreign based on political, social or economic
underpinnings, any one 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,
at times, has tended to increase the volatility associated with these prices resulting in large differences in prices even on a week-
to-week and month-to-month basis. All of these factors, especially when coupled with the fact that much of our product prices
are determined on a daily basis, can, and at times do, lead to wide fluctuations in the prices we receive.
Based on our 2013 production, a $0.10 per Mcf change in what we receive for our natural gas production, without the
effect of hedging, would result in a corresponding $448,000 per month ($5.4 million annualized) change in our pre-tax
operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $268,000 per month
($3.2 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 hedging, would have a $310,000 per month ($3.7 million annualized) change in our pre-tax operating cash flow.
In order to reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter
into hedging arrangements such as swaps and collars. To date, we have hedged part, but not all of our production which only
provides price protection against declines in oil, NGLs, and natural gas prices on the production subject to our hedges, but not
otherwise. Should market prices for the production we have hedged exceed the prices due under our hedges, our hedging
arrangements then expose us to risk of financial loss and limit the benefit to us of those increases in market prices. During
2013, substantially all of our oil, NGLs, and natural gas volumes were sold at market responsive prices. To help manage our
cash flow and capital expenditure requirements, we hedged approximately 90% and 65% of our 2013 average daily production
for oil and natural gas, respectively. A more thorough discussion of our hedging arrangements is contained in the
Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report contained in
Item 7.
Uncertainty of Oil, NGLs, and Natural Gas Reserves; Ceiling Test. There are many uncertainties 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 included 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 gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs, and
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natural gas reserves depend on a number of variable factors, including historical production from the area compared with
production from other producing areas, and assumptions concerning:
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reservoir size;
the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
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 reasons, estimates of the
economically recoverable quantities of oil, NGLs, and natural gas attributable to any particular group of properties,
classifications of those oil, NGLs, and natural gas reserves based on risk of recovery, and 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, oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward
adjustments. Actual production, revenues, and expenditures with respect to 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 included in this report is not necessarily the current market
value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. The use of 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. Actual future net cash flows are also
affected, in part, by the following factors:
•
•
•
•
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, required by the SEC for use 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
the risks associated with our operations or the oil and natural gas industry in general.
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 result in a charge to earnings but would not impact our cash flow
from operating activities. Once incurred, a write-down is not reversible.
As a result of these ceiling test rules, during the quarters ending June 30, 2012 and December 31, 2012, we recorded a
non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax) and $167.7 million pre-tax $104.4 million,
net of tax), respectively. No ceiling test write down was necessary during 2011 or 2013.
If there are declines in the 12-month average prices, we may be required to record a write-down in future periods.
We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including
acquisitions that would be significantly larger than those we have consummated to date. We cannot assure you that we will
successfully consummate any acquisition, that we will be able to acquire producing oil and natural gas properties that contain
economically recoverable reserves or that any acquisition will be profitably integrated into our operations.
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Debt and Bank Borrowing. We have incurred and currently expect to continue to incur substantial capital expenditures
because of the growth in our operations. Historically, we have funded our capital needs through a combination of internally
generated cash flow and borrowings under our bank credit agreement. In 2011 and 2012, we issued $250.0 million (the 2011
Notes) and $400.0 million (the 2012 Notes), respectively, of senior subordinated notes (collectively, the Notes). We have also,
from time to time, obtained funds through equity financing. We currently have, and will continue to have, a certain amount of
indebtedness. At December 31, 2013, we had no outstanding long-term debt under our credit agreement and the amount of the
Notes, net of unamortized discount, was $645.7 million.
Depending on the amount of our debt, the cash flow needed to satisfy that debt and the covenants contained in our bank
credit agreement 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 in the event of a downturn in our
business; 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 would be entitled to accelerate the
payment of the outstanding indebtedness. If that were to occur, we would not have sufficient funds available and probably
would not be able to obtain the financing required to meet our obligations.
The amount of our existing debt, as well as our future debt, if any, is, to a large extent, based on the costs associated with
the projects we undertake at any given time and of our cash flow. Generally, our 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 a degree of control
regarding the timing or the need to incur them. But, in some cases, unforeseen circumstances may arise, such as in the case of
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 that which we had expected or forecasted. Likewise, if our
cash flow should prove to be insufficient to cover our current cash requirements we would need to increase our debt either
through bank borrowings or otherwise.
RISK FACTORS
There are many other factors that could adversely affect our business. The following discussion describes the material
risks currently known to us. However, additional risks that we do not know about or that we currently view as immaterial may
also impair our business or adversely affect 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 as well as produce our oil, NGLs, and natural gas
may be negatively affected.
Historically, oil, NGLs, and natural gas prices have been extremely volatile, with significant increases and significant
price drops being experienced from time to time. In the future, various factors beyond our control will have a significant effect
on oil, NGLs, and natural gas prices. Such factors include, among other things, the domestic and foreign supply of oil, NGLs,
and natural gas, the price of foreign imports, the levels of consumer demand, the price and availability of alternative fuels, the
availability of pipeline capacity, and changes in existing and proposed federal regulation and price controls.
The oil, NGLs, and natural gas markets are also unsettled due to a number of 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
25
demand and transportation and storage capacity. It is possible, however, that some of our wells may in the future 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 available markets has been vigorous and there remains great uncertainty about
prices that purchasers will pay. Oil, NGLs, and natural gas surpluses could result in our inability to market oil, NGLs, and
natural gas profitably, causing us to curtail production and/or receive lower prices for our oil, NGls, and natural gas, situations
which would adversely affect us.
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 market disruptions may result in tight credit markets in the United States. Liquidity in the global-
credit 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. As a result of credit-market turmoil, we may not be able
to obtain debt 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, and future rate of growth depend substantially on prevailing prices for oil,
NGLs, and natural gas. Historically, oil, NGLs, and natural gas prices and markets have been volatile, and they are likely to
continue to be volatile in the future. Any decline in prices in the future would have a negative impact on our future financial
results.
Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply
of and demand for oil, NGLs, and natural gas, market uncertainty, and a variety of additional factors that are beyond our
control. These factors include:
•
•
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•
•
political conditions in oil producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries to agree on prices and their ability
to maintain production quotas;
the price of foreign oil imports;
imports and exports of liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
• U.S. storage levels of oil, NGLs, and natural gas;
• weather conditions;
•
•
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels; 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
26
volatile. Any decrease from current oil, NGLs, and natural gas prices would depress the level of exploration and production
activity. This, in turn, would likely result in a decline in the demand for our drilling services and would have an adverse effect
on our contract drilling revenues, cash flows, and profitability. As a result, the future demand for our drilling services is
uncertain.
The industries in which we operate are highly competitive, and many of our competitors have greater resources than we do.
The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded on the basis
of competitive bids, which may result in 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 on the basis of price and technology, to build 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.
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
substantially greater resources than we do.
The midstream industry is also highly competitive. We compete in areas of gathering, processing, transporting, and
treating natural gas with other midstream companies. We are continually competing with larger midstream companies for
acquisitions and construction projects. Many of our competitors have greater financial resources, human resources, and larger
geographic presence than we do currently.
Continued growth through acquisitions is not assured.
In the past, we have experienced growth in each of our segments, in part, through mergers and acquisitions. The contract
land drilling industry, the exploration and development industry, as well as the gas gathering and processing industry, have
experienced significant consolidation over the past several years, and there can be no assurance that acquisition opportunities
will continue to be available. Additionally, we are likely to continue to face intense competition from other companies for
available acquisition opportunities.
There can be no assurance that we will:
•
•
•
•
be able to identify suitable acquisition opportunities;
have sufficient capital resources to complete additional acquisitions;
successfully integrate acquired operations and assets;
effectively manage the growth and increased size;
• maintain the crews and market share to operate any future drilling rigs we may acquire; or
•
successfully improve our financial condition, results of operations, business or prospects in any material manner as a
result 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 the issuance of 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 a number of 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.
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Our operations have significant capital requirements, and our indebtedness could have important consequences.
We have experienced and may continue to experience substantial capital needs in the growth of our operations. We have
$645.7 million of indebtedness outstanding (net of unamortized discount) under the senior subordinated notes we have issued to
date and in addition, have the right to borrow up to $500.0 million under our credit agreement. As of February 14, 2014, we had
no outstanding borrowings under our credit agreement. Our level of indebtedness, the cash flow needed 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 reacting 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 in the event of a downturn in our
business; 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 result in future reductions in the amount available for
borrowing under our credit agreement, reducing our liquidity, and 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 agreement contain various restrictive covenants
that limit the conduct of our business. In particular, these agreements will 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;
• 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 agreement also requires us to maintain a minimum current ratio and a maximum leverage ratio.
If we fail to comply with the restrictions in the indentures governing our senior subordinated notes, our credit agreement
or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the
related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. If that
occurs, we may not be able to make all of 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.
In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline
depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline,
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resulting eventually in a decrease in oil, NGLs, and natural gas production and lower revenues and cash flow from operations.
Historically, we have succeeded in increasing reserves after taking production into account through exploration and
development. We have conducted these activities on our existing oil and natural gas properties as well as on newly acquired
properties. We may not be able to continue to replace reserves from these activities at acceptable costs. Lower prices of oil,
NGLs, and natural gas may further limit the kinds of reserves that can economically be developed. Lower prices also decrease
our cash flow and may cause us to decrease capital expenditures.
We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including
acquisitions that would be significantly larger than those consummated to date by us. We cannot assure you that we will
successfully consummate any acquisition, that we will be able to 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 will have to pay higher prices and accept greater ownership risks than we have in the past.
Our exploration and production and mid-stream operations involve a high degree of business and financial risk which could
adversely affect us.
Exploration and development involve numerous risks that may result in 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, or
cancellation of drilling operations, including:
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•
•
•
•
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 or delivery crews and the delivery of equipment.
Exploratory drilling is a speculative activity. Although we may disclose our overall drilling success rate, those rates may
decline. Although we may discuss drilling prospects that we have identified or budgeted for, we may ultimately not lease or
drill 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.
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 as a result of many things beyond our control, including:
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•
•
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 the development of 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. As a result, 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 that are
not in our best interests.
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Competition for experienced technical personnel may negatively impact our operations or financial results.
Our continued oil and natural gas segment and mid-stream segment success and the success of 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 extremely intense, particularly when the industry is experiencing
favorable conditions.
Our hedging arrangements might limit the benefit of increases in oil, NGLs, and natural gas prices.
In order to reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter
into hedging arrangements. Our hedging arrangements apply to only a portion of our production and provide only partial price
protection against declines in oil, NGLs, and natural gas prices. These hedging arrangements 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 to be inaccurate.
There are numerous uncertainties 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. Estimates
of economically recoverable oil, NGLs, and natural gas reserves depend on a number of variable factors, including historical
production from the area compared with production from other producing areas, and assumptions concerning:
•
•
•
•
•
the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
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. For these reasons, estimates of the
economically recoverable quantities of oil, NGLs, and natural gas attributable to any particular group of properties,
classifications of those reserves based on risk of recovery, and 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. Accordingly, reserve estimates may
be subject to downward or upward adjustment. Actual production, revenues and expenditures with respect to our reserves will
likely vary from estimates, and those variances may be material.
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. Actual future net cash flows also will be affected by the following 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, which 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 in general.
30
If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may be required 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. Application 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 prior to 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
natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would result in 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 at a later date.
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, equipment, 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 adversely affect our results of
operations.
Our contract drilling operations are subject to many hazards inherent in the drilling industry, including blowouts,
cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment, and damage or loss from
inclement weather. Our exploration and production and mid-stream operations are subject to these and similar risks. Any of
these events could result in 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, drilling contracts provide for the division
of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our drilling
customers by contract for some of these risks. To the extent that we are unable to 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, some risks are not
covered by insurance and we cannot assure you that the insurance we do have or the indemnification agreements we have
entered into will adequately protect us against liability from all of the consequences of the hazards described above. The
occurrence of an event not fully insured or indemnified against, or the failure of a customer to meet its indemnification
obligations, could result in 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.
In addition, we are not the operator of many of our wells. As a result, 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 that are not in
our best interests.
Governmental and environmental regulations could adversely affect 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 total 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 various jurisdictions
where we own or operate. We could incur liability to governments or third parties for discharges of oil, natural gas or other
pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials
31
into the environment in any number of ways including the following:
•
•
•
•
from a well or drilling equipment at a drill site;
from gathering systems, pipelines, transportation facilities, and storage tanks;
damage to oil and natural gas wells resulting from accidents during normal operations; and
blowouts, cratering, and explosions.
Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and
regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. The
current Congress and White House administration may impose or change laws and regulations that will adversely affect our
business. With the trend toward stricter standards, greater regulation, and more extensive permit requirements, our risks related
to environmental matters and our environmental expenditures could increase in the future. In addition, because we acquire
interests in properties that have been 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 some form of 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 serve to limit the amount that we might be able to
get for our future oil, NGLs, and natural gas production. Any future limits on the price of oil, NGLs, and natural gas could also
result in adversely affecting the demand for our drilling services.
Our shareholders’ rights plan and 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. We have also adopted a shareholders’ rights plan. Because of our
shareholders’ rights plan and these provisions of our by-laws, charter, and Delaware law, persons 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. As a result, these provisions may make it more difficult for our shareholders to benefit from
transactions that are opposed by an incumbent board of directors.
New technologies may cause our current 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, including 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 in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently
use or that we may implement in the future may become obsolete or may not work as we expected and we may be adversely
affected.
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
results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse
gasses, including diesel exhaust, could significantly increase our operating costs. Restrictions on emissions could also affect our
customers that (a) use commodities that we carry to produce energy, (b) use significant amounts of energy in producing or
delivering the commodities we carry, or (c) manufacture or produce goods that consume significant amounts of energy or burn
fossil fuels, including 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
32
of energy or emissions reductions could materially affect the markets for the commodities associated with our business, which
in turn could have a material adverse effect on our results of operations, financial condition, and liquidity. Government
incentives encouraging the use of alternative sources of energy could also affect certain of our customers and the markets for
certain of the commodities associated with our business in an unpredictable manner that could alter our business activities.
Finally, we could face increased 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. Any of these factors, individually or in operation with one
or more of the other factors, or other unforeseen impacts of climate change could reduce the amount of business activity we
conduct and have a material adverse effect on our results of operations, financial condition, and liquidity.
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, proximity, and capacity
of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of available capacity on these
systems and facilities could result in 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 adversely affect our ability to produce, gather and, transport oil, NGLs, and natural gas.
The loss of one or a number of our larger customers could have a material adverse effect on our financial condition and
results of operations.
During 2013 , QEP Resources, Inc. and Kodiak Oil and Gas Corp. were our largest drilling customers accounting for
approximately 18% and 10%, respectively, of our total contract drilling revenues. No other third party customer accounted for
10% or more of our contract drilling revenues. Any of our customers may choose not to use our services and the loss of one or a
number of our larger customers could have a material adverse effect on our financial condition and results of operations.
Shortages of completion equipment and services could delay or otherwise adversely affect our oil and natural gas segment’s
operations.
In the past several years, the increase in horizontal drilling activity in certain areas has, at times, resulted in shortages in
the availability of third party equipment and services required for the completion of wells drilled by our oil and natural gas
segment. As a result, we have experienced delays in completing some of our wells. Although we have taken steps to try to
reduce the delays associated with these services, we anticipate that these services will remain in high demand for the immediate
future and could, at times, delay, restrict, 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. The loss of any of these producers could result in a decline in our volumes and revenues.
We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. While some of
these producers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts
on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these producers, as a result
of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we were able to acquire
comparable volumes from other sources.
The counterparties to our commodity derivative contracts may not be able to 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, and 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, as well as to
the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. If one or more of our
counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have
a material adverse effect on our financial condition and results of operations.
33
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.
Derivatives regulation included 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 (the Act) was passed by Congress and
signed into law. The Act contains significant derivatives regulation, including a requirement that certain transactions be cleared
on exchanges and a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. The Act
provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes
a number of defined terms that will be used in determining how this exception applies to particular derivative transactions
and the parties to those transactions.
We use crude oil, NGLs, and natural gas derivative instruments with respect to a portion of our expected production in
order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude
oil and natural gas. As commodity prices increase, our derivative liability positions increase; however, none of our current
derivative contracts require the posting of margin or similar cash collateral when there are changes in the underlying
commodity prices that are referred to in these contracts.
Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer
counterparties for our commodities 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 result in additional costs being passed on to us, thereby decreasing the effectiveness of our
hedges and our profitability.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in 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 apply
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.
Hydraulic-fracturing involves using water, sand, 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, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the
Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory
authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of
Chemicals Act, to provide for federal regulation of hydraulic-fracturing and to require disclosure of the chemicals used in the
hydraulic-fracturing process.
Certain states in which we operate, including Texas, Oklahoma, and Wyoming, have adopted, and other states are
considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well
construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For
example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of
34
certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use
restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic
fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently
conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that
may be significant in nature, experience delays or curtailment in the pursuit of 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 has conducted an investigation of
hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a
variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential
environmental effects of hydraulic fracturing on drinking water and groundwater. In addition, the U.S. Department of Energy is
conducting an investigation into practices the agency could recommend to better protect the environment from drilling using
hydraulic-fracturing completion methods.
Additionally, certain members of the Congress have called upon the U.S. Government Accountability Office to
investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission 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, as well as 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.
Further, after reviewing extensive comments and making a number of changes to its previously July 28, 2011 proposed
rules, on April 17, 2012 the EPA issued its final rules that subject a wide range of oil and gas operations (production,
processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (NSPS) and
National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs (with the NSPS and NESHAPS published in
the Federal Register on August 16, 2012). The EPA revised the NSPS for volatile organic compounds (VOCs) from leaking
components at onshore gas processing plants and the NSPS for sulfur dioxide emissions from natural gas processing plants.
The EPA also established standards for certain oil and gas operations not covered by existing standards, which will regulate
VOC emissions from gas wells, centrifugal and reciprocating compressors, pneumatic controllers, and storage vessels over a
certain size. The EPA also made revisions to the existing leak detection and repair requirements for the oil and gas production
source category and the natural gas transmission source category and established action limits reflecting most achievable
control for certain previously uncontrolled emission sources. There also are additional testing and related notification, record
keeping and reporting requirements. These changes were effective October 15, 2012.
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 the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional
federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a
decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our
financial position, results of operations, and cash flows.
On October 20, 2011, EPA announced a schedule for development of standards for disposal of wastewater produced from
shale gas operations to publicly owned treatment works (POTWs). The regulations will be developed under EPA’s Effluent
Guidelines Program under the authority of the Clean Water Act. EPA anticipates issuing the proposed rules in 2014.
Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be
impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to
dispose of or recycle the water we use at a reasonable cost and in accordance with 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 that are intended to provide coverage for losses solely related
to hydraulic fracturing operations; however, it is possible that our general liability and excess liability insurance policies might
35
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, as well as the specific terms of such policies.
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 dispose of or recycle the water used in our oil and natural gas
segment operations, could adversely impact our operations. Moreover, 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, drilling fluids, and other wastes associated with the exploration,
development or production of oil and natural gas.
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 of the prospects we have identified, and locations that we do 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 that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of
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 be able to 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 include a general requirement 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 the date of
booking. At December 31, 2013, we had 180 proved undeveloped drilling locations. To the extent that 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
be required 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 adversely affect 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 our 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.
Significant declines in oil, NGLs, and natural gas prices may result in a decrease in our borrowing base. The lenders can
unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under our credit agreement. If
outstanding borrowings are in excess of the borrowing base, we must (a) repay the loan in excess of the borrowing base,
(b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments in accordance with our credit
agreement.
Potential listing of species as “endangered” under the federal Endangered Species Act could result in increased costs and
new operating restrictions or delays on our operations and that of our customers, which could adversely affect our
operations and financial results.
The federal Endangered Species Act, referred to as 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. For instance, the American Burying Beetle and the Lesser Prairie-Chicken
both have habitat in some areas where we operate or provide services. The FWS initiated the process to list the Lesser Prairie-
36
Chicken as threatened in November 2012, with a decision expected in March 2014. The sage grouse and certain wildflower
species, among others, are also species that have been or are being considered for protected status under the ESA and whose
range can coincide with oil and natural gas production activities. 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, adversely affect our results of operations and financial position.
Our new drilling rig program to design and build new proprietary BOSS drilling rigs is subject to risks, including delays and
cost overruns, and may not meet our expectations.
We have launched a new drilling rig program to design and build new proprietary 1,500 horsepower AC electric drilling
rigs, which we refer to as BOSS drilling rigs. We anticipate that this new drilling rig will position us to more effectively meet
the demands of our existing customers, result in additional new-build contract opportunities and allow us to compete for the
work of new customers. The construction of new BOSS drilling rigs is subject to the risks of delays or cost overruns inherent
in any large construction project as a result of numerous factors, including the following:
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 rigs, particularly
steel;
• weather interferences;
•
•
•
•
difficulties in obtaining necessary permits or in meeting permit conditions;
unforeseen design and engineering problems;
failure or delay in obtaining acceptance of the rig from our customer; and
failure or delay of third party equipment vendors or service providers.
As we design and build new BOSS drilling rigs, there can be no assurance that we will:
•
•
•
•
obtain additional new-build contract opportunities;
successfully integrate the new rigs with our existing drilling fleet;
successfully deploy the new rigs; or
successfully improve our financial condition, results of operations or prospects as a result of the new rigs.
Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and
production activities. We depend on digital technology to estimate quantities of natural gas, oil and NGL reserves, process and
record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-
party partners. Although we utilize various procedures and controls to mitigate our exposure to such risk, cyber attacks are
evolving and unpredictable. These attacks could include, but are not limited to, malicious software, attempts to gain
unauthorized access to data, other electronic security breaches that could lead to disruptions in critical systems, the
unauthorized release of protected information and the corruption or loss of data. The occurrence of such an attack could lead to
financial losses and have a negative impact on our results of operations. We are not aware that any such breaches have occurred
to date.
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.
37
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, Oklahoma.
Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita
Golightly, Melody Culberson and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas
drilling and spacing units for which the our exploration segment distributes royalty. The Plaintiffs' central allegation is that our
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. We also asserted that the case
should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions 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 Oklahoma Supreme Court for
certiorari and on October 8, 2012, the Plaintiff's petition was denied. The Plaintiffs filed a second request in 2013 to certify a
class of royalty owners that is slightly smaller than their first attempt. We will continue to resist certification using the defenses
described above, as well as new defenses based on the Court of Civil Appeals' decertification of the Plaintiffs' original class
action. The merits of Plaintiffs' claims will remain stayed while class certification issues are pending.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity
Securities
Our common stock trades on the New York Stock Exchange under the symbol “UNT.” The following table identifies the
high and low sales prices per share of our common stock for the periods indicated:
Quarter
First...................................................................................... $
Second ................................................................................. $
Third .................................................................................... $
Fourth .................................................................................. $
2013
2012
High
Low
High
Low
49.68
47.45
47.49
52.81
$
$
$
$
43.75
40.51
42.50
46.34
$
$
$
$
50.82
43.83
46.27
46.97
$
$
$
$
41.53
32.14
34.59
39.73
On February 14, 2014, the closing sale price of our common stock, as reported by the NYSE, was $52.57 per share. On
that date, there were approximately 870 holders of record of our common stock.
We have never declared any 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. Additionally, our bank credit agreement and the Notes prohibit the payment of cash
dividends on our common stock under certain circumstances. For further information regarding our bank credit agreement and
the Notes agreement’s impact on our ability to pay dividends see “Our Credit Agreement and Senior Subordinated Notes” under
Item 7 of this report.
Performance Graph. The following graph and related information shall not be deemed “soliciting material” or be
deemed to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing, except to the
extent that we specifically incorporate it by reference into such filing.
38
Set forth below is a line graph comparing our 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 our peer group which
includes Helmerich & Payne, Inc., Patterson – UTI Energy Inc. and Pioneer Energy Services Corp. 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 2013, 2012, and
2011 activity.
As of and for the Year Ended December 31,
2013
2012
2011
2010
2009
(In thousands except per share amounts)
$ 1,315,123
$ 1,207,503 $
870,671 $
23,176 (2) $
195,867
$
146,484
$
707,188
(55,500) (3)
Revenues(1) ......................................... $ 1,351,850
Net income (loss) ............................... $
184,746
Net income (loss) per common share:
3.83
Basic............................................ $
Diluted......................................... $
3.80
Total assets ......................................... $ 4,022,390
Long-term debt (4)............................... $
645,696
Other long-term liabilities .................. $
158,331
Cash dividends per common share..... $
—
$
$
$
0.48
0.48
$ 3,761,120
$
$
$
716,359
167,545
—
$
$
4.11
(1.18)
(1.18)
$ 3,256,720 $ 2,669,240 $ 2,228,399
3.09 $
3.10 $
4.08
$
$
$
$
$
300,000 $
113,830 $
163,000 $
92,389 $
— $
— $
30,000
81,126
—
_________________________
(1) During the third quarter of 2012, we made the decision to prospectively use mark-to-market accounting for our economic hedges. Previously, we reported
all gains (losses) in oil and natural gas revenues and now we reflect gains (losses) on non-designated hedges and the ineffectiveness from cash flow
hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to
current year presentation.
(2)
(3)
In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write downs of our oil and natural
gas properties of $115.9 million pre-tax ($72.1 million net of tax) and $167.7 million pre-tax ($104.4 million net of tax), respectively.
In March 2009, we incurred a non-cash ceiling test write down of our oil and natural gas properties of $281.2 million pre-tax ($175.1 million net of tax)
due to low commodity prices at quarter-end.
(4) Long-term debt is net of unamortized discount.
40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Please read the following discussion of our financial condition and results of operations in conjunction with the
consolidated financial statements and related notes included in Item 8 of this report.
General
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. This segment explores, develops,
acquires, and produces oil and natural gas properties for our own account.
• Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts
to drill onshore oil and natural gas wells for others and for our own account.
• Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment
buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.
Business Outlook
Our current 2014 capital budget for all of our business segments forecasts a 33% increase over our 2013 capital
expenditures, excluding acquisitions. Our oil and natural gas segment’s capital budget is $718.0 million, a 31% increase over
2013, excluding acquisitions and ARO liability. Our drilling segment’s capital budget is $132.0 million, a 105% increase over
2013. Our plans for 2014 include focusing on our new drilling rig program, a program we launched to design and build a new
proprietary 1,500 horsepower AC electric drilling rig, called the BOSS rig. We also plan to refurbish and upgrade several of our
existing drilling rigs in order that those drilling rigs can be used in horizontal drilling operations. Our mid-stream segment’s
capital budget is $78.0 million, a 19% decrease from 2013, excluding acquisitions. New and continued projects are discussed
further in the Executive Summary.
Our 2014 current capital expenditures budget is based on realized prices for the year of $90.08 per barrel of oil, $29.45
per barrel of NGLs, and $3.77 per Mcf of natural gas. This budget is subject to possible periodic adjustments for various
reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from
internally generated cash flow and, if necessary, borrowings under our credit agreement.
As discussed in other parts of this report, the success of our consolidated business, as well as that of each of our three
operating segments depends, to a large extent, on: the prices we receive for our oil, NGLs, and natural gas production; the
demand for oil, NGLs, and natural gas; and the demand for our drilling rigs which, in turn, influences the amounts we can
charge for the use of those drilling rigs. Although all of our current operations (with the exception of a minor amount of
production in Canada) are located within the United States, events outside the United States can and do have an impact on us
and our industry.
In addition to their direct impact on us, low commodity prices–if sustained for a long period of time–could impact the
liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial
obligations to us.
Executive Summary
Oil and Natural Gas
Fourth quarter 2013 production from our oil and natural gas segment was 4,438,000 barrels of oil equivalent (Boe), a 5%
increase over the third quarter of 2013 and an 8% increase over the fourth quarter of 2012. These increases came primarily from
production associated with new wells. Oil and NGLs production during the fourth quarter of 2013 was 46% of our total
production compared to 41% of our total production during the fourth quarter of 2012.
Fourth quarter 2013 oil and natural gas revenues increased 11% over the third quarter of 2013 and increased 5% over the
fourth quarter of 2012. These increases were primarily due to increases in production.
41
Our NGLs and natural gas prices for the fourth quarter of 2013 increased 21% and 3%, respectively, over the third quarter
of 2013 while our oil prices decreased 1%. Our oil prices increased 3% over the fourth quarter of 2012 while NGLs prices were
essentially unchanged and natural gas prices decreased 12%.
Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 20% over the third quarter
of 2013 and 6% over the fourth quarter of 2012. The increases were primarily attributable to increased production from
developmental drilling and acquisitions.
Operating cost per Boe produced for the fourth quarter of 2013 decreased 13% from the third quarter of 2013 and
decreased 6% from the fourth quarter of 2012. The decrease from the third quarter of 2013 was primarily due to decreased lease
operating expenses (LOE) due to decreased workover expense and lower gross production tax resulting from credits received.
These decreases were somewhat offset by higher saltwater disposal expenses. The decrease from the fourth quarter of 2012 was
primarily due to a decrease in well servicing and transportation charges and a decrease in production taxes due to tax credits.
For 2013 we hedged approximately 90% of our average daily oil production and approximately 65% of our average
natural gas production to help manage our cash flow and capital expenditure requirements.
Currently for 2014 we have hedged approximately 7,250 Bbls per day of oil production and 90,000 Mmbtu per day of
natural gas production. The oil production is hedged by swap contracts for 3,250 Bbls per day and collars for 4,000 Bbls per
day. The swap transactions were done at a comparable average NYMEX prices of $92.35. The collar transactions were done at
a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The natural gas production is hedged by
swaps for 80,000 Mmbtu per day and a collar for 10,000 Mmbtu per day. The swap transactions were done at a comparable
average NYMEX price of $4.24. The collar transaction was done at a comparable average NYMEX floor price of $3.75 and
ceiling price of $4.37. Additionally, we have hedged our March 2014 natural gas basis exposure with basis swaps at an average
price of -$0.05.
In August 2013, we sold some of our Bakken oil and gas properties. The proceeds, net of related expenses, were $57.1
million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013.
Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
During 2013, we drilled 149 wells (91.14 net wells). For 2014, we plan to participate in the drilling of approximately 180
wells. Our 2014 production guidance is approximately 19.2 to 19.7 MMBoe, an increase of 15% to 18% over 2013, although
actual results will continue to be subject to many factors. This segment’s capital budget for 2014 is $718.0 million, a 31%
increase over 2013, excluding acquisitions and ARO liability.
Contract Drilling
The rate at which our drilling rigs were used (“our utilization rate”) for the fourth quarter 2013 was 53%, compared to
51% and 50% for the third quarter of 2013 and the fourth quarter of 2012, respectively.
Dayrates for the fourth quarter of 2013 averaged $19,630, a 1% decrease from both the third quarter of 2013 and the
fourth quarter of 2012. The decreases were primarily due to the expiration of certain contracts during 2013 that had higher rates.
Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2013 increased
3% over the third quarter of 2013 and was essentially unchanged from the fourth quarter of 2012. For both comparative periods
utilization slightly increased.
Operating cost per day for the fourth quarter of 2013 decreased 3% from the third quarter of 2013 and 13% from the
fourth quarter of 2012. The decreases were primarily due to decreases in direct rig expenses and workers' compensation related
costs.
Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. Part of this
shift included operators moving to shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas.
These shallower plays tend to use drilling rigs with lower horsepower which have lower dayrates and margins. As methods for
drilling horizontal wells have improved, demand to drill deeper and longer horizontal wells has once again strengthened
demand for higher horsepower rigs. All of these factors ultimately affect the demand and mix of the type of drilling rigs used by
our customers.
42
As of December 31, 2013, we had 23 term drilling contracts with original terms ranging from six months to three years.
Twenty-two of these contracts are up for renewal in 2014, seven in the first quarter, ten in the second quarter, and five in the
fourth quarter and one is up for renewal in 2015. Term contracts may contain a fixed rate for the duration of the contract or
provide for rate adjustments within a specific range from the existing rate.
In the second quarter of 2013, we sold one of our 2,000 horsepower electric drilling rigs. During the third and fourth
quarters of 2013, we sold three additional 2,000 horsepower and one 3,000 horsepower electric drilling rigs. All of these sales
were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party in
the first quarter of 2014 all of which were classified as assets held for sale at December 31, 2013. The proceeds from these
various sales will be used in our new drilling rig program we launched to design and build a new proprietary 1,500 horsepower,
AC electric drilling rig, called the BOSS rig. We anticipate the BOSS drilling rig will position us to more effectively meet the
demands of our existing customers as well as allowing us to compete for the work of new customers.
Our anticipated 2014 capital expenditures for this segment are $132.0 million, a 105% increase over 2013. The first
BOSS drilling rig will be operational the first quarter of 2014 and will work initially for our oil and natural gas segment. Two
additional BOSS drilling rigs are contracted to third party operators and are anticipated to be placed into service in the second
and third quarters of 2014.
Mid-Stream
Fourth quarter 2013 liquids sold per day increased 12% over the third quarter of 2013 and increased 49% over the fourth
quarter of 2012. During the third quarter 2012, one of our producers completed construction of their own processing plant and
moved their volumes off our system resulting in decreases in liquids sold, gas gathered, and gas processed. In addition, during
the fourth quarter of 2012, certain processing plants were rejecting ethane due to weak ethane prices. For the fourth quarter of
2013, gas processed per day increased 3% over the third quarter of 2013 and increased 13% over the fourth quarter of 2012. We
upgraded several of our existing processing facilities and added processing plants which was the primary reason for increased
volumes. For the fourth quarter of 2013, gas gathered per day decreased 4% from the third quarter of 2013 and increased 12%
over the fourth quarter of 2012. The decrease during the fourth quarter of 2013 was primarily due to the transfer of one system
to the oil and natural gas segment. The increase over the fourth quarter of 2012 was primarily from well connects throughout
2013.
NGLs prices in the fourth quarter of 2013 increased 1% over the prices received in both the third quarter of 2013 and the
fourth quarter of 2012. Because certain of the contracts used by our mid-stream segment for NGLs transactions are percent of
proceeds (POP) contracts – under which we receive a share of the proceeds from the sale of the NGLs– our revenues from those
POP contracts fluctuate based on the prices of NGLs.
Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2013 decreased 4% from
the third quarter of 2013 and increased 89% over the fourth quarter of 2012. The decrease from the third quarter of 2013 was
primarily due to higher costs associated with gas purchased and the increase over the fourth quarter of 2012 was primarily due
to increased revenues from gas liquids sold. Total operating cost for our this segment for the fourth quarter of 2013 increased
13% over the third quarter of 2013 and increased 40% over the fourth quarter of 2012 due primarily to the cost of gas
purchased.
After relocating two processing plants from our Hemphill County, Texas facility to our new Reno County, Kansas facility,
we now have the capacity to process 135 MMcf per day of our own and third party Granite Wash natural gas production at our
Hemphill facility. We completed two pipeline extension projects for a total cost of approximately $5.7 million in the fourth
quarter of 2013. These extensions will connect additional production from our oil and natural gas segment to this system.
We have completed construction of a new gathering and processing facility in Reno County, Kansas. This new system
consists of approximately 20 miles of gathering pipeline and two processing plants that were relocated from our Hemphill
facility which included a five MMcf per day refrigerated JT plant skid and a 20 MMcf per day turbo expander plant skid. Both
plant skids are installed and operational. We began gathering gas at this facility during the second quarter of 2013
and processing gas in the third quarter of 2013.
At our Cashion facility located in central Oklahoma, we completed the extension of our gathering system approximately
three miles at a capital cost of $2.8 million. This extension will allow us to gather additional production from active producers
43
in the area. We installed a new 25 MMcf per day high efficiency turbo-expander processing plant at this facility that became
operational in March 2012. With the installation of this additional plant, our total processing capacity increased to
approximately 45 MMcf per day at our Cashion facility.
At our Perkins facility located in central Oklahoma, we completed the installation and upgrade of an 8 MMcf per day
processing skid which became operational in the first quarter of 2013. With this new plant skid operational, our total processing
capacity is now 18 MMcf per day.
In the Mississippian play in north central Oklahoma, our Bellmon system consists of approximately 185 miles of pipeline,
which includes a 26-mile extension to connect our existing Remington facility, a 20-mile NGL line and two owned natural gas
processing plants. In the first quarter of 2013, we completed the installation of an owned 30 MMcf per day cryogenic
processing plant, which allowed us to take out of service the original rental processing plant. After this owned processing plant
was installed and operational, our total processing capacity at this facility was 55 MMcf per day including the original rental
processing plant. Due to anticipated increased volumes, we also completed the installation of a new 60 MMcf per day
processing plant in the first quarter of 2014. With both of these owned processing plants operational we will have capacity to
process 90 MMcf per day at this facility.
In the Appalachian region, in the fourth quarter of 2012, construction was completed on the first phase of our Pittsburgh
Mills gathering facility in Allegheny and Butler Counties, Pennsylvania. The first phase of this project consists of
approximately 14 miles of gathering pipeline. In the first quarter of 2013, the related compressor station was completed and
operational. We currently have 19 wells connected to this gathering system with plans to continue to add wells as they are
drilled. Preliminary activity is underway for the planned expansion of this pipeline into Butler County, Pennsylvania. Right of
way has been acquired and construction is scheduled to begin in the second quarter of 2014. This expansion is expected to be
completed by the end of 2014. We completed the construction of the Brookfield gathering system, a new gathering system in
north central Pennsylvania. It became operational in the second quarter of 2013.
In December 2012, we had a $1.2 million write-down of our Erick system. There was no volume from the wells
connected to this system, the compressor and related surface equipment have been removed from this location and there is
no future activity anticipated from this gathering system.
Anticipated 2014 capital expenditures for this segment are $78.0 million, a 19% decrease from 2013, excluding
acquisitions.
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 of these policies require us to make difficult, subjective, and complex judgments in the course of making
estimates of matters that are inherently imprecise. Some accounting policies involve judgments and uncertainties to such an
extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions,
or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates
on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In
the following discussion we will attempt to explain the nature of these estimates, assumptions and judgments, as well as the
likelihood that materially different amounts would be reported in our financial statements under different conditions or using
different assumptions.
44
The following table lists the critical accounting policies, estimates and assumptions that can have a significant impact on
the application of 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
Estimates or Assumptions
• Oil, NGLs, and natural gas reserves,
estimates, and related present value
of future net revenues
• Valuation of unproved properties
• Estimates of future development
costs
Accounts Affected
• Oil and natural gas properties
• Accumulated depletion, depreciation
and amortization
• Provision for depletion, depreciation
and amortization
• Impairment of oil and natural gas
• Derivatives measured at fair value
properties
• Long-term debt and interest expense
Accounting for ARO for oil, NGLs, and
natural gas properties
• Cost estimates related to the
plugging and abandonment of wells
• Oil and natural gas properties
• Accumulated depletion, depreciation
• Timing of cost incurred
and amortization
Accounting for impairment of long-
lived assets
• Forecast of undiscounted estimated
future net operating cash flows
• Provision for depletion, depreciation
and amortization
• Current and non-current liabilities
• Operating expense
• Drilling and mid-stream property
and equipment
• Accumulated depletion, depreciation
and amortization
• Provision for depletion, depreciation
and amortization
• Other intangible assets
Goodwill
• Forecast of discounted estimated
future net operating cash flows
• Terminal value
• Weighted average cost of capital
• Goodwill
Turnkey and footage drilling contracts
• Estimates of costs to complete
turnkey and footage contracts
• Revenue and operating expense
• Current assets and liabilities
Accounting for value of stock
compensation awards
• Estimates of stock volatility
• Estimates of expected life of awards
granted
• Estimates of rates of forfeitures
• Oil and natural gas properties
• Shareholder’s equity
• Operating expenses
• General and administrative expenses
Accounting for derivative instruments
and hedging
• Hedges measured for effectiveness
• Current and non-current derivative
and ineffectiveness
• Non-qualifying and qualifying
derivatives measured at fair value
assets and liabilities
• Other comprehensive income as a
component of equity
• Oil and natural gas revenue
• Gain (loss) on derivatives not
designated as hedges and hedge
ineffectiveness, net
Significant Estimates and Assumptions
Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. The determination of 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. The degree of accuracy of these estimates depends on a number of factors, including,
the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual
45
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, 2013 included those we projected that comprised 84% of the total
proved developed discounted future net income and 91% of the total proved undeveloped discounted future net income based
on the unescalated pricing policy of the SEC. Included in Part I, Item 1 of this report are the qualifications of our independent
petroleum engineering firm and our personnel responsible for the preparation of our reserve reports.
As a general rule, the degree of accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve
classification and the related accumulation of available data, as shown in the following table:
Type of Reserves
Nature of Available Data
Degree of Accuracy
Proved undeveloped
Data from offsetting wells, seismic data
Less accurate
Proved developed non-producing The above as well as logs, core samples, well tests, pressure data More accurate
Proved developed producing
The above as well as production history, pressure data over time Most accurate
Assumptions as to future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in
estimating oil, NGLs, and natural gas 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 what is
known as the economic limit (that point when the projected costs and expenses of producing recoverable oil, NGLs, and natural
gas reserves is greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the
estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is extremely 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 our provision for DD&A on a units-of-production method. Each quarter, we use the following 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
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If reserve estimates for a
property or group of properties are revised downward in the future, the DD&A rate will increase as a result of the revision.
Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease. Based on our 2013 production level of 16.7
MMBoe, a decrease in the amount of our 2013 oil, NGLs, and natural gas reserves by 5% would increase our DD&A rate by
$0.72 per Boe and would decrease pre-tax income by $12.0 million annually. Conversely, an increase in our 2013 oil, NGLs,
and natural gas reserves by 5% would decrease our DD&A rate by $0.66 per Boe and would increase pre-tax income by $11.0
million annually.
Our DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities
adjusted for current period production.
As noted, we account for our oil and natural gas exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition, exploration, and development of oil and natural gas
properties are capitalized. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to
the lower of unamortized cost 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 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.
46
The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil,
NGLs, and natural gas prices 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, increases the chance
of a ceiling test write-down. Based on the application of 12-month 2013 average unescalated prices of $96.94 per barrel of oil,
$41.03 per barrel of NGLs, and $3.67 per Mcf of natural gas, then adjusted for price differentials, for the estimated life of the
respective properties, the unamortized cost of our oil and natural gas properties did not exceed the ceiling of our proved oil,
NGLs, and natural gas reserves. If there are declines in the 12-month average prices, we may be required to record a write-
down in future periods.
Derivative instruments qualifying as cash flow hedges are included in the computation of limitation on capitalized costs.
Our cash flow hedges expired as of December 31, 2013 and no longer effect this computation. Our oil and natural gas hedging
is discussed in Note 13 of the Notes to our Consolidated Financial Statements.
We use the sales method for recording natural gas sales. This method allows for the recognition of revenue, which may be
more or less than our 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 an imbalance are not material.
Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with
the retirement of assets having a long life. In our case, when the reserves in each of our oil or gas wells deplete or otherwise
become uneconomical, we are required to 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 do not have any assets restricted for the purpose
of settling these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs
taking into account the type of well (either oil or natural gas), the depth of the well and physical location of the well to
determine the estimated plugging costs.
Accounting for Impairment of Long-Lived Assets. 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. Realization of the carrying value of property and
equipment is reviewed for possible impairment whenever events or changes in circumstances suggest that these carrying
amounts may not be recoverable. Assets are 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 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. An estimate of the impact to our
earnings if other assumptions had been used is not practicable because of the significant number of assumptions that would be
involved in the estimates. In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system. There
was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from
this location and there is no future activity anticipated from this gathering system. No significant impairment was recorded at
December 31, 2013 or 2011.
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. An
annual impairment test is performed in the fourth quarter to determine whether the fair value has decreased and additionally
when events indicate an impairment may have occurred. Goodwill is all related to our drilling segment, and accordingly, the
impairment test is 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. No goodwill impairment was recorded at December 31,
2013, 2012, or 2011.
Turnkey and Footage Drilling Contracts. Because our contract drilling operations do not bear the risk of completion of
a well being drilled under a “daywork” contract, we recognize revenues and expense generated under “daywork” contracts as
the services are performed. Under “footage” and “turnkey” contracts we bear the risk of completion of the well, so revenues
and expenses are recognized when the well is substantially completed. Substantial completion is determined when the well bore
reaches the depth specified in the contract. The entire amount of a loss, if any, is recorded when the loss can be reasonably
determined, however, any profit is recorded only at the time the well is finished. The costs of drilling contracts uncompleted at
the end of the reporting period (which includes expenses incurred to date on “footage” or “turnkey” contracts) are included in
other current assets. We did not drill any wells under turnkey or footage contracts in 2013, 2012, or 2011.
47
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. The determination of 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. For our economic hedges that we did not apply cash flow
accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported
in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Consolidated Statements of Income.
The commodity derivative instruments we had under cash flow accounting expired as of December 2013. Previous changes in
the fair value of derivatives designated as cash flow hedges, to the extent they were effective in offsetting cash flows
attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item
was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value resulting from
ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.
New Accounting Standards
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax
Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the
financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a
tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an
unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The
amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15,
2013. Early adoption is permitted. The amendments should be applied prospectively to all unrecognized tax benefits that exist
at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or
results of operations when adopted.
Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge
Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap
Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S.
Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The
amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July
17, 2013. We do not have any interest rate hedges at this time.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued
ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that
companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant
amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release
due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g.,
interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years,
beginning after December 15, 2012. We chose to present the information in a single note (Note 15 of the Notes to our
Consolidated Financial Statements).
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU
2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—
Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase
agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset
in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or
similar agreement.
Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a
legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or
bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure
draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in
response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead,
48
the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare
financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose
information about offsetting and related arrangements to enable users of its financial statements to understand the effect of
those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods
beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures
required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting
agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial
position in Note 14 of the Notes to our Consolidated Financial Statements.
Financial Condition and Liquidity
Summary.
Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit
agreement. The principal factors determining the amount of our cash flow are:
•
•
•
•
the demand for and the dayrates we receive for our drilling rigs;
the quantity of oil, NGLs, and natural gas we produce;
the prices we receive for our oil, NGLs, and natural gas production; and
the margins we obtain from our natural gas gathering and processing contracts.
The following is a summary of certain financial information as of December 31, and for the years ended December 31:
2013
2012
(In thousands except percentages)
2011
Working capital........................................................................................ $
(31,542)
Long-term debt (2) .................................................................................... $
645,696
Shareholders’ equity................................................................................ $ 2,173,392
Ratio of long-term debt to total capitalization.........................................
Net income............................................................................................... $
Net cash provided by operating activities ............................................... $
Net cash used in investing activities........................................................ $
Net cash provided by (used in) financing activities ................................ $
674,331
(579,180)
(77,532)
184,746
23%
$
$
(11,495)
716,359
$ 1,974,301
$
15,715
$
300,000
(1) $ 1,947,017
27% (1)
13%
$
23,176
$
690,911
$ (1,079,042)
388,270
$
(1) $
$
$
$
195,867
608,455
(768,236)
159,257
_________________________
(1)
In June and December 2012, we incurred a non-cash ceiling test write down of our oil and natural gas properties of $115.9 million and $167.7 million pre-
tax ($72.1 million and $104.4 million, net of tax), respectively, due to low 12-month average commodity prices at quarter-end. The write downs impacted
our 2012 shareholders’ equity, ratio of long-term debt to total capitalization and net income. There was no impact on our compliance with the covenants
contained in our credit agreement.
(2) Long-term debt is net of unamortized discount.
49
The following 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 hedges ................................. $
Average NGLs price per barrel received......................................................... $
Average NGLs price per barrel received excluding hedges............................ $
Average natural gas price per mcf received.................................................... $
Average natural gas price per mcf received excluding hedges ....................... $
Contract Drilling:
Average number of our drilling rigs in use during the period.........................
Total number of drilling rigs owned at the end of the period..........................
Average dayrate............................................................................................... $
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...........................................................................
2013
2012
2011
3,360
3,914
56,757
95.06
95.18
31.79
31.79
3.32
3.33
65.0
121
$
$
$
$
$
$
3,279
2,796
48,930
92.60
90.19
31.58
30.70
3.37
2.53
73.9
127
$
$
$
$
$
$
2,511
2,239
44,104
87.18
93.49
43.64
44.44
4.26
3.78
76.1
127
19,646
$
19,949
$
18,842
309,554
140,584
543,602
38
15
250,290
133,987
542,578
39
14
188,569
92,940
412,064
35
10
At December 31, 2013, we had unrestricted cash totaling $18.6 million and had borrowed none of the $500.0 million we
currently have available under our credit agreement. Our credit agreement is used primarily for working capital and capital
expenditures.
On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of registered senior subordinated
notes due 2021 (the 2011 Notes) which bear interest at a rate of 6.625% per year. . The 2011 Notes were issued at par and
mature on May 15, 2021. The net proceeds were used to repay the $220.3 million we had outstanding as of May 18, 2011 under
the credit agreement. The remaining proceeds were used for general working capital purposes.
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of unregistered senior
subordinated notes (the 2012 Notes) due May 15, 2021, which bear interest at a rate of 6.625% per year. The 2012 Notes were
sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance
the acquisition of oil and natural gas properties from Noble. We incurred $8.7 million of fees that are being amortized as debt
issuance cost over the life of the 2012 Notes.
On November 13, 2012, we registered with the SEC on Form S-4 an offer to exchange the 2012 Notes for additional
notes with materially identical terms to our existing 2011 Notes. The 2011 Notes were registered under the Securities Act. On
January 7, 2013, the exchange of the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now
registered and treated as a single series of debt securities with the 2011 Notes, bringing the total to $650.0 million aggregate
principal amount of 6.625% senior subordinated notes (the Notes). The interest is payable semi-annually (in arrears) on May 15
and November 15 of each year, and the Notes will mature on May 15, 2021.
Working Capital
Typically, our working capital balance varies primarily because of the timing of our trade accounts receivable and
accounts payable and from the fluctuation in current assets and liabilities associated with the mark to market value of our
hedging activity. We had negative working capital of $31.5 million and $11.5 million as of December 31, 2013 and 2012,
respectively, and positive working capital of $15.7 million as of December 31, 2011. The effect of our derivatives decreased
50
working capital by $5.0 million as of December 31, 2013, and increased working capital by $9.6 million and $18.0 million as of
December 31, 2012, and 2011, respectively.
Impact of Prices for Our Oil, NGLs, and Natural Gas
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. All of these factors are beyond our control and we cannot predict nor measure their future influence on
the prices we will receive.
Based on our 2013 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the
effect of hedging, would result in a corresponding $448,000 per month ($5.4 million annualized) change in our pre-tax
operating cash flow. Our 2013 average natural gas price was $3.32 compared to an average natural gas price of $3.37 for 2012
and $4.26 for 2011. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $268,000 per month
($3.2 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 hedging, would have a $310,000 per month ($3.7 million annualized) change in our pre-tax operating cash flow
based on our production in 2013. Our 2013 average oil price per barrel was $95.06 compared with an average oil price of
$92.60 in 2012 and $87.18 in 2011, and our 2013 average NGLs price per barrel was $31.79 compared with an average NGLs
price of $31.58 in 2012 and $43.64 in 2011.
Because commodity prices have an effect on the value of our oil, NGLs, and natural gas reserves, declines in those prices
can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the
semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is
based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our
planned capital projects.
Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers
under contracts with terms generally ranging anywhere from one month to five years. Our oil production is sold to independent
marketing firms generally under six month contracts.
Contract Drilling
Many factors influence the number of drilling rigs we are working at any given time as well as 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 rig personnel in the Rocky Mountain
division during the first quarter of 2012. We do not currently anticipate any further increases.
Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. Part of this
shift included operators moving to shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas.
These shallower plays tend to use drilling rigs with lower horsepower which have lower dayrates and margins. As methods for
drilling and completing horizontal wells have improved, demand to drill deeper and longer horizontal wells has once again
strengthened demand for qualified higher horsepower rigs. All of 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 have
an impact on our future dayrates. For 2013, our average dayrate was $19,646 per day compared to $19,949 per day for 2012.
Our average number of drilling rigs used in 2013 was 65.0 (52%) compared with 73.9 (58%) in 2012. Based on the average
utilization of our drilling rigs during 2013, a $100 per day change in dayrates has a $6,500 per day ($2.4 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 to be associated with the
acquisition of an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in
our income statement, 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
51
parties. We eliminated revenue of $64.3 million, $49.6 million, and $52.2 million for 2013, 2012, and 2011, respectively, from
our contract drilling segment and eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6 million
during 2013, 2012, and 2011, respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012, and
2011, respectively, as a reduction to the carrying value of our oil and natural gas properties.
Mid-Stream
This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates
three natural gas treatment plants, 15 processing plants, 38 gathering systems, and approximately 1,500 miles of pipeline. Its
operations are located 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 2013, 2012, and 2011
this segment purchased $83.0 million, $68.2 million, and $71.5 million, respectively, of our oil and natural gas segment's
natural gas and NGLs production, and provided gathering and transportation services of $8.0 million, $5.1 million, and $4.6
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.
Our mid-stream segment gathered an average of 309,554 Mcf per day in 2013 compared to 250,290 Mcf per day in 2012
and 188,569 Mcf per day in 2011. It processed an average of 140,584 Mcf per day in 2013 compared to 133,987 Mcf per day
in 2012 and 92,940 Mcf per day in 2011, and sold NGLs of 543,602 gallons per day in 2013 compared to 542,578 gallons per
day in 2012 and 412,064 gallons per day in 2011. Gas gathering volumes per day in 2013 increased primarily from new wells
connected to our systems throughout 2013 along with the addition of new systems and the expansion of existing systems.
Volumes processed and NGLs sold both increased primarily due to the addition of new wells connected, recent upgrades to
several existing processing facilities, and the addition of new processing facilities.
Our Credit Agreement and Senior Subordinated Notes
Credit Agreement. Under our Senior Credit Agreement (credit agreement) the amount available to be borrowed is the
lesser of the amount we elect (from time to time) as the commitment amount ($500.0 million) or the value of the borrowing
base as determined by the lenders ($800.0 million), but in either event not to exceed the maximum credit agreement amount of
$900.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed.
The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement
matures as of September 13, 2016. We paid $1.5 million in origination, agency, syndication, and other related fees when the
credit agreement was amended on September 5, 2012. We are amortizing these fees over the life of the credit agreement. At
both December 31, 2013 and February 14, 2014, there were no borrowings.
The current lenders under our credit agreement and their respective participation interests are as follows:
Lender
BOK (BOKF, NA, dba Bank of Oklahoma)..........................................................................................
BBVA Compass Bank............................................................................................................................
Bank of Montreal ...................................................................................................................................
Bank of America, N.A. ..........................................................................................................................
Comerica Bank.......................................................................................................................................
Crédit Agricole Corporate and Investment Bank, London Branch........................................................
Wells Fargo Bank, National Association...............................................................................................
Canadian Imperial Bank of Commerce..................................................................................................
The Bank of Nova Scotia.......................................................................................................................
Participation
Interest
17 %
17 %
15 %
15 %
8 %
8 %
8 %
8 %
4 %
100%
The amount of the borrowing base, 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. There was no
change to the borrowing base as of the October 1, 2013 redetermination. We or the lenders may request a onetime special
52
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 credit agreement.
At our election, any part of the outstanding debt under the 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 1.75% 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 agreement,which cannot be less
than LIBOR plus 1.00%. Interest is payable at the end of each month, and the principal may be repaid in whole or in part at
anytime, without a premium or penalty.
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 credit agreement prohibits, among other things:
•
•
•
•
•
the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net
income for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except in favor of our lenders.
The 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; and
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, 2013, we were in compliance with the covenants contained in the credit agreement.
6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million aggregate principal
amount of registered senior subordinated notes due 2021 (the 2011 Notes) which bear interest at a rate of 6.625% per year. The
Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after
deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the
Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on
May 18, 2011. The remaining proceeds were used for general working capital purposes.
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of unregistered senior
subordinated notes (the 2012 Notes) due May 15, 2021, which bear interest at a rate of 6.625% per year. The 2012 Notes were
sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance
the acquisition of oil and natural gas properties from Noble. We incurred $8.7 million of fees that are being amortized as debt
issuance cost over the life of the 2012 Notes.
On November 13, 2012, we registered with the SEC on Form S-4 an offer to exchange the 2012 Notes for additional
notes with materially identical terms to our existing 2011 Notes, which were registered under the Securities Act. On January 7,
2013, the exchange of the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now registered and
treated as a single series of debt securities with the 2011 Notes, bringing the total to $650.0 million aggregate principal amount
of 6.625% senior subordinated notes (the Notes). The interest is payable semi-annually (in arrears) on May 15 and
November 15 of each year, and the Notes will mature on May 15, 2021.
The notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the
parent company, has no independent assets or operations. The guarantees registered under the registration statement are full and
unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of
the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant
defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the governing Indenture. Any
subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive
funds from its subsidiaries through dividends, loans, advances, or otherwise.
53
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 thereto
dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by that the Second
Supplemental Indenture thereto dated as of January 7, 2013, between us, the Guarantors and the Trustee, establishing the terms
and providing for the issuance of the Notes (as supplemented, the 2011 Indenture). The discussion of the Notes in this report is
qualified by and subject to the actual terms of the 2011 Indenture .
On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices,
plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original
principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of
the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original
principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we
may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole”
premium, plus accrued and unpaid interest, if any, to the redemption date. 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 Indenture
contains customary events of default. The Indenture 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, 2013.
Capital Requirements
Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this
segment are discretionary and directed toward future 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 under the circumstances involved, all of which
provide us with a large degree of flexibility in deciding when and if to incur these costs. We completed drilling 149 gross wells
(91.14 net wells) in 2013 compared to 171 gross wells (80.08 net wells) in 2012, and 160 gross wells (82.42 net wells) in 2011.
Our 2013 total capital expenditures for our oil and natural gas segment, excluding an $18.0 million reduction in the ARO
liability, totaled $549.2 million compared to 2012 capital expenditures of $521.2 million (excluding a $45.1 million ARO
liability and $579.0 million for acquisitions), and 2011 capital expenditures of $514.8 million (excluding a $23.3 million ARO
liability and $50.0 million for acquisitions).
For all of 2014, we plan to participate in drilling approximately 180 wells and estimate our total capital expenditures
(excluding any possible acquisitions) for our oil and natural gas segment will be approximately $718.0 million. Whether we are
able to drill all of those wells is dependent on a number of 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, and the efforts of outside industry partners.
On July 20, 2011, we acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in
cash, after post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver,
Harper, and Ellis Counties, Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved
properties and $3.9 million for acreage.
On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash from an unaffiliated
seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and
Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The acquisition also included
approximately 55,000 net acres of which 96% was held by production.
On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble. After final closing
adjustments, the acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various
other plays in western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6 million.
Also in September 2012, we sold our interest in certain Bakken properties. The proceeds, net of related expenses, were
$226.6 million. In addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas for
approximately $44.1 million. In August 2013, we sold additional Bakken property interests. The proceeds, net of related
54
expenses, were $57.1 million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7
million for 2013. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss
recognized.
Drilling Dispositions, Acquisitions, and Capital Expenditures. During 2011, we were awarded two additional new build
drilling rig contracts for 1,500 horsepower, diesel-electric drilling rigs. One was placed into service during the fourth quarter of
2011 and the other was placed in service during the first quarter of 2012, both in Wyoming.
During the first quarter of 2012, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third-party.
Additionally, in the second quarter we placed another new 1,500 horsepower, diesel-electric drilling rig to work in North
Dakota under a three year contract.
During the third quarter of 2012, we had a fire on one of our drilling rigs located in the mid-continent region. The net
book value of the damaged equipment was $3.2 million. All of the net book value of the damaged equipment was recoverable
from insurance proceeds. No personnel were injured in this incident.
In the second quarter of 2013, we sold one of our 2,000 horsepower electric drilling rigs. During the third and fourth
quarters of 2013, we sold three additional 2,000 horsepower and one 3,000 horsepower electric drilling rigs. All of these sales
were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party in
the first quarter of 2014 all of which were classified as assets held for sale at December 31, 2013. The proceeds from these
various sales will be used in our new drilling rig program we launched to design and build a new proprietary 1,500 horsepower,
AC electric drilling rig, called the BOSS rig. We anticipate the BOSS drilling rig will position us to more effectively meet the
demands of our existing customers as well as allowing us to compete for the work of new customers.
The first BOSS drilling rig will be operational the first quarter of 2014 and will work initially for our oil and natural gas
segment. Two additional BOSS drilling rigs are contracted to third party operators and are anticipated to be placed into service
in the second and third quarters of 2014.
Our anticipated 2014 capital expenditures for this segment are $132.0 million. We have spent $64.3 million for capital
expenditures during 2013 compared to $77.5 million in 2012, and $162.2 million in 2011.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. After relocating two processing plants from our
Hemphill County, Texas facility to our new Reno County, Kansas facility, we now have the capacity to process 135 MMcf per
day of our own and third party Granite Wash natural gas production at our Hemphill facility. We completed two pipeline
extension projects for a total cost of approximately $5.7 million in the fourth quarter of 2013. These extensions will connect
additional production from our oil and natural gas segment to this system.
We have completed construction of a new gathering and processing facility in Reno County, Kansas. This new system
consists of approximately 20 miles of gathering pipeline and two processing plants that were relocated from our Hemphill
facility which included a five MMcf per day refrigeration plant skid and a 20 MMcf per day turbo expander plant skid. Both
plant skids are installed and operational. We began gathering gas at this facility during the second quarter of 2013
and processing gas in the third quarter of 2013.
At our Cashion facility located in central Oklahoma, we completed the extension of our gathering system approximately
three miles at a capital cost of $2.8 million. This extension will allow us to gather additional production from active producers
in the area. We installed a new 25 MMcf per day high efficiency turbo-expander processing plant at this facility that became
operational in March 2012. With the installation of this additional plant, our total processing capacity increased to
approximately 45 MMcf per day at our Cashion facility.
At our Perkins facility located in central Oklahoma, we completed the installation and upgrade of an 8 MMcf per day
processing skid which became operational in the first quarter of 2013. With this new plant skid operational, our total processing
capacity is now 18 MMcf per day.
In the Mississippian play in north central Oklahoma, our Bellmon system consists of approximately 185 miles of pipeline,
which includes a 26-mile extension to connect our existing Remington facility, a 20-mile NGL line and two owned natural gas
processing plants. In the first quarter of 2013, we completed the installation of an owned 30 MMcf per day cryogenic
processing plant, which allowed us to take out of service the original rental processing plant. After this owned processing plant
was installed and operational, our total processing capacity at this facility was 55 MMcf per day including the original rental
55
processing plan. Due to anticipated increased volumes, we also completed the installation of a new 60 MMcf per day
processing plant in the first quarter of 2014. With both of these owned processing plants operational we will have capacity to
process 90 MMcf per day at this facility.
In the Appalachian region, in the fourth quarter of 2012, construction was completed on the first phase of our Pittsburgh
Mills gathering facility in Allegheny and Butler Counties, Pennsylvania. The first phase of this project consists of
approximately 14 miles of gathering pipeline. In the first quarter of 2013, the related compressor station was completed and
operational. We currently have 19 wells connected to this gathering system with plans to continue to add wells as they are
drilled. Preliminary activity is underway for the planned expansion of this pipeline into Butler County, Pennsylvania. Right of
way has been acquired and construction is scheduled to begin in the second quarter of 2014. This expansion is expected to be
completed by the end of 2014. We completed the construction of the Brookfield gathering system, a new gathering system in
north central Pennsylvania. It became operational in the second quarter of 2013.
In December 2012, we had a $1.2 million write-down of its Erick system. There was no volume from the wells
connected to this system, the compressor and related surface equipment have been removed from this location and there is
no future activity anticipated from this gathering system.
During 2013, our mid-stream segment incurred $96.1 million in capital expenditures as compared to $183.2 million
($18.7 million on four gathering systems acquired in the Noble acquisition) in 2012 and $79.4 million in 2011, including
acquisitions. For 2014, our estimated capital expenditures (excluding acquisitions) are $78.0 million. At December 31, 2013,
we had committed to purchase a gas treating plant for the remaining payment of $0.6 million within the next twelve months.
Contractual Commitments
At December 31, 2013, we had the following contractual obligations:
Total
Less Than
1 Year
Payments Due by Period
2-3
Years
(In thousands)
4-5
Years
After
5 Years
Long-term debt (1) .................................... $
Operating leases (2) ...................................
Drill pipe, drilling components and
equipment purchases (3)............................
Total contractual obligations.................... $
1,021,281
$
43,062
$
86,125
$
86,125
$
805,969
12,640
12,021
8,480
12,021
4,044
—
116
—
—
—
1,045,942
$
63,563
$
90,169
$
86,241
$
805,969
_________________________
(1) See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit
agreement and includes interest calculated using our December 31, 2013 interest rates of 6.625% for the Notes.
(2) We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and
Pittsburgh, Pennsylvania under the terms of operating leases expiring through September, 2017. Additionally, we have several equipment leases and lease
space on short-term commitments to stack excess drilling rig equipment and production inventory.
(3) We have committed to purchase approximately $11.4 million of new drilling rig components, drill pipe, and related equipment and $0.6 million towards a
gas treating plant over the next twelve months.
56
At December 31, 2013, we also had the following commitments and contingencies that could create, increase or
accelerate our liabilities:
Other Commitments
Estimated Amount of Commitment Expiration Per Period
Total
Accrued
Less
Than 1
Year
2-3
Years
(In thousands)
4-5
Years
After 5
Years
$
351
9,382
3,589
Unknown
Unknown
Unknown
Unknown
Deferred compensation plan (1) ................ $
Separation benefit plans (2)....................... $
Derivative liabilities—commodity
hedges ...................................................... $
ARO liability (3)........................................ $
Gas balancing liability (4) ......................... $
Repurchase obligations (5) ........................ $
Workers’ compensation liability (6) .......... $
_________________________
(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.
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
133,657
40,261
83,939
20,041
— $
— $
6,503
2,861
8,808
5,561
5,561
3,775
7,218
1,154
2,954
—
—
$
$
$
$
$
$
$
$
$
$
(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, 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 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. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue
Code of 1986, as amended.
(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, with a subsidiary of ours serving as general partner. The
Partnerships were formed for the purpose of conducting 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 $16,000, $56,000, and $22,000 in 2013, 2012, and 2011, respectively.
(6) We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling
segment.
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. In August 2012, we determined on a prospective basis to enter into economic hedges without electing
cash flow hedge accounting. All of our previous cash flow hedges expired as of December 31, 2013. Therefore, the change in
fair value, on all commodity derivatives entered into are reflected in the income statement and not in accumulated other
comprehensive income.
57
Commodity Hedges. Our commodity hedging is intended to 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 hedge(s) is based, in part, on our view of
current and future market conditions. As of December 31, 2013, based on our fourth quarter 2013 average daily production, the
approximated percentages of our production that we have hedged are as follows:
Daily oil production ...............................................................................................................................
Daily natural gas production..................................................................................................................
Mark-to-Market
2014
75%
58%
With respect to the commodities subject to our hedges, the use of hedging limits the risk of adverse downward price
movements. However, it also limits increases in future revenues that would otherwise result from price movements above the
hedged prices.
The use of derivative transactions carries with it the risk that one or more of the counterparties may not be able to meet
their financial obligations under the transactions. Based on our evaluation at December 31, 2013, we determined that there was
no material risk of non-performance by any of our counterparties. At December 31, 2013, the fair values of the net assets
(liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:
December 31, 2013
(In millions)
Canadian Imperial Bank of Commerce.................................................................................................. $
Scotiabank..............................................................................................................................................
Bank of Montreal ...................................................................................................................................
Total assets (liabilities) .......................................................................................................................... $
0.5
(0.3)
(5.2)
(5.0)
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, 2013, we recorded the fair value of our commodity derivatives on our balance
sheet as current derivative assets of $0.5 million and current derivative liabilities of $5.6 million. At December 31, 2012, we
recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $16.5 million and
current and non-current derivative liabilities of $1.9 million and $0.6 million, respectively.
For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before
their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and
hedge ineffectiveness, net in our Consolidated Statements of Income. The commodity derivative instruments we had under cash
flow accounting expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow
hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the
hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and
natural gas revenues. Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not
designated as hedges and hedge ineffectiveness, net.
58
These gains (losses) are as follows at December 31:
Gain (loss) on derivatives not designated as hedges and
hedge ineffectiveness, net:
2013
2012
(In thousands)
2011
Gain (loss) on derivatives not designated as hedges, included are
amounts settled during the period of ($1,764), $0, and ($711),
respectively ................................................................................................. $
Gain (loss) on ineffectiveness of cash flow hedges....................................
$
(8,184) $
(190)
(8,374) $
$
1,373
(2,616)
(1,243) $
(1,047)
2,749
1,702
Stock and Incentive Compensation
During 2013, we granted awards covering 474,677 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 $21.3 million. Compensation expense
will be recognized over the awards' three year vesting period. During 2013, we recognized $8.5 million in additional
compensation expense and capitalized $1.9 million for these awards. During 2012, we granted awards covering 401,051 shares
of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three
year vesting period. During 2011, we granted awards covering 211,050 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 2013, 2012, or 2011.
During 2013, we recognized compensation expense of $16.1 million for our restricted stock grants and capitalized $3.5
million of compensation cost for oil and natural gas properties.
Insurance
We are self-insured for certain losses relating to workers’ compensation, control of well, and employee medical
benefits. Insured policies for other coverages contain deductibles or retentions per occurrence that range from $50,000 to $1.5
million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to
certain types of claims. However, there is no assurance that the insurance coverages we have will adequately protect us against
liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover
our drilling segment employees in Texas in lieu of covering them under Texas Workers’ Compensation. 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 16 oil and natural gas partnerships which were formed privately or publicly. Each
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 on the same basis 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 as well as 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 2013, 2012, and 2011, the total we
received for all of these fees was $0.5 million, $0.7 million, and $1.4 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.
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 in turn 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 as well as the costs of services to support our drilling rigs. Historically, during this same
period, when oil, NGLs, and natural gas prices did decline, labor rates did not come back down to the levels existing before the
59
increases. If commodity prices increase substantially for a long period, shortages in support equipment (such as drill pipe, third
party services, and qualified labor) can result in 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. How inflation will affect us in the future will depend on
increases, if any, realized 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.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and
capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to
various contractual commitments.
60
Results of Operations
2013 versus 2012
Following is a comparison of selected operating and financial data:
Total operating revenue ............................................................................ $
Net income................................................................................................ $
Oil and Natural Gas:
Revenue ............................................................................................ $
Operating costs excluding depreciation, depletion, amortization,
and impairment ............................................................................. $
Average oil price received (Bbl)....................................................... $
Average NGL price received (Bbl)................................................... $
Average natural gas price received (Mcf)......................................... $
Oil production (Bbl) .........................................................................
NGLs production (Bbl).....................................................................
Natural gas production (Mcf) ...........................................................
Depreciation, depletion, and amortization rate (Boe)....................... $
Depreciation, depletion, and amortization........................................ $
Impairment of oil and natural gas properties.................................... $
Contract Drilling:
Revenue ............................................................................................ $
Operating costs excluding depreciation............................................ $
Percentage of revenue from daywork contracts ...............................
Average number of drilling rigs in use.............................................
Average dayrate on daywork contracts............................................. $
Depreciation...................................................................................... $
Mid-Stream:
Revenue ............................................................................................ $
Operating costs excluding depreciation, amortization, and
impairment.................................................................................... $
Depreciation, amortization, and impairment .................................... $
Gas gathered—Mcf/day....................................................................
Gas processed—Mcf/day..................................................................
Gas liquids sold—gallons/day ..........................................................
General and administrative expense ......................................................... $
Gain on disposition of assets .................................................................... $
Other income (expense):
Interest expense, net ......................................................................... $
Loss on derivatives not designated as hedges and hedge
ineffectiveness, net ....................................................................... $
Other ................................................................................................. $
Income tax expense .................................................................................. $
Average interest rate.................................................................................
Average long-term debt outstanding......................................................... $
$
$
$
$
$
$
$
2013
1,351,850,000
184,746,000
649,718,000
184,001,000
95.06
31.79
3.32
3,360,000
3,914,000
56,757,000
13.32
226,498,000
$
$
— $
414,778,000
247,280,000
100%
65.0
19,646
71,194,000
287,354,000
243,406,000
33,191,000
309,554
140,584
543,602
38,323,000
(17,076,000)
(15,015,000)
(8,374,000)
(175,000)
116,723,000
6.4%
686,656,000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2012
1,315,123,000
23,176,000
567,944,000
150,212,000
92.60
31.58
3.37
3,279,000
2,796,000
48,930,000
14.70
211,347,000
283,606,000
529,719,000
289,524,000
100%
73.9
19,949
81,007,000
217,460,000
187,292,000
24,388,000
250,290
133,987
542,578
33,086,000
(253,000)
(14,137,000)
(1,243,000)
(132,000)
16,226,000
6.1%
495,830,000
Percent
Change (1)
3 %
NM
14 %
22 %
3 %
1 %
(1)%
2 %
40 %
16 %
(9)%
7 %
NM
(22)%
(15)%
(12)%
(2)%
(12)%
32 %
30 %
36 %
24 %
5 %
— %
16 %
NM
6 %
NM
33 %
NM
5 %
38 %
_________________________
(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
61
Oil and Natural Gas
Oil and natural gas revenues increased $81.8 million or 14% in 2013 as compared to 2012 primarily due to an 18%
increase in equivalent production volumes. This production increase was the result of 2012 acquisitions and new wells
completed in oil and NGLs rich prospects that were brought online. Oil production increased 2%, NGLs production increased
40%, and natural gas production increased 16%. Average oil prices between the comparative years increased 3% to $95.06 per
barrel and NGLs prices increased 1% to $31.79 per barrel while prices for natural gas decreased 1% to $3.32 per Mcf.
Oil and natural gas operating costs increased $33.8 million or 22% between the comparative years of 2013 and 2012 due
to increased well servicing costs, higher saltwater disposal expenses, and increased general and administrative expense .
Depreciation, depletion, and amortization (“DD&A”) increased $15.2 million or 7% primarily due to an 18% increase in
equivalent production offset by a 9% decrease in our DD&A rate. The decrease in our DD&A rate resulted primarily from a
reduction to the full cost pool from proceeds associated with the divestitures completed during 2013 and the non-cash ceiling
test write-down of $167.7 million pre-tax ($104.4 million, net of tax) that occurred during the fourth quarter of 2012. Our
DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities adjusted for
current period production.
We did not have any ceiling test write-downs during 2013. During the second quarter of 2012, we recorded a non-cash
ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax). During the fourth quarter of 2012, we recorded a
non-cash ceiling test write down of $167.7 million pre-tax ($104.4 million, net of tax). If there are declines in the 12-month
average prices, we may be required to record a write-down in future periods.
Contract Drilling
Drilling revenues decreased $114.9 million or 22% in 2013 as compared to 2012. The decrease was due primarily to a
12% decrease in the average number of drilling rigs in use and a 2% decrease in the average dayrate. Average drilling rig
utilization decreased from 73.9 drilling rigs in 2012 to 65.0 drilling rigs in 2013. During 2012, we had eight drilling contracts
that were terminated early by the operator. The early termination fees associated with these contracts included in revenues was
approximately $22.6 million compared to $1.9 million for the termination of one long-term drilling contract in 2013.
Drilling operating costs decreased $42.2 million or 15% in 2013 compared to 2012. The decrease was due primarily to
operating fewer rigs as per day direct cost increased $79 and indirect cost increased $0.6 million due to increased ad valoreum
tax. Contract drilling depreciation decreased $9.8 million or 12% also due primarily to the decrease in utilization.
Mid-Stream
Our mid-stream revenues increased $69.9 million or 32% in 2013 as compared to 2012. The average price for natural gas
sold increased 37%. Gas processing volumes per day increased 5% between the comparative years and NGLs sold per day were
essentially unchanged between the comparative periods. The increase in volumes processed per day is primarily attributable to
the volumes added from new wells connected to existing systems and increased capacity of processing facilities. NGLs sold
volumes per day remained constant as an increase in volumes processed and upgrades to several of our processing facilities was
offset from decreases due to one of our customers completing construction of their own processing plant and moving their
volumes off our system during the second half of 2012. Gas gathering volumes per day increased 24% primarily from new well
connections.
Operating costs increased $56.1 million or 30% in 2013 compared to 2012 primarily due to a 25% increase in prices paid
for natural gas purchased. Depreciation, amortization, and impairment increased $8.8 million or 36% primarily due to
additional assets placed into service throughout 2013.
62
General and Administrative
General and administrative expenses increased $5.2 million or 16% in 2013 compared to 2012. The increase was
primarily due to increases in employee costs.
Gain on Disposition of Assets
Gain on disposition of assets increased $16.8 million in 2013 compared to 2012 primarily due to the sale of five drilling
rigs.
Other Income (Expense)
Interest expense, net of capitalized interest, increased $0.9 million between the comparative years of 2013 and 2012. 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 2013 was $33.7 million compared
to $18.9 million in 2012, and was netted against our gross interest of $48.7 million and $33.0 million for 2013 and 2012,
respectively. Our average interest rate increased from 6.1% to 6.4% and our average debt outstanding was $190.8 million
higher in 2013 as compared to 2012 due to the issuance of $400.0 million of senior subordinated notes during the third quarter
of 2012 to partially fund the Noble acquisition in the oil and natural gas segment.
Loss on derivatives not designated as hedges and hedge ineffectiveness, net increased from $1.2 million in 2012 to $8.4
million in 2013 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Expense
Income tax expense increased $100.5 million in 2013 compared to 2012 primarily due to increased income. Our effective
tax rate was 38.7% for 2013 and 41.2% for 2012. This decrease is primarily due to the effect of permanent differences as they
relate to the rise in pre-tax income. Current income tax expense was $16.0 million in 2013 compared to a current tax expense of
$0.7 million for 2012. This increase is also primarily due to increased income. We paid $9.1 million in income taxes during
2013.
63
2012 versus 2011
Total operating revenue............................................................................. $
Net income ................................................................................................ $
Oil and Natural Gas:
Revenue (2)......................................................................................... $
Operating costs excluding depreciation, depletion, amortization,
and impairment ............................................................................. $
Average oil price received (Bbl)....................................................... $
Average NGL price received (Bbl)................................................... $
Average natural gas price received (Mcf)......................................... $
Oil production (Bbl)..........................................................................
NGLs production (Bbl) .....................................................................
Natural gas production (Mcf)............................................................
Depreciation, depletion, and amortization rate (Boe) ....................... $
Depreciation, depletion, and amortization ........................................ $
Impairment of oil and natural gas properties .................................... $
Contract Drilling:
Revenue............................................................................................. $
Operating costs excluding depreciation ............................................ $
Percentage of revenue from daywork contracts................................
Average number of drilling rigs in use..............................................
Average dayrate on daywork contracts............................................. $
Depreciation ...................................................................................... $
Mid-Stream:
Revenue............................................................................................. $
Operating costs excluding depreciation and amortization ................ $
Depreciation, amortization, and impairment..................................... $
Gas gathered—Mcf/day ....................................................................
Gas processed—Mcf/day ..................................................................
Gas liquids sold—gallons/day ..........................................................
General and administrative expense ......................................................... $
Gain (loss) on disposition of assets........................................................... $
Other income (expense): (2)
Interest expense, net.......................................................................... $
Gain/(loss) on derivatives not designated as hedges and hedge
ineffectiveness, net........................................................................ $
Other.................................................................................................. $
Income tax expense................................................................................... $
Average interest rate..................................................................................
Average long-term debt outstanding......................................................... $
2012
1,315,123,000
23,176,000
567,944,000
150,212,000
92.60
31.58
3.37
3,279,000
2,796,000
48,930,000
14.70
211,347,000
283,606,000
529,719,000
289,524,000
100%
73.9
19,949
81,007,000
217,460,000
187,292,000
24,388,000
250,290
133,987
542,578
33,086,000
(253,000)
(14,137,000)
(1,243,000)
(132,000)
16,226,000
6.1%
495,830,000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2011
1,207,503,000
195,867,000
514,614,000
131,271,000
87.18
43.64
4.26
2,511,000
2,239,000
44,104,000
15.06
183,350,000
—
484,651,000
269,899,000
100%
76.1
18,842
79,667,000
208,238,000
174,859,000
16,101,000
188,569
92,940
412,064
30,055,000
595,000
(4,167,000)
1,702,000
(239,000)
123,135,000
5.6%
249,681,000
Percent
Change (1)
9 %
(88)%
10 %
14 %
6 %
(28)%
(21)%
31 %
25 %
11 %
(2)%
15 %
NM
9 %
7 %
(3)%
6 %
2 %
4 %
7 %
51 %
33 %
44 %
32 %
10 %
(143)%
NM
(173)%
(45)%
(87)%
9 %
99 %
_________________________
(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
(2) During the third quarter of 2012, we made the decision to prospectively use mark-to-market accounting for our economic hedges. Previously, we reported
all designated and non-designated hedging gains (losses) in oil and natural gas revenues. We now reflect gains (losses) on non-designated hedges and the
ineffectiveness from cash flow hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have
been reclassified to conform to current year presentation.
64
Oil and Natural Gas
Oil and natural gas revenues increased $53.3 million or 10% in 2012 as compared to 2011 primarily due to an increase in
equivalent production volumes of 18% and an increase in oil prices partially offset by decreases in prices for NGLs and natural
gas. Average oil prices between the comparative years increased 6% to $92.60 per barrel while NGLs and natural gas prices
decreased 28% to $31.58 per barrel and 21% to $3.37 per Mcf, respectively. In 2012, as compared to 2011, oil production
increased 31%, NGLs production increased 25%, and natural gas production increased 11%. Production increased from our
drilling program and primarily from wells acquired from Noble.
Oil and natural gas operating costs increased $18.9 million or 14% between the comparative years of 2012 and 2011 due
to increased well servicing costs, higher saltwater disposal fees, and higher gross production taxes due to higher revenue in
2012. Lease operating expenses per Boe decreased 2% to $6.66.
DD&A increased $28.0 million or 15% primarily due to an 18% increase in equivalent production slightly offset by a 2%
decrease in our DD&A rate. The decrease in our DD&A rate resulted primarily from a reduction to the full cost pool from
proceeds associated with the divestitures completed during the third quarter of 2012 and the non-cash ceiling test write-down of
$115.9 million pre-tax ($72.1 million, net of tax) that occurred during the second quarter of 2012. Our DD&A expense on our
oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period
production.
During the fourth quarter of 2012, we recorded a non-cash ceiling test write down of $167.7 million pre-tax ($104.4
million, net of tax).
Contract Drilling
Drilling revenues increased $45.1 million or 9% in 2012 as compared to 2011 primarily due to $22.6 million in
termination fees during 2012 for eight drilling rigs that were under long-term contracts but were terminated early by the
operator and a 6% increase in the average dayrate, somewhat offset by a 3% decrease in rigs utilized. Average drilling rig
utilization decreased from 76.1 drilling rigs in 2011 to 73.9 drilling rigs in 2012.
Drilling operating costs increased $19.6 million or 7% in 2012 compared to 2012 due largely to increased personnel costs
and to a lesser extent for repair and maintenance costs. The increased personnel cost was due to an increase in compensation
for Rocky Mountain personnel in the first quarter of 2012 to keep qualified labor. Contract drilling depreciation increased $1.3
million or 2% primarily due to increased capital expenditures associated with the construction of new drilling rigs and for
upgrades to existing drilling rigs in our fleet.
Mid-Stream
Our mid-stream revenues increased $9.2 million or 4% in 2012 as compared to 2011 primarily due to higher NGLs
volumes offset by a decrease in price. Gas processing volumes per day increased 44% between the comparative years and
NGLs sold per day increased 32% between the comparative periods. The increase in volumes processed per day is primarily
attributable to the volumes added from new wells connected to existing systems and increased capacity of processing facilities.
NGLs sold volumes per day increased due to an increase in volumes processed and upgrades to several of our processing
facilities . Gas gathering volumes per day increased 33% primarily from new well connections. The average price for NGLs
sold decreased 27%.
Operating costs increased $12.4 million or 7% in 2012 compared to 2011 primarily due to a 42% increase in per day gas
volumes purchased offset by a 30% decrease in prices paid for natural gas purchased. Depreciation, amortization, and
impairment increased $8.3 million or 51% primarily due to the $1.2 million write-down of the carrying value of our Erick
system and increased assets placed into service throughout 2012.
General and Administrative
General and administrative expenses increased $3.0 million or 10% in 2012 compared to 2011 primarily due to increases
in employee costs.
65
Other Income (Expense)
Interest expense, net of capitalized interest, increased $10.0 million between the comparative years of 2012 and 2011. 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 2012 was $18.9 million compared
to $11.5 million in 2011, and was netted against our gross interest of $33.0 million and $15.6 million for 2012 and 2011,
respectively. Our average interest rate increased from 5.6% to 6.1% and our average debt outstanding was $246.1 million
higher in 2012 as compared to 2011 due to the issuance of $400.0 million of senior subordinated notes during the third quarter
of 2012 to partially fund the Noble acquisition in the oil and natural gas segment.
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net fluctuates due to changes in forward
prices used to estimate the fair value in mark-to-market accounting.
Income Tax Expense
Income tax expense decreased $106.9 million or 87% in 2012 compared to 2011 primarily due to decreased income. Our
effective tax rate was 41.2% for 2012 and 38.6% for 2011. Current income tax expense was $0.7 million in 2012 compared to a
current tax benefit of $2.4 million for 2011. We paid $5.1 million in income taxes during 2012.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Our operations are exposed to market risks primarily as a result 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, these prices have fluctuated and we expect they will 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 the use of our
drilling rigs. Based on our 2013 production, a $0.10 per Mcf change in what we are paid for our natural gas production would
result in a corresponding $448,000 per month ($5.4 million annualized) change in our pre-tax cash flow. A $1.00 per barrel
change in our oil price would have a $268,000 per month ($3.2 million annualized) change in our pre-tax operating cash flow
and a $1.00 per barrel change in our NGLs prices would have a $310,000 per month ($3.7 million annualized) change in our
pre-tax cash flow.
We use hedging transactions to manage the risk associated with price volatility. Our decisions regarding the amount and
prices at which we choose to hedge certain of our products 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. We do not hold or issue derivative instruments for speculative
trading purposes.
At December 31, 2013, the following non-designated hedges were outstanding:
Term
Commodity
Hedged Volume
Weighted Average
Fixed Price for
Swaps
Jan’14 – Dec’14
Natural gas – swap
80,000 MMBtu/day
$4.24
Jan’14 – Dec’14
Natural gas – collar
10,000 MMBtu/day
$3.75-4.37
Jan’14 – Jun’14
Crude oil – swap
Jan’14 – Dec’14
Crude oil – swap
Jan’14 – Dec’14
Crude oil – collar
500 Bbl/day
3,000 Bbl/day
4,000 Bbl/day
$100.03
$91.77
$90.00-96.08
Hedged Market
IF – NYMEX (HH)
IF – NYMEX (HH)
WTI – NYMEX
WTI – NYMEX
WTI – NYMEX
66
Subsequent to December 31, 2013, the following non-designated hedges were entered into:
Term
Commodity
Hedged Volume
Weighted Average
Fixed Price for
Swaps
Mar'14
Mar'14
Natural gas – basis swap
30,000 MMBtu/day
Natural gas – basis swap
60,000 MMBtu/day
$(0.095)
$(0.027)
Hedged Market
NGPL-TXOK
NGPL-Midcon
Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The
credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election,
borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average
outstanding long-term debt subject to a variable rate in 2013, a 1% increase in the floating rate would reduce our annual pre-tax
cash flow by approximately $0.4 million. 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).
67
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, 2013 and 2012 ......................................................................
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012, and 2011 ....................
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012, and
2011.................................................................................................................................................................
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2011,
2012, and 2013 ................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012, and 2011 .............
Notes to Consolidated Financial Statements...................................................................................................
Page
69
70
71
73
74
75
76
77
68
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 under 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:
•
•
•
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, 2013. In making this assessment, the company’s management used the criteria set forth in Internal Control—
Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on their assessment, the company’s management concluded that, as of December 31, 2013, the company’s internal
control over financial reporting was effective based on those criteria.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2013, has been audited
by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears
herein.
69
Report of Independent Registered Public Accounting Firm
To Board of Directors and Shareholders of Unit Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income,
comprehensive income, changes in shareholders’ equity, and cash flows present fairly, in all material respects, the financial
position of Unit Corporation and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the
index appearing under item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal
Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our
responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s
internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. 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.
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
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 25, 2014
70
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
2012
2013
(In thousands except share and par
value amounts)
Current assets:
ASSETS
Cash and cash equivalents ................................................................................................... $
Accounts receivable (less allowance for doubtful accounts of $5,342 and $5,343 at
December 31, 2013 and 2012, respectively)....................................................................
Materials and supplies .........................................................................................................
Current derivative asset (Note 13).......................................................................................
Current income tax receivable.............................................................................................
Current deferred tax asset (Note 8) .....................................................................................
Assets held for sale (Note 3) ...............................................................................................
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 ............................................................................
Transportation equipment....................................................................................................
Other ....................................................................................................................................
Less accumulated depreciation, depletion, amortization, and impairment .........................
Net property and equipment ...............................................................................
Debt issuance cost.......................................................................................................................
Goodwill (Note 2).......................................................................................................................
Other intangible assets, net .........................................................................................................
Other assets.................................................................................................................................
Total assets.................................................................................................................................. $
18,593
$
974
139,788
10,998
515
—
13,585
15,621
12,931
212,031
4,235,712
545,588
1,477,093
549,422
39,666
87,435
6,934,916
3,212,225
3,722,691
11,844
62,808
—
13,016
4,022,390
$
146,046
8,563
16,552
901
8,765
—
13,843
195,644
3,822,381
521,659
1,478,645
461,629
37,728
62,840
6,384,882
2,907,660
3,477,222
13,432
62,808
680
11,334
3,761,120
71
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
As of December 31,
2012
2013
(In thousands except share and par
value amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable................................................................................................................. $
Accrued liabilities (Note 5) .................................................................................................
Income taxes payable ..........................................................................................................
Current derivative liabilities (Note 13)................................................................................
Current portion of other long-term liabilities (Note 6)........................................................
Total current liabilities........................................................................................
Long-term debt (Note 6).............................................................................................................
Non-current derivative liabilities (Note 13) ...............................................................................
Other long-term liabilities (Note 6) ............................................................................................
Deferred income taxes (Note 8)..................................................................................................
Commitments and contingencies (Note 16) ...............................................................................
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, 49,107,004 and
48,581,948 shares issued as of December 31, 2013 and 2012, respectively ...................
Capital in excess of par value..............................................................................................
Accumulated other comprehensive income (net of tax of $0 and $4,892, respectively)
(Note 15) ..........................................................................................................................
Retained earnings ................................................................................................................
Total shareholders’ equity.....................................................................................
Total liabilities and shareholders’ equity.................................................................................... $
$
154,062
64,363
7,474
5,561
12,113
243,573
645,696
—
158,331
801,398
—
138,811
54,098
—
1,948
12,282
207,139
716,359
562
166,983
695,776
—
—
—
9,659
445,470
9,594
423,603
—
1,718,263
2,173,392
4,022,390
$
7,587
1,533,517
1,974,301
3,761,120
The accompanying notes are an integral part of the consolidated financial statements.
72
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
2013
Year Ended December 31,
2012
(In thousands except per share amounts)
2011
Revenues:
Oil and natural gas ................................................................................... $
Contract drilling .......................................................................................
Gas gathering and processing ..................................................................
Total revenues...................................................................................
649,718
414,778
287,354
1,351,850
$
567,944
529,719
217,460
1,315,123
$
514,614
484,651
208,238
1,207,503
Expenses:
Oil and natural gas:
Operating costs .................................................................................
Depreciation, depletion, and amortization........................................
Impairment of oil and natural gas properties (Note 2) .....................
Contract drilling:
Operating costs .................................................................................
Depreciation......................................................................................
Gas gathering and processing:
Operating costs .................................................................................
Depreciation, amortization, and impairment ....................................
General and administrative ......................................................................
(Gain) loss on disposition of assets..........................................................
Total expenses...................................................................................
Income from operations ..................................................................................
Other income (expense):
Interest, net...............................................................................................
Gain (loss) on derivatives not designated as hedges and hedge
ineffectiveness, net ...............................................................................
Other ........................................................................................................
Total other expense...........................................................................
Income before income taxes ...........................................................................
Income tax expense (benefit):
Current .....................................................................................................
Deferred ...................................................................................................
Total income taxes............................................................................
Net income ...................................................................................................... $
Net income per common share:
184,001
226,498
—
247,280
71,194
243,406
33,191
38,323
(17,076)
1,026,817
325,033
150,212
211,347
283,606
289,524
81,007
187,292
24,388
33,086
(253)
1,260,209
54,914
131,271
183,350
—
269,899
79,667
174,859
16,101
30,055
595
885,797
321,706
(15,015)
(14,137)
(4,167)
(8,374)
(175)
(23,564)
301,469
15,991
100,732
116,723
184,746
(1,243)
(132)
(15,512)
39,402
696
15,530
16,226
23,176
0.48
0.48
$
$
$
1,702
(239)
(2,704)
319,002
(2,416)
125,551
123,135
195,867
4.11
4.08
$
$
$
Basic......................................................................................................... $
Diluted...................................................................................................... $
3.83
3.80
The accompanying notes are an integral part of the consolidated financial statements.
73
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
2013
For Years ended December 31,
2012
(In thousands)
2011
Net income ......................................................................................................... $
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net
of tax of ($4,717), $12,094, and $18,412....................................................
Reclassification - derivative settlements, net of tax of ($249), ($20,171),
and ($1,146) ................................................................................................
Ineffective portion of derivatives, net of tax of $74, $1,008, and ($1,061)
Comprehensive income ...................................................................................... $
184,746
$
23,176
$
195,867
(7,349)
18,635
29,384
(354)
116
(31,682)
1,608
177,159
$
11,737
$
(1,819)
(1,688)
221,744
The accompanying notes are an integral part of the consolidated financial statements.
74
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2011, 2012, and 2013
Common
Stock
Capital
In Excess
of Par Value
Accumulated
Other
Comprehensive
Income
(In thousands except share amounts)
Retained
Earnings
Total
Balances, January 1, 2011..................... $
9,493
$
393,501
$
(6,851) $
1,314,474
$
1,710,617
Comprehensive income:
Net income.....................................
Other comprehensive income (net
of tax of $16,205).......................
Total comprehensive income....
Activity in employee compensation
plans (241,011 shares) ....................
Balances, December 31, 2011...............
Comprehensive income (loss):
Net income.....................................
Other comprehensive loss (net of
tax ($7,069))...............................
Total comprehensive income....
Activity in employee compensation
plans (430,506 shares) ....................
Balances, December 31, 2012 ..............
Comprehensive income (loss):
Net income.....................................
Other comprehensive loss (net of
tax ($4,892))...............................
Total comprehensive income....
Activity in employee compensation
plans (525,056 shares) ....................
Balances, December 31, 2013 .............. $
—
—
48
9,541
—
—
53
9,594
—
—
—
—
—
195,867
195,867
25,877
—
25,877
221,744
14,656
1,947,017
14,608
408,109
—
19,026
—
1,510,341
—
—
—
23,176
23,176
(11,439)
—
(11,439)
11,737
15,494
423,603
—
7,587
—
1,533,517
15,547
1,974,301
—
—
—
184,746
184,746
(7,587)
—
(7,587)
177,159
65
9,659
$
21,867
445,470
$
—
— $
—
1,718,263
$
21,932
2,173,392
The accompanying notes are an integral part of the consolidated financial statements.
75
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
OPERATING ACTIVITIES:
Net income .............................................................................................................. $
Adjustments to reconcile net income (loss) to net cash provided (used) by
operating activities:
Depreciation, depletion, amortization, and impairment ...............................
Impairment of oil and natural gas properties (Note 2) .................................
(Gain) loss on derivatives .............................................................................
Derivatives settled ........................................................................................
(Gain) loss on disposition of assets ..............................................................
Deferred tax expense ....................................................................................
Employee stock compensation plans............................................................
Bad debt expense ..........................................................................................
ARO liability accretion.................................................................................
Other, net ......................................................................................................
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable......................................................................................
Materials and supplies ..................................................................................
Prepaid expenses and other...........................................................................
Accounts payable..........................................................................................
Accrued liabilities.........................................................................................
Contract advances.........................................................................................
2013
Year Ended December 31,
2012
(In thousands)
2011
184,746
$
23,176
$
195,867
333,907
—
5,449
1,161
(17,076)
100,732
21,317
—
5,450
2,250
2,967
(2,435)
1,813
15,715
17,198
1,137
319,021
283,606
53,096
(51,853)
(253)
15,530
16,956
90
4,615
781
13,994
(361)
(3,466)
10,187
6,911
(1,119)
280,451
—
(159)
(2,254)
595
125,551
14,303
260
3,838
294
(38,731)
(1,886)
22,672
(1,064)
9,245
(527)
Net cash provided by operating activities.............................................
674,331
690,911
608,455
INVESTING ACTIVITIES:
Capital expenditures................................................................................................
Producing property and other acquisitions..............................................................
Proceeds from disposition of property and equipment............................................
Other........................................................................................................................
(703,984)
—
120,910
3,894
(762,381)
(598,485)
281,824
—
(728,551)
(50,013)
10,328
—
Net cash used in investing activities.....................................................
(579,180)
(1,079,042)
(768,236)
FINANCING ACTIVITIES:
Borrowings under line of credit ..............................................................................
Payments under line of credit..................................................................................
Proceeds from issuance of senior subordinated notes, net of debt issuance costs
and discount.........................................................................................................
Proceeds from exercise of stock options .................................................................
Tax benefit from stock options................................................................................
Increase (decrease) in book overdrafts (Note 2) .....................................................
Net cash provided by (used in) financing activities .............................
Net increase (decrease) in cash and cash equivalents .....................................................
Cash and cash equivalents, beginning of year.................................................................
Cash and cash equivalents, end of year........................................................................... $
Supplemental disclosure of cash flow information:
Cash paid during the year for:
222,500
(293,600)
735,300
(714,200)
441,500
(554,500)
—
574
8
(7,014)
(77,532)
17,619
974
18,593
386,274
215
121
(19,440)
388,270
139
835
974
14,880
5,116
$
$
$
243,950
679
1,174
26,454
159,257
(524)
1,359
835
3,470
655
$
$
$
Interest paid (net of capitalized) ................................................................... $
Income taxes ................................................................................................. $
12,485
9,100
Changes in accounts payable and accrued liabilities related to purchases of
property, plant, and equipment............................................................................ $
Non-cash additions (reductions) to oil and natural gas properties related to asset
retirement obligations.......................................................................................... $
(6,550) $
(4,753) $
(28,036)
(17,952) $
45,097
$
23,345
The accompanying notes are an integral part of the consolidated financial statements.
76
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and its subsidiaries.
We are primarily engaged in the land contract drilling of natural gas and oil wells, the exploration, development,
acquisition, and production of oil and natural gas properties, and the buying, selling, gathering, processing, and treating of
natural gas. Our operations are located 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, Unit Petroleum Company, we explore, 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 located mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana,
Mississippi, Montana, New Mexico, North Dakota, Pennsylvania, and Wyoming.
Historically, our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil
and NGLs. With the current natural gas market, operators have been focusing on drilling for oil and NGLs.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company and its subsidiary Unit Texas Drilling, L.L.C.,
we drill onshore oil and natural gas wells for our own account as well as for a wide range of other oil and natural gas
companies. Our drilling operations are mainly located in Oklahoma, Texas, Louisiana, Kansas, Wyoming, Colorado, Utah,
Montana, and North Dakota.
Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, 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 OF 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.
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to
conform to current year presentation. 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. Under “footage” and “turnkey” contracts, we bear the risk of
completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this
method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The
entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include
expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are
included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well
which can take from 20 to 90 days. At December 31, 2013, all of our contracts were daywork contracts of which 23 were multi-
well and had durations which ranged from six months to three years, 22 of which expire in 2014 and one expiring in 2015.
77
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
These longer term contracts may contain a fixed rate for the duration of the contract or provide for the 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. There
were no book overdrafts at December 31, 2013. At December 31, 2012, book overdrafts were $7.0 million and included in
accounts payable.
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:
Oil and Natural Gas:
Valero Energy Corporation......................................................................
Sunoco Partners Marketing......................................................................
Drilling:
QEP Resources, Inc..................................................................................
Kodiak Oil and Gas Corp.........................................................................
Mid-Stream:
ONEOK, Inc. ...........................................................................................
Tenaska Resources, LLC .........................................................................
Gavilon, LLC ...........................................................................................
2013
2012
2011
25%
8%
18%
10%
50%
16%
—%
26%
8%
15%
10%
54%
7%
10%
18%
10%
22%
6%
54%
1%
19%
We had a concentration of cash of $52.1 million and $40.4 million at December 31, 2013 and 2012, 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, 2013 and determined there was no material risk at that time. At December 31,
2013, 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:
December 31,
2013
(In millions)
Canadian Imperial Bank of Commerce .................................................................................................................. $
Scotiabank ..............................................................................................................................................................
Bank of Montreal ...................................................................................................................................................
Total assets (liabilities)........................................................................................................................................... $
0.5
(0.3)
(5.2)
(5.0)
Property and Equipment. Drilling equipment, natural gas gathering and processing equipment, transportation
equipment, and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and
maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on
78
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the equipment is idle.
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 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.
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. Assets are 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
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. An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property
and equipment. In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system. There was no
volume from the wells connected to this system, the compressor and related surface equipment have been removed from this
location and there is no future activity anticipated from this gathering system. No significant impairments were recorded in
2013 or 2011.
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. 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, are credited to accumulated depreciation.
We record an asset and a liability equal to the present value of the expected future asset retirement obligation (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 2013, 2012, and 2011, interest of approximately $33.7 million, $18.9 million, and $11.5
million, respectively, was capitalized 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. Interest is being capitalized using a
weighted average interest rate based on our outstanding borrowings.
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. Goodwill is all related to our
contract drilling segment, and accordingly, 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 rig utilization, day rates, gross margin percentages, and
terminal value (these are all considered level 3 inputs). No goodwill impairment was recorded for the years ended
December 31, 2013, 2012, or 2011. There were no additions to goodwill in 2013, 2012, or 2011. Goodwill of $3.9 million is
deductible for tax purposes.
Intangible Assets. Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are
reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be
recoverable. No intangible asset impairment was recorded for the years ended December 31, 2013, 2012, or 2011. Amortization
of $0.7 million, $1.2 million and $1.2 million was recorded in 2013, 2012, and 2011, respectively. Accumulated amortization
for 2013 and 2012 was $18.0 million and $17.3 million, respectively. Our intangible assets became fully amortized in 2013, so
no amortization is expected to be recorded in 2014.
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, all 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 $21.5 million, $17.6 million, and $15.6 million were
capitalized in 2013, 2012, and 2011, respectively. Independent petroleum engineers annually audit our internal evaluation of our
reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $13.32, $14.70, and $15.06 per
Boe in 2013, 2012, and 2011, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in
79
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our
unproved properties totaling $545.6 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 review 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.
For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash
flow hedges, decreased significantly, resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million,
net of tax). Our qualifying cash flow hedges used in the ceiling test determination at June 30, 2012, consisted of swaps and
collars, covering production of 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012
ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties.
For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our
cash flow hedges, decreased further, resulting in an additional non-cash ceiling test write down of $167.7 million pre-tax
($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012,
consisted of swaps and collars covering 6.9 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test
was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural
gas hedging is discussed in Note 13 of the Notes to our Consolidated Financial Statements.
At December 31, 2013, using the existing 12-month average commodity prices, we were not required to record a ceiling
test write-down. All cash flow hedges expired at December 31, 2013 and did not effect the ceiling test determination.
If there are declines in the 12-month average prices, we may be required to record a write-down in future periods.
Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their
timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an
ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, 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. We eliminated revenue of
$64.3 million, $49.6 million, and $52.2 million for 2013, 2012, and 2011, respectively from our contract drilling segment and
eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6 million during 2013, 2012, and 2011,
respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012, and 2011, respectively, as a reduction
to the carrying value of our oil and natural gas properties.
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 $50,000
to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate
exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us
against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to
cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. 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.
80
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Hedging Activities. All derivatives are recognized on the balance sheet and measured at fair value. Derivatives that are
designated as a cash flow hedge are measured by the effectiveness of the hedge, or the degree that the gain (loss) for the
hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss)
on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently
reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in
fair value is required to be recognized in earnings immediately. Derivatives that are not designated for hedge treatment are
recorded at fair value with gains (losses) recognized in earnings in the period of change. In August 2012, we determined on a
prospective basis, to enter into economic hedges without electing cash flow hedge accounting. Our cash flow hedges (that
existed before August 2012) expired in December 2013.
We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for
the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge.
Limited Partnerships. Unit Petroleum Company is a general partner in 16 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. Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted
tax law; 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. We
have no unrecognized tax benefits and we do not expect any significant changes in unrecognized tax benefits in the next twelve
months.
Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of
revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31,
2013 balancing position to be approximately 5.2 Bcf on under-produced properties and approximately 4.5 Bcf on over-
produced properties. We have recorded a receivable of $2.0 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 $3.8
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.
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 stock appreciation rights (SARs). The value of our restricted
stock grants is based on the closing stock price on the date of the grants.
Impact of Financial Accounting Pronouncements.
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax
Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the
financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a
tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an
unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The
amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15,
2013. Early adoption is permitted. The amendments should be applied prospectively to all unrecognized tax benefits that exist
81
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or
results of operations when adopted.
Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge
Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap
Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S.
Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The
amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July
17, 2013. We do not have any interest rate hedges at this time.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued
ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that
companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant
amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release
due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g.,
interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years,
beginning after December 15, 2012. We chose to present the information in a single note (Note 15 of the Notes to our
Consolidated Financial Statements).
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU
2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—
Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase
agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset
in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or
similar agreement.
Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a
legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or
bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure
draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in
response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead,
the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare
financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose
information about offsetting and related arrangements to enable users of its financial statements to understand the effect of
those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods
beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures
required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting
agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial
position in Note 14 of the Notes to our Consolidated Financial Statements.
NOTE 3 – ACQUISITIONS AND DIVESTITURES
On July 20, 2011, we acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in
cash, after post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver,
Harper, and Ellis Counties,Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved
properties and $3.9 million for acreage. The acquisition also included in excess of 12,000 net acres held by production available
for future development.
On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, from an unaffiliated
seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and
Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The acquisition also included
approximately 55,000 net acres of which 96% was held by production.
On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble Energy, Inc.
(Noble). After final closing adjustments, the acquisition included approximately 83,000 net acres primarily in the Granite Wash,
Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6
million.
82
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
As of the effective date of the Noble acquisition (April 1, 2012), the estimated proved reserves of the acquired properties
were 44 million barrels of oil equivalent (MMBoe). The acquisition added approximately 24,000 net acres to our Granite Wash
core area in the Texas Panhandle with significant resource potential including approximately 600 horizontal drilling locations.
The total acreage acquired in other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres
and is characterized by high working interest and operatorship, 95% of which was held by production. We also received four
gathering systems as part of the transaction and other miscellaneous assets.
The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which
required that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table
summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It was based on
information available to us at the time these consolidated financial statements were prepared and we believe these estimates are
reasonable(in thousands):
Adjusted Purchase Price
Total consideration given........................................................................................................................................ $
592,627
Adjusted Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties ................................................................................................................... $
Unproved oil and natural gas properties ..............................................................................................................
Total oil and natural gas properties included in the full cost pool (1) .................................................................
Gas gathering and processing equipment and other ...............................................................................................
Asset retirement obligation.....................................................................................................................................
Fair value of net assets acquired............................................................................................................................. $
260,799
353,343
614,142
25,163
(46,678)
592,627
(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.
Pro Forma Financial Information
The following unaudited pro forma financial information is presented to reflect the operations of the acquired assets as if
the acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the
historical accounting records of the seller adjusted for estimated transaction costs, depreciation, depletion and amortization,
ceiling test impact, general and administrative expenses, capitalized interest, and interest on the $400.0 million of Notes issued
along with additional borrowings under our credit agreement to finance the acquisition. The unaudited pro forma financial
information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on
the basis assumed above, nor is such information indicative of our expected future results of operations. The pro forma results
of operations do not include any cost savings or other synergies that resulted, or may result, from the acquisition or any
estimated costs that will be incurred to integrate these assets. Future results may vary significantly from the results reflected in
this pro forma financial information because of future events and transactions, as well as other factors.
83
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Twelve months ended
December 31,
2012
2011
(In thousands, except per share
amounts)
Pro forma:
Revenues........................................................................................................................ $
Net income..................................................................................................................... $
Net income per common share:
1,376,393
83,940
Basic............................................................................................................................ $
Diluted......................................................................................................................... $
1.75
1.74
$
$
$
$
1,336,227
229,272
4.81
4.78
From September 17, 2012, the date of the acquisition, through December 31, 2012, the portion of our revenues that were
attributable to Noble were $21.4 million with a net loss of $0.8 million.
2012 Divestitures
We completed the following divestitures in 2012, the proceeds all of which reduced the net book value of the full cost
pool with no gain or loss recognized:
•
In September 2012, we sold our interest in certain Bakken properties. The proceeds, net of related expenses were
$226.6 million.
•
In September 2012, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas, for
approximately $44.1 million.
2012 Other
In conjunction with the acquisition and divestitures completed in the third quarter 2012, we took the necessary steps to
secure like-kind exchange tax treatment for the transactions under Section 1031 of the Internal Revenue Code.
2013 Divestitures and Assets Held for Sale
In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million.
In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013. Proceeds from
these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
During 2013, we sold five 2,000-3,000 horsepower drilling rigs to unaffiliated third-parties for a gain of $16.5 million.
Four of our idle drilling rigs were classified as assets held for sale at December 31, 2013 and were sold to an unaffiliated third-
party in the first quarter of 2014. The proceeds for the sale of these assets, less costs to sell, is expected to exceed the
approximate $15.6 million net book value of the drilling rigs, both in the aggregate and for each drilling rig with an estimated
gain of $10.4 million.
84
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 4 – EARNINGS PER SHARE
The following data shows the amounts used in computing earnings per share:
Income
(Numerator)
Weighted
Shares
(Denominator)
(In thousands except per share amounts)
Per-Share
Amount
For the year ended December 31, 2013:
Basic earnings per common share...................................................... $
Effect of dilutive stock options, restricted stock, and SARs..............
Diluted earnings per common share .................................................. $
For the year ended December 31, 2012:
Basic earnings per common share...................................................... $
Effect of dilutive stock options, restricted stock, and SARs..............
Diluted earnings per common share .................................................. $
For the year ended December 31, 2011:
Basic earnings per common share...................................................... $
Effect of dilutive stock options, restricted stock, and SARs..............
Diluted earnings per common share .................................................. $
184,746
—
184,746
23,176
—
23,176
195,867
—
195,867
48,218
354
48,572
47,909
245
48,154
47,658
293
47,951
$
$
$
$
$
$
3.83
(0.03)
3.80
0.48
—
0.48
4.11
(0.03)
4.08
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:
Options and SARs ...........................................................................................
Average exercise price .................................................................................... $
149,665
250,901
58.41
$
52.72
$
105,000
61.24
2013
2012
2011
NOTE 5 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31:
2013
2012
(In thousands)
Employee costs ........................................................................................................................... $
Lease operating expenses ...........................................................................................................
27,633
$
16,073
Interest payable...........................................................................................................................
Deposits on assets held for sale ..................................................................................................
Taxes...........................................................................................................................................
Hedge settlements.......................................................................................................................
Other ...........................................................................................................................................
Total accrued liabilities............................................................................................................... $
85
24,632
10,903
6,568
—
7,308
160
4,527
6,504
3,750
2,313
416
7,674
64,363
$
54,098
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Long-term debt consisted of the following as of December 31:
Credit agreement with an average interest rates of 2.9% at December 31, 2012 ....................... $
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.3 million and
$4.7 million at December 31, 2013 and 2012, respectively....................................................
Total long-term debt ................................................................................................................... $
2013
2012
(In thousands)
— $
71,100
645,696
645,696
$
645,259
716,359
Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount available to be borrowed is the
lesser of the amount we elect (from time to time) as the commitment amount ($500.0 million) or the value of the borrowing
base as determined by the lenders ($800.0 million), but in either event not to exceed the maximum credit agreement amount of
$900.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed.
The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement
matures as of September 13, 2016. In connection with this new amendment, we paid $1.5 million in origination, agency,
syndication, and other related fees when the credit agreement was amended on September 5, 2012. We are amortizing these
fees over the life of the credit agreement.
The amount of the borrowing base, 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. There was no
change to the borrowing base as of the October 1, 2013 redetermination. We or the lenders may request a onetime 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 credit agreement.
At our election, any part of the outstanding debt under the 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 1.75% 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, which cannot be less than LIBOR plus 1.00%.
Interest is payable at the end of each month, and the principal may be repaid in whole or in part at anytime, without a premium
or penalty. At December 31, 2013, we had no outstanding borrowings under our credit agreement.
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 credit agreement prohibits, among other things:
•
•
•
•
•
the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net
income for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except in favor of our lenders.
The 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; and
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, 2013, we were in compliance with the covenants contained in the credit agreement.
86
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million aggregate principal
amount of registered senior subordinated notes due 2021 (the 2011 Notes) which bear interest at a rate of 6.625% per year. The
Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after
deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the
Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on
May 18, 2011. The remaining proceeds were used for general working capital purposes.
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of unregistered senior
subordinated notes (the 2012 Notes) due May 15, 2021, which will bear interest at a rate of 6.625% per year. The 2012 Notes
were sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially
finance the acquisition of oil and natural gas properties from Noble. We incurred $8.7 million of fees that are being amortized
as debt issuance cost over the life of the 2012 Notes.
On November 13, 2012, we registered with the SEC on Form S-4 an offer to exchange the 2012 Notes for additional
notes with materially identical terms to our existing 2011 Notes, which were registered under the Securities Act. On January 7,
2013, the exchange of the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now registered and
treated as a single series of debt securities with the 2011 Notes, bringing the total to $650.0 million aggregate principal amount
of 6.625% senior subordinated notes (the Notes). The interest is payable semi-annually (in arrears) on May 15 and
November 15 of each year, and the Notes will mature on May 15, 2021.
The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the
parent company, has no independent assets or operations. The guarantees registered under the registration statement are full and
unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of
the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant
defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. Any subsidiaries
of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its
subsidiaries through dividends, loans, advances or otherwise.
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 thereto
dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by that the Second
Supplemental Indenture thereto dated as of January 7, 2013, between us, the Guarantors and the Trustee, establishing the terms
and providing for the issuance of the Notes (as supplemented, the 2011 Indenture). The discussion of the Notes in this report is
qualified by and subject to the actual terms of the 2011 Indenture.
On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices,
plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the
original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of
106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65%
of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before
May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus
a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. 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 Indenture contains customary events of default. The Indenture 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, 2013.
87
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Other Long-Term Liabilities
Other long-term liabilities consisted of the following as of December 31:
ARO liability .............................................................................................................................. $
Workers’ compensation...............................................................................................................
Separation benefit plans..............................................................................................................
Gas balancing liability ................................................................................................................
Deferred compensation plan .......................................................................................................
Less current portion ....................................................................................................................
Total other long-term liabilities .................................................................................................. $
2013
2012
(In thousands)
133,657
$
146,159
20,041
9,382
3,775
3,589
170,444
12,113
18,517
7,972
3,838
2,779
179,265
12,282
158,331
$
166,983
Estimated annual principal payments under the terms of debt and other long-term liabilities from 2014 through 2018 are
$12.1 million, $2.8 million, $40.4 million, $4.2 million, and $3.5 million, respectively.
NOTE 7 – 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:
ARO liability, January 1:................................................................................................... $
Accretion of discount ........................................................................................................
Liability incurred...............................................................................................................
Liability settled .................................................................................................................
Liability sold .....................................................................................................................
Revision of estimates (2) ....................................................................................................
ARO liability, December 31:.............................................................................................
Less current portion ..........................................................................................................
Total long-term ARO liability........................................................................................... $
2013
2012
(In thousands)
146,159
$
96,446
5,450
4,857
(4,751)
(2,622)
(15,436)
133,657
2,954
4,615
56,650 (1)
(2,788)
(1,258)
(7,506)
146,159
2,953
130,703
$
143,206
_________________________
(1) The liability incurred increased $46.7 million related to the Noble properties acquired in September 2012.
(2) Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had
various upward and downward adjustments as well as changes in estimated timing of cash flows.
88
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 8 – INCOME TAXES
A reconciliation of income tax expense, computed by applying the federal statutory rate to pre-tax income to our effective
income tax expense is as follows:
Income tax expense computed by applying the statutory rate ........................ $
State income tax, net of federal benefit...........................................................
Statutory depletion and other ..........................................................................
2013
2012
(In thousands)
2011
105,514
$
13,791
$
111,651
8,290
2,919
1,084
1,351
8,941
2,543
Income tax expense.................................................................................. $
116,723
$
16,226
$
123,135
For the periods indicated, the total provision for income taxes consisted of the following:
Current taxes:
Federal...................................................................................................... $
State..........................................................................................................
Deferred taxes:
Federal......................................................................................................
State..........................................................................................................
2013
2012
(In thousands)
2011
15,845
$
146
15,991
$
2,084
(1,388)
696
(3,159)
743
(2,416)
87,839
12,893
100,732
13,768
1,762
15,530
109,363
16,188
125,551
123,135
Total provision.................................................................................. $
116,723
$
16,226
$
Deferred tax assets and liabilities are comprised of the following at December 31:
Deferred tax assets:
Allowance for losses and nondeductible accruals ............................................................... $
Net operating loss carryforward ..........................................................................................
Alternative minimum tax credit carryforward.....................................................................
2013
2012
(In thousands)
$
77,285
61,055
17,258
155,598
74,890
56,020
1,972
132,882
Deferred tax liability:
Depreciation, depletion, amortization and impairment .......................................................
Net deferred tax liability ..............................................................................................
Current deferred tax asset ...........................................................................................................
Non-current—deferred tax liability ............................................................................................ $
(943,411)
(787,813)
13,585
(801,398) $
(819,893)
(687,011)
8,765
(695,776)
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. At December 31, 2013, we have federal net operating loss carryforwards of approximately $146.5 million which
expire from 2015 to 2033.
89
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 9 – 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 111,995, 95,598, and
71,742 shares of common stock and recognized expense of $6.0 million, $5.5 million, and $4.3 million in 2013, 2012, and
2011, 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, 2013 and 2012 was $3.6
million and $2.8 million, respectively. We recognized 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. None of the
amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $2.4 million,
$2.2 million, and $1.9 million in 2013, 2012, and 2011, respectively, for benefits associated with anticipated payments from
these separation plans.
We have entered into key employee change of control contracts with three of our current executive officers. These
severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a
notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of
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.
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 10 – TRANSACTIONS WITH RELATED PARTIES
Unit Petroleum Company serves as the general partner of 16 oil and gas limited partnerships. Three were formed for
investment by third parties and 13 (the employee partnerships) 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. The partnerships for the third
party investments were formed in 1984 and 1986. Employee partnerships have been formed for each year beginning with 1984
90
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
and ending with 2011. Interests in the employee partnerships were offered to the employees of Unit and its subsidiaries whose
annual base compensation was at least a specified amount ($36,000 for 2011) and to the directors of Unit.
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:
2013
2012
(In thousands)
2011
Contract drilling .............................................................................................. $
Well supervision and other fees ...................................................................... $
General and administrative expense reimbursement....................................... $
16
470
36
$
$
$
246
434
39
$
$
$
352
396
610
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.
One of our directors, G. Bailey Peyton IV, also serves as the President and a significant investor in Upland Resources,
L.L.C., a small independent oil and natural gas exploration company, and as Manager of Peyton Royalties, LP, a family-
controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. In the ordinary course
of business, there were no wells drilled for Upland Resources, L.L.C. during 2013 or 2011 and the Company drilled three wells
during 2012, under its usual standard dayrate contracts, in which Upland Resources, L.L.C. was a participant, for which the
Company received payments of approximately $1.6 million from Upland Resources, L.L.C. The Company also paid royalties
during 2013 and 2012, 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 $1.4 million, $1.2 million, and $0.7 million during
2013, 2012, and 2011, respectively. Our Audit Committee and the board, in accordance with the Policy, have determined that
these arrangements are in the best interest of the Company.
NOTE 11 – SHAREHOLDER RIGHTS PLAN
We maintain a Shareholder Rights Plan (the Plan) designed to deter coercive or unfair takeover tactics, to prevent a
person or group from gaining control of us without offering fair value to all our shareholders and to deter other abusive
takeover tactics, which are not in the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition
and business combination criteria, entitles the shareholder to purchase from us one one-hundredth of a newly issued share of
Series A Participating Cumulative Preferred Stock at a price subject to adjustment by us or to purchase from an acquiring
company certain shares of its common stock or the surviving company’s common stock at 50% of its value.
The rights become exercisable 10 days after we learn that an acquiring person (as defined in the Plan) has acquired 15%
or more of the outstanding common stock of Unit or 10 business days after the commencement of a tender offer, which would
result in a person owning 15% or more of our shares. We can redeem the rights for $0.01 per right at any date before the earlier
91
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
of (i) the close of business on the 10th day following the time we learn that a person has become an acquiring person or
(ii) May 19, 2015 (the “Expiration Date”). The rights will expire on the Expiration Date, unless redeemed earlier by Unit.
NOTE 12 – STOCK-BASED COMPENSATION
For restricted stock awards and stock options, we had:
Recognized stock compensation expense ....................................................... $
Capitalized stock compensation cost for our oil and natural gas properties ...
Tax benefit on stock based compensation.......................................................
2013
2012
(In millions)
2011
16.1
$
11.4
$
3.5
6.2
2.7
4.5
10.0
2.5
3.9
The remaining unrecognized compensation cost related to unvested awards at December 31, 2013 is approximately $14.2
million with $2.4 million of this amount anticipated to be capitalized. The weighted average period of time over which this cost
will be recognized is 0.8 years.
At our annual meeting of stockholders held on May 2, 2012, our stockholders approved the Unit Corporation Stock and
Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan). The amended plan allows us to grant
stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as non-employee
directors. The amended plan succeeds the Non-employee Directors' 2000 Stock Option Plan (the option plan), and no new
awards will be issued under the option plan.
The amended plan allows for the issuance of 3.3 million shares of common stock 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.
92
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The table below shows the estimates of the fair value of stock options granted to our non-employee directors under the
option plan in 2011 using the Black-Scholes model and applying the estimated values also presented in the table:
Options granted .......................................................................................................................................................
Estimated fair value (in millions)............................................................................................................................
$
Estimate of stock volatility .....................................................................................................................................
Estimated dividend yield.........................................................................................................................................
Risk free interest rate ..............................................................................................................................................
Expected life range based on prior experience (in years) .......................................................................................
Forfeiture rate..........................................................................................................................................................
2011
31,500
0.7
0.48
—%
2%
5
—%
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 Unit Corporation Stock and Incentive Compensation Plan is as follows:
Number of
Shares
Weighted
Average
Grant Date
Price
Outstanding at January 1, 2011...................................................................................................
145,901
$
46.59
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
—
—
—
—
—
—
Outstanding at December 31, 2011.............................................................................................
145,901
46.59
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2012 ............................................................................................
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
—
—
—
—
—
—
145,901
46.59
—
—
—
—
—
—
Outstanding at December 31, 2013 ............................................................................................
145,901
$
46.59
There were no SARs granted in 2013, 2012, or 2011. The SARs expire after 10 years from the date of the grant. In 2013
and 2012, no shares vested. In 2011, 33,745 shares vested. The aggregate intrinsic value of the 145,901 shares outstanding at
December 31, 2013 was $0.7 million with a weighted average remaining contractual term of 3.6 years.
93
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:
Employees
Nonvested at January 1, 2011.....................................................................................................
Granted ................................................................................................................................
Vested ..................................................................................................................................
Forfeited ..............................................................................................................................
Nonvested at December 31, 2011...............................................................................................
Granted ................................................................................................................................
Vested ..................................................................................................................................
Forfeited ..............................................................................................................................
Nonvested at December 31, 2012...............................................................................................
Granted ................................................................................................................................
Vested ..................................................................................................................................
Forfeited ..............................................................................................................................
Nonvested at December 31, 2013...............................................................................................
Non-Employee Directors
Nonvested at December 31, 2011...............................................................................................
Granted ................................................................................................................................
Vested ..................................................................................................................................
Forfeited ..............................................................................................................................
Number of
Shares
Weighted
Average
Grant Date
Price
446,125
$
211,050
(190,262)
(18,952)
447,961
376,445
(220,788)
(14,091)
589,527
453,549
(248,003)
(18,330)
776,743
$
47.39
55.91
43.32
44.55
47.44
47.37
45.66
45.37
48.11
48.20
46.46
47.85
48.70
Number of
Shares
Weighted
Average
Grant Date
Price
— $
24,606
—
—
—
40.23
—
—
40.23
41.65
40.23
—
41.07
Nonvested at December 31, 2012...............................................................................................
24,606
$
Granted ................................................................................................................................
Vested ..................................................................................................................................
Forfeited ..............................................................................................................................
Nonvested at December 31, 2013...............................................................................................
21,128
(10,030)
—
35,704
$
The restricted stock awards vest in periods ranging from 2 to 3 years, except for a portion of those granted to certain
executive officers. As to those executive officers, 30% of the shares granted, or 57,405 shares in 2013, 46,441 shares in 2012,
and 20,062 shares in 2011 (the performance shares), will cliff vest in the first half of 2016, 2015, and 2014, respectively. The
actual number of performance shares that vest in 2014, 2015, and 2016 will be based on the company’s achievement of certain
performance criteria over a three-year period, and will range from 0% to 150% of the restricted shares granted as performance
shares. Based on the performance criteria, the participants will receive 65.25% of the 2011 performance based shares and are
estimated to receive the targeted amount (or 100%) of the 2012 and 2013 performance shares.
The fair value of the restricted stock granted in 2013, 2012, and 2011 at the grant date was $21.3 million, $16.9 million,
and $10.8 million, respectively. The aggregate intrinsic value of the 248,003 shares of restricted stock on their 2013 vesting
date was $11.3 million. The aggregate intrinsic value of the 776,743 shares outstanding subject to vesting at December 31,
2013 was $40.1 million with a weighted average remaining life of 1.0 year.
94
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Employee Stock Option Plan
The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and
employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became
exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The
exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In
2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further
awards were made under this plan.
Activity pertaining to the Stock Option Plan is as follows:
Number of
Shares
Weighted
Average
Exercise
Price
Outstanding at January 1, 2011...................................................................................................
184,765
$
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2011.............................................................................................
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2012 ............................................................................................
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2013 ............................................................................................
—
(42,285)
(3,500)
138,980
—
(18,850)
(2,100)
118,030
—
(48,110)
(1,000)
68,920
$
31.11
—
28.29
53.90
31.39
—
20.38
37.83
33.03
—
26.09
37.83
37.81
There were no shares that vested in 2013, 2012, or 2011. The intrinsic value of options exercised in 2013 was $1.1
million. Total cash received from the options exercised in 2013 was $0.1 million.
Exercise Prices
$37.69 - $37.83 ...............................................................................................
Outstanding and Exercisable Options at
December 31, 2013
Weighted
Average
Remaining
Contractual
Life
Weighted
Average
Exercise
Price
Number of
Shares
68,920
1.0 year
$37.81
Options for 68,920, 118,030, and 138,980 shares were exercisable with weighted average exercise prices of $37.81,
$33.03, and $31.39 at December 31, 2013, 2012, and 2011, respectively. The aggregate intrinsic value of the 68,920 shares
outstanding subject to options at December 31, 2013 was $1.0 million with a weighted average remaining contractual term of
1.0 year.
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
95
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
months of its term except in case of death. As mentioned above, on May 2, 2012, our stockholders approved the amended plan
which succeeds this plan, and no new awards will be issued 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, 2011...................................................................................................
178,500
$
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2011.............................................................................................
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2012 ............................................................................................
Granted ................................................................................................................................
Exercised .............................................................................................................................
Forfeited ..............................................................................................................................
Outstanding at December 31, 2013 ............................................................................................
31,500
(10,500)
—
199,500
—
(7,000)
—
192,500
—
(17,500)
(3,500)
171,500
$
48.77
53.81
21.96
—
48.37
—
20.28
—
49.39
—
32.53
20.46
51.70
The total grant date fair value of the 31,500 shares vesting in 2011 was $0.7 million. The intrinsic value of the 17,500
options exercised in 2013 was $0.2 million. Total cash received from options exercised in 2013 was $0.6 million.
Weighted
Average
Exercise
Price
$28.23 - $41.21 ...............................................................................................
$53.81 - $73.26 ...............................................................................................
Outstanding and Exercisable
Options at December 31, 2013
Weighted
Average
Remaining
Contractual
Life
Weighted
Average
Exercise
Price
Number of
Shares
66,500
105,000
4.6 years
4.5 years
$
$
36.64
61.24
Options for 171,500, 192,500, and 199,500 shares were exercisable with weighted average exercise prices of $51.70,
$49.39, and $48.37 at December 31, 2013, 2012, and 2011, respectively. The aggregate intrinsic value of the shares outstanding
subject to options at December 31, 2013 was $1.0 million with a weighted average remaining contractual term of 4.6 years.
96
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 hedged is based, in part, on our
view of current and future market conditions. As of December 31, 2013, our derivative transactions consisted of the following
types of hedges:
•
Swaps. We receive or pay a fixed price for the hedged 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.
• 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.
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. In August 2012, we determined on a prospective basis, to enter into
economic hedges without electing cash flow hedge accounting. Therefore, the change in fair value, on all commodity
derivatives entered into after that determination, will be reflected in the income statement and not in accumulated other
comprehensive income (OCI).
At December 31, 2013, the following non-designated hedges were outstanding:
Term
Commodity
Hedged Volume
Weighted Average
Fixed Price for
Swaps
Jan’14 – Dec’14
Natural gas – swap
80,000 MMBtu/day
$4.24
Jan’14 – Dec’14
Natural gas – collar
10,000 MMBtu/day
$3.75-4.37
Jan’14 – Jun’14
Crude oil – swap
Jan’14 – Dec’14
Crude oil – swap
Jan’14 – Dec’14
Crude oil – collar
500 Bbl/day
3,000 Bbl/day
4,000 Bbl/day
$100.03
$91.77
$90.00-96.08
Subsequent to December 31, 2013, the following non-designated hedges were entered into:
Term
Commodity
Hedged Volume
Weighted Average
Fixed Price for
Swaps
Mar'14
Mar'14
Natural gas – basis swap
30,000 MMBtu/day
Natural gas – basis swap
60,000 MMBtu/day
$(0.095)
$(0.027)
Hedged Market
IF – NYMEX (HH)
IF – NYMEX (HH)
WTI – NYMEX
WTI – NYMEX
WTI – NYMEX
Hedged Market
NGPL-TXOK
NGPL-Midcon
97
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following tables present the fair values of our derivative transactions and the location within our balance sheets where
those values are recorded at December 31:
Derivative Assets
Fair Value
Balance Sheet Location
2013
2012
(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current ............................................................................ Current derivative assets
Long-term ....................................................................... Non-current derivative assets
$
Total derivatives designated as hedging instruments.............
Derivatives not designated as hedging instruments
Commodity derivatives:
Current ............................................................................ Current derivative assets
Long-term ....................................................................... Non-current derivative assets
Total derivatives not designated as hedging instruments.......
Total derivative assets............................................................
$
— $
13,674
—
—
515
—
515
515
$
—
13,674
2,878
—
2,878
16,552
Derivative Liabilities
Fair Value
Balance Sheet Location
2013
2012
(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current ............................................................................ Current derivative liabilities
Long-term ....................................................................... Non-current derivative
$
— $
1,005
Total derivatives designated as hedging instruments.............
Derivatives not designated as hedging instruments
Commodity derivatives:
liabilities
Current ............................................................................ Current derivative liabilities
Long-term ....................................................................... Non-current derivative
liabilities
Total derivatives not designated as hedging instruments.......
Total derivative liabilities ......................................................
—
—
5,561
—
5,561
$
5,561
$
—
1,005
943
562
1,505
2,510
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our
balance sheets.
We recognized in accumulated other comprehensive income (OCI) the effective portion of any changes in fair value and
reclassified the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions were settled.
All cash flow hedges expired as of December 31, 2013, therefore we had no balance in accumulated OCI at December 31, 2013
and at December 31, 2012, we had a gain of $7.6 million, net of tax.
For our economic hedges that we elected not to apply cash flow accounting to, any changes in their fair value occurring
before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges
98
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
and hedge ineffectiveness, net in our consolidated statements of income. Changes in the fair value of derivatives that were
designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were
recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it
was reported in oil and natural gas revenues. Any change in fair value that resulted from ineffectiveness was recognized in gain
(loss) on derivatives not designated as hedges and hedge ineffectiveness, net.
Effect of Derivative Instruments on the Consolidated Balance Sheets (cash flow hedges) for the year ended December 31:
Derivatives in Cash Flow Hedging Relationships
Amount of Gain or (Loss)
Recognized in
Accumulated OCI on
Derivative
(Effective Portion) (1)
2012
2013
(In thousands)
Commodity derivatives............................................................................................................... $
— $
7,587
_________________________
(1) Net of taxes.
Effect of derivative instruments on the Consolidated Statements of Income (cash flow hedges) for the year ended
December 31:
Location of Gain or (Loss)
Reclassified
from Accumulated
OCI into Income &
Location of Gain or (Loss)
Recognized in
Income
Derivative Instrument
Commodity derivatives Oil and natural gas revenue (1)
Commodity derivatives Gain (loss) on derivatives not
designated as hedges and
hedge ineffectiveness, net (2)
Total
$
$
_________________________
(1) Effective portion of gain (loss).
(2)
Ineffective portion of gain (loss).
Amount of Gain or (Loss)
Reclassified from
Accumulated
OCI into Income (1)
2012
2013
Amount of Gain or (Loss)
Recognized in Income (2)
2013
2012
(In thousands)
603
$
51,853
$
— $
—
—
—
603
$
51,853
$
(190)
(190) $
(2,616)
(2,616)
Effect of Derivative Instruments on the Consolidated Statements of Income (derivatives not designated as hedging
instruments) for the year ended December 31:
Derivatives Not Designated as Hedging Instruments
Location of Gain or (Loss)
Recognized in Income on
Derivative
Commodity derivatives...................................................... Gain (loss) on derivatives not
designated as hedges and hedge
ineffectiveness, net (1)
Total ...................................................................................
_________________________
(1) Amount settled during the period is a loss of $(1,764) and $0, respectively.
Amount of Gain or (Loss)
Recognized in Income on
Derivative
2013
2012
(In thousands)
$
$
(8,184) $
(8,184) $
1,373
1,373
99
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 14 – FAIR VALUE MEASUREMENTS
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.
• 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, 2013
Level 2
Level 3
Effect of
Netting
Total
(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets ..................................................................... $
Liabilities................................................................
$
$
1,978
(4,429)
(2,451) $
$
20
(2,615)
(2,595) $
(1,483) $
1,483
— $
515
(5,561)
(5,046)
December 31, 2012
Level 2
Level 3
Effect of
Netting
Total
(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets ..................................................................... $
Liabilities................................................................
$
18,555
(3,918)
14,637
$
$
— $
(595)
(595) $
(2,003) $
2,003
— $
16,552
(2,510)
14,042
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, 2013.
Certain natural gas fixed price swaps were transferred from Level 3 to Level 2 as of March 31, 2012 because of
improvements in our ability to obtain and corroborate observable significant inputs to assess the fair value. Our policy is to
recognize transfers either in or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the
event or change in circumstances causing the transfer occurred.
100
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table
above.
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.
The following tables are reconciliations of our level 3 fair value measurements:
Beginning of period ........................................................................................................ $
Total gains or losses:
Included in earnings (1) ..........................................................................................
Included in other comprehensive income (loss)....................................................
Settlements.................................................................................................................
Transfers out of Level 3 into Level 2.........................................................................
End of period .................................................................................................................. $
Total gains (losses) for the period included in earnings attributable to the change in
unrealized loss relating to assets still held at end of period ........................................ $
Net Derivatives
For the Year Ended,
December 31,
2013
December 31,
2012
(In thousands)
(595) $
(2,637)
—
637
—
(2,595) $
33,615
24,484
(11,641)
(25,129)
(21,924)
(595)
(2,000) $
(645)
_________________________
(1) Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (loss) on
derivatives not designated as hedges and hedge ineffectiveness, net, respectively.
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2013:
Commodity (1)
Fair Value
(In thousands)
Valuation Technique
Unobservable Input
Range
Oil collars.......................... $
(2,246)
Discounted cash flow Forward commodity price curve
$0.20-$5.29
Natural gas collar.............. $
(349)
Discounted cash flow Forward commodity price curve
$0.00-$0.39
_________________________
(1) The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil 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, 2013, 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.
101
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
At December 31, 2013, 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 agreement at December 31, 2013
approximates its fair value. This debt would be classified as Level 2.
The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the
consolidated balance sheets at December 31, 2013 and December 31, 2012 were $645.7 million and $645.3 million,
respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2013 and December 31,
2012 were $688.2 million and $687.7 million, respectively. These Notes would be classified as Level 2.
NOTE 15 – ACCUMULATED OTHER COMPREHENSIVE INCOME
Changes in accumulated other comprehensive income (loss) by component, net of tax, are as follows:
Net Gains (Losses) on Cash Flow Hedges
2012
(In thousands)
2013
2011
Balance at January 1: ........................................................................................ $
Other comprehensive income before reclassification ....................................
Amounts reclassified from accumulated other comprehensive income.........
New current-period other comprehensive income............................................
Balance at December 31: .................................................................................. $
7,587
(7,349)
(238)
(7,587)
$
19,026
$
18,635
(30,074)
(11,439)
7,587
$
(6,851)
29,384
(3,507)
25,877
19,026
— $
Amounts reclassified from accumulated other comprehensive income (loss) into the consolidated statements of income for
the year ended December 31:
2013
2012
(In thousands)
2011
Affected Line Item in the Statement
Where Net Income is Presented
Net gains (loss) on cash flow hedges
Commodity derivatives .................. $
603
$
51,853
$
2,965
Oil and natural gas revenues
Commodity derivatives ..................
(190)
413
(175)
Total reclassification for the period.. $
238
$
(2,616)
49,237
(19,163)
30,074
2,749
5,714
(2,207)
3,507
$
Gain (loss) on derivatives not designated
as hedges and hedge ineffectiveness, net
Total before tax
Tax expense
Net of tax
NOTE 16 – COMMITMENTS AND CONTINGENCIES
We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado;
Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through September, 2017.
Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess
drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are
approximately $8.4 million, $3.4 million, $0.6 million, and $0.1 million in 2014 through 2017, respectively. Total rent expense
incurred was $16.9 million, $14.0 million, and $8.5 million in 2013, 2012, and 2011, respectively.
102
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with
the employee oil and gas limited partnerships 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. These repurchases in any one year are limited to 20%
of the units outstanding. We made repurchases of $16,000 in 2013, 56,000 in 2012, and $22,000 in 2011.
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.
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 the next twelve months, we have committed to purchase approximately $11.4 million of new drilling rig components,
drill pipe, drill collars and related equipment and $0.6 million remaining towards a gas treating plant.
We are subject to various legal proceedings arising in the ordinary course of our various businesses none of which, in our
opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash
flows.
NOTE 17 – INDUSTRY SEGMENT 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 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.
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.
103
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table provides certain information about the operations of each of our segments:
2013
2012
(In thousands)
2011
Revenues:
Oil and natural gas .................................................................................... $
Contract drilling ........................................................................................
Elimination of inter-segment revenue.......................................................
Contract drilling net of inter-segment revenue .........................................
Gas gathering and processing ...................................................................
Elimination of inter-segment revenue.......................................................
Gas gathering and processing net of inter-segment revenue.....................
Total revenues ........................................................................................... $
Operating income:
Oil and natural gas .................................................................................... $
Contract drilling ........................................................................................
Gas gathering and processing ...................................................................
Total operating income (1)..........................................................................
General and administrative expense..........................................................
Gain (loss) on disposition of assets...........................................................
Interest expense, net ..................................................................................
Gain (loss) on derivatives not designated as hedges and hedge
ineffectiveness, net....................................................................................
Other income (expense), net .....................................................................
Income before income taxes ..................................................................... $
Identifiable assets:
Oil and natural gas .................................................................................... $
Contract drilling ........................................................................................
Gas gathering and processing ...................................................................
Total identifiable assets (2) .........................................................................
Corporate assets ........................................................................................
Total assets ................................................................................................ $
Capital expenditures:
Oil and natural gas (5) ................................................................................ $
Contract drilling ........................................................................................
Gas gathering and processing ...................................................................
Other (5)......................................................................................................
Total capital expenditures ......................................................................... $
Depreciation, depletion, amortization, and impairment:
Oil and natural gas:
Depreciation, depletion and amortization ............................................
Impairment of oil and natural gas properties .......................................
Contract drilling ........................................................................................
Gas gathering and processing ...................................................................
Other..........................................................................................................
Total depreciation, depletion, amortization, and impairment ................... $
649,718
479,091
(64,313)
414,778
378,397
(91,043)
287,354
1,351,850
239,219
96,304
10,757
346,280
(38,323)
17,076
(15,015)
(8,374)
(175)
301,469
2,441,792
1,042,661
473,717
3,958,170
64,220
4,022,390
531,233
64,325
96,085
4,483
696,126
226,498
—
71,194
33,191
3,024
333,907
$
$
$
$
$
$
$
$
$
567,944
579,368
(49,649)
529,719
290,773
(73,313)
217,460
1,315,123
(77,221)
159,188
5,780
87,747
(33,086)
253
(14,137)
(1,243)
(132)
39,402
2,214,029
1,079,736
413,708
3,707,473
53,647
3,761,120
1,145,337
77,520
183,162
11,083
1,417,102
$
514,614
536,872
(52,221)
484,651
284,248
(76,010)
208,238
$ 1,207,503
$
(3)
(4)
$
199,993
135,085
17,278
352,356
(30,055)
(595)
(4,167)
1,702
(239)
319,002
$ 1,820,492
1,118,666
247,763
3,186,921
69,799
$ 3,256,720
$
$
$
588,158
162,208
79,355
2,688
832,409
183,350
—
79,667
16,101
1,333
280,451
(3)
(4)
211,347
283,606
81,007
24,388
2,279
602,627
_________________________
(1) Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general
corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income
(loss), or income taxes.
(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, corporate leasehold improvements, furniture and equipment.
In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write downs of our oil and natural
gas properties of $115.9 million pre-tax ($72.1 million net of tax) and $167.7 million pre-tax ($104.4 million net of tax), respectively.
104
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(4) Depreciation, depletion, amortization, and impairment for gas gathering and processing includes a $1.2 million write down of our Erick system.
(5) Reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $16,988 and $8,103 for 2012 and 2011, respectively.
NOTE 18 – 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)
2013
Revenues................................................................. $
Gross profit ............................................................. $
Net income.............................................................. $
Net income per common share:
318,532
83,683
40,206
Basic ................................................................ $
Diluted ............................................................. $
0.84
0.83
2012
Revenues................................................................. $
Gross profit (loss) ................................................... $
Net income (loss).................................................... $
Net income (loss) per common share:
333,966
95,912
52,439
Basic ................................................................ $
Diluted ............................................................. $
1.10
1.09
$
$
$
$
$
$
$
$
$
$
340,421
90,823
59,007
1.22
1.22
$
$
$
$
$
333,776
79,082
34,232
0.71
0.70
$
327,785
(22,253) $
(19,302) $
321,790
95,921
46,586
(0.40) $
(0.40) $
0.97
0.97
$
$
$
$
$
$
$
$
$
$
359,121
92,692 (1)
51,301
1.06
1.05
331,582
(81,833) (1)
(56,547)
(1.18) (2)
(1.18)
_________________________
(1) Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and
hedge ineffectiveness, income taxes, and other income (loss).
(2) Due to the effect of rounding the basic earnings per share for the year’s four quarters does not equal annual earnings per share.
105
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
Our oil and gas operations are substantially located in the United States. We do have operations in Canada that are
insignificant. The capitalized costs at year-end and costs incurred during the year were as follows:
2013
2012
(In thousands)
2011
Capitalized costs:
Proved properties ..................................................................................... $
Unproved properties.................................................................................
4,235,712
$
3,822,381
$
3,302,032
545,588
521,659
185,632
Accumulated depreciation, depletion, amortization, and impairment .....
Net capitalized costs ......................................................................... $
Cost incurred:
Unproved properties acquired.................................................................. $
Proved properties acquired ......................................................................
Exploration...............................................................................................
Development ............................................................................................
Asset retirement obligation ......................................................................
Total costs incurred........................................................................... $
4,781,300
(2,439,458)
2,341,842
76,304
—
33,373
424,314
(17,951)
516,040
$
$
$
$
4,344,040
(2,216,787)
2,127,253
420,467
225,669
46,467
390,649
45,097
3,487,664
(1,724,312)
1,763,352
70,999
50,013
43,836
391,862
23,345
$
1,128,349
$
580,055
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31,
2013, by the year in which such costs were incurred:
Unproved properties acquired and wells
in progress ............................................ $
92,929
$
412,623
$
32,492
$
7,544
$
545,588
2013
2012
2011
(In thousands)
2010 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:
Revenues ......................................................................................................... $
Production costs ..............................................................................................
Depreciation, depletion, amortization, and impairment..................................
Income tax (expense) benefit ..........................................................................
Results of operations for producing activities (excluding corporate
2013
2012
(In thousands)
2011
$
633,792
(162,822)
(222,672)
248,298
(96,091)
$
557,003
(131,389)
(492,475)
(66,861)
27,533
505,450
(115,400)
(181,960)
208,090
(80,323)
overhead and financing costs) ..................................................................... $
152,207
$
(39,328) $
127,767
106
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
(In thousands)
Natural Gas
Mcf
2013
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...........................................................................................................................
2012
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...........................................................................................................................
2011
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...........................................................................................................................
_________________________
(1) Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.
107
21,998
(2,113)
4,678
2,299
—
(3,360)
(1,737)
21,765
16,441
15,594
5,557
6,171
20,255
(1,747)
5,014
4,196
2,830
(3,279)
(5,271)
21,998
15,618
16,441
4,637
5,557
17,494
374
3,477
1,229
192
(2,511)
—
20,255
12,773
15,618
4,721
4,637
35,166
836
7,273
1,945
—
(3,914)
(101)
41,205
25,657
30,437
9,509
10,768
22,087
(2,682)
4,819
3,018
11,098
(2,796)
(378)
35,166
16,649
25,657
5,438
9,509
16,117
2,112
3,924
1,780
393
(2,239)
—
22,087
12,088
16,649
4,029
5,438
555,647
2,421
68,611
21,573
11
(56,757)
(9,722)
581,784
452,844
464,234
102,803
117,550
442,135
(55,110)
54,761
25,057
141,494
(48,930)
(3,760)
555,647
372,311
452,844
69,824
102,803
420,486
(30,510)
39,836
15,592
40,835
(44,104)
—
442,135
346,928
372,311
73,558
69,824
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 and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural
gas reserves. SMOG as of December 31 is as follows:
Future cash flows ............................................................................................ $
Future production costs ...................................................................................
Future development costs................................................................................
Future income tax expenses ............................................................................
Future net cash flows ......................................................................................
10% annual discount for estimated timing of cash flows ...............................
Standardized measure of discounted future net cash flows relating to
2013
2012
(In thousands)
2011
$
$
5,573,119
(1,734,985)
(571,170)
(1,044,608)
2,222,356
(996,380)
4,522,351
(1,405,773)
(431,673)
(762,519)
1,922,386
(842,430)
4,583,629
(1,277,856)
(340,992)
(952,736)
2,012,045
(924,136)
proved oil, NGLs, and natural gas reserves................................................. $
1,225,976
$
1,079,956
$
1,087,909
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
Sales and transfers of oil and natural gas produced, net of production costs.. $
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............................................................................................
End of year ...................................................................................................... $
2013
2012
(In thousands)
2011
(470,970) $
188,826
(10,650)
426,377
(425,626) $
(321,099)
(148,648)
432,058
26,629
96,457
9
(43,435)
147,579
(170,091)
(44,711)
146,020
1,079,956
51,587
104,377
283,774
(112,359)
157,842
94,678
(124,537)
(7,953)
1,087,909
(389,339)
115,852
(38,336)
401,134
37,742
45,327
58,567
(29)
128,492
(60,675)
(65,912)
232,823
855,086
1,225,976
$
1,079,956
$
1,087,909
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 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
108
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.
The December 31, 2013, future cash flows were computed by applying the unescalated 12-month average prices of
$96.94 per barrel for oil, $41.03 per barrel for NGLs, and $3.67 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.
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, based on continuation of existing economic
conditions.
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
(a) Evaluation of Disclosure Controls and Procedures
The company maintains “disclosure controls and procedures,” as that term is defined in Rule 13a-15(e) and Rule 15d-15
(e) under the Securities Exchange Act of 1934 (the Exchange Act), that are designed to ensure that information required to be
disclosed in reports the company files or submits under the Exchange Act is recorded, processed, summarized, and reported
within the time periods specified in SEC rules and forms, and that such information is collected and communicated to
management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure. In designing and evaluating its disclosure controls and procedures, our management recognized
that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute,
assurance that the objectives of the disclosure controls and procedures are met. Our disclosure controls and procedures have
been designed to meet, and our management believes that they meet, reasonable assurance standards. Based on their evaluation
as of the end of the period covered by this Annual Report on Form 10-K, our Chief Executive Officer and Chief Financial
Officer have concluded that, subject to the limitations noted above, the company’s disclosure controls and procedures were
effective.
(b) 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 Chief Executive Officer and Chief Financial Officer,
conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control—
Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
the results of this evaluation, our management concluded that our internal control over financial reporting was effective as of
December 31, 2013.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2013, has been audited
by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears
herein.
109
(c) Changes in Internal Control Over Financial Reporting
During the last quarter, there were no changes in our internal control over financial reporting that have materially affected,
or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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 7, 2014.
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 of our corporate governance listing standards
of the NYSE. Our Chief Executive Officer made his annual certification to that effect to the NYSE as of May 8, 2013. 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 14, 2014 concerning each of our
executive officers as well as 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 ..
AGE
POSITION HELD
59 Chief Executive Officer since April 1, 2005, Director since January 15, 2004, President since
August 1, 2003, Chief Operating Officer since February 24, 2004, Vice President and Chief
Financial Officer from May 1989 to February 24, 2004
Mark E. Schell.......
56 Senior Vice President since December 2002, General Counsel and Corporate Secretary since
January 1987
David T. Merrill.....
53 Senior Vice President since May 2, 2012, Chief Financial Officer and Treasurer since February
24, 2004, Vice President of Finance from August 2003 to February 24, 2004
Brad J. Guidry .......
John Cromling.......
Robert Parks ..........
58 Executive Vice President, Unit Petroleum Company since March 1, 2005
66 Executive Vice President, Unit Drilling Company since April 15, 2005
59 Manager and President, Superior Pipeline Company, L.L.C. since June 1996
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. In April 2005, he also began
serving as Chief Executive Officer. Mr. Pinkston holds the offices of President, Chief Executive Officer, and Chief Operating
Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma.
110
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 as well as the Association of Corporate Counsel. Mr. Schell is a director of the Oklahoma Independent Petroleum
Association and is Chairman of its legal committee. In addition, he is the President and a director of the Oklahoma Injury
Benefit Coalition, an Oklahoma non-profit association advocating for alternatives to Oklahoma's current Workers'
Compensation system. 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.
Mr. Merrill 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.
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. From July 1994 through July 1996
he was Director of Financial 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.
Mr. Guidry joined Unit Petroleum Company in August 1988 as a Staff Geologist. In 1991, he was promoted to Geologic
Manager overseeing the Geologic Operations of the company. In January 2003, he was promoted to Vice President of the West
division. In March 2005, Mr. Guidry was promoted to Senior Vice President of Exploration for Unit Petroleum Company. From
1979 to 1988, he was employed as a Division Geologist for Reading and Bates Petroleum Co. From 1978 to 1979, he worked
with ANR Resources in Houston. He began his career as an open hole well logging engineer with Dresser Atlas Oilfield
Services. Mr. Guidry graduated from Louisiana State University with a Bachelor of Science degree in Geology.
Mr. Cromling joined Unit Drilling Company in 1997 as a Vice-President and Division Manager. In April 2005, he was
promoted to the position of Executive Vice-President of Drilling for Unit Drilling Company. In 1980, 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.
Mr. Parks founded Superior Pipeline Company, L.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. Parks began his career as an
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.
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).
111
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,
2013, 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)
240,420 (2) $
—
240,420 $
47.72
—
47.72
1,604,390 (3)
—
1,604,390
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)
This number includes the following:
68,920 stock options outstanding under the company’s Amended and Restated Stock Option Plan.
171,500 stock options outstanding under the Non-Employee Directors’ Stock Option Plan.
(3)
This number reflects the shares available for issuance under the Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May
2, 2012 (the amended plan). The amended plan allows us to grant stock-based compensation to our employees and non-employee directors. The previous
balance of 230,000 shares that were available for issuance under the Non-Employee Directors’ Stock Option Plan were transferred to the amended plan
on May 2, 2012. 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).
112
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, 2013 and 2012
Consolidated Statements of Income for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012, and 2011
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2011, 2012, and 2013
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Included in Part IV of this report for the years ended December 31, 2013, 2012, and 2011:
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
Item 601 of Regulation S-K.
3.1
3.1.2
3.2
4.1
4.2
4.3
4.4
4.5
4.6
Restated Certificate of Incorporation of Unit Corporation (filed as Exhibit 3.1 to Unit's Form 8-K, dated June 29,
2000, which is incorporated herein by reference).
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 May 7, 2008 (filed as Exhibit 3.2 to Unit’s Form 8-K,
dated May 8, 2008 which is incorporated herein by reference).
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).
Rights Agreement as amended and restated on May 18, 2005 (filed as Exhibit 4.1 to Unit’s Form 8-K dated May
18, 2005, which is incorporated herein by reference).
Amendment to Rights Agreement dated March 24, 2009 (filed as Exhibit 4.1 to Unit’s Form 8-K dated March 23,
2009, which is incorporated herein by reference).
Standstill Agreement dated March 24, 2009, by and between us and the George Kaiser Foundation (filed as
Exhibit 4.2 to Unit’s Form 8-K dated March 23, 2009, 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).
First Supplemental Indenture (including form of note) dated as of May 18, 2011, by and among the Company, as
issuer, the Subsidiary Guarantors (as defined therein), as guarantors 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).
113
4.7
10.1.1
10.1.2*
10.1.3*
10.1.4
10.1.5
10.1.6
10.1.7
10.2.1
10.2.2
10.2.3*
10.2.4*
10.2.5*
10.2.6
10.2.7*
10.2.8*
10.2.9*
10.2.10
Registration Rights Agreement dated July 24, 2012, among Unit Corporation, certain of its wholly-owned
subsidiaries party thereto, as guarantors, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as the
representative of the several initial purchasers (filed as Exhibit 4.3 to Unit’s Form 8-K dated July 24, 2012, which
is incorporated herein by reference).
Third Amended and Restated Security Agreement effective November 1, 2005 (filed as Exhibit 10.2 to Unit’s
Form 8-K dated November 4, 2005, which is incorporated herein by reference).
Form of Unit Corporation Restricted Stock Bonus Agreement (filed as Exhibit 10.1 to Unit’s Form 8-K dated
December 13, 2005, which is incorporated herein by reference).
Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (filed as Exhibit
10 to Unit’s Form 8-K dated May 2, 2012, which is incorporated herein by reference).
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).
Gas Purchase Agreement dated November 21, 2011 by and between Superior Pipeline Company, L.L.C. and
Sullivan and Company, L.L.C. (filed as Exhibit 10.1 to Unit’s Form 8-K dated November 21, 2011, which is
incorporated herein by reference).
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, 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 5, 2012, which is incorporated herein by reference).
Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and
Exploration Company’s Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated
herein by reference).
Unit 1984 Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Oil and
Gas Program’s Registration Statement Form S-1 as S.E.C. File No. 2-92582, which is incorporated herein by
reference).
Unit’s Amended and Restated Stock Option Plan (filed as an Exhibit to Unit’s Registration Statement on Form
S-8 as S.E.C. File No’s. 33-19652, 33-44103, 33-64323 and 333-39584 which is incorporated herein by
reference).
Unit Corporation Non-Employee Directors’ Stock Option Plan (filed as an Exhibit to Form S-8 as S.E.C. File No.
33-49724 and File No. 333-166605, which are incorporated herein by reference).
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).
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 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).
Unit Corporation Separation Benefit Plan for Senior Management as amended (filed as an Exhibit 10.1 to Unit’s
Form 8-K dated December 20, 2004).
Unit Corporation Special Separation Benefit Plan as amended (filed as Exhibit 10.3 to Unit’s Form 8-K dated
December 20, 2004).
Unit 2000 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, 1999).
10.2.11*
Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan (filed as an Exhibit to Form S-8 as S.E.C.
File No. 333-38166, which is incorporated herein by reference).
114
10.2.12
10.2.13
10.2.14
10.2.15
10.2.16
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).
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).
10.2.17*
Form of Indemnification Agreement entered into between the Company and its executive officers and directors
(filed as Exhibit 10.1 to Unit’s Form 8-K dated February 22, 2005, which is incorporated herein by reference).
10.2.18
10.2.19
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).
10.2.20*
Separation Benefit Plan as amended August 21, 2007 (filed as an Exhibit to Unit’s Form 10-Q for the quarter
ended September 30, 2007).
10.2.21
10.2.22*
10.2.23*
10.2.24*
10.2.25*
10.2.26*
10.2.27
10.2.28*
10.2.29
10.2.30
21
23.1
23.2
31.1
31.2
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).
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).
Separation Benefit Plan as amended October 21, 2008 (filed as Exhibit 10.2 to Unit’s Form 8-K dated October
23, 2008, which is incorporated herein by reference).
Separation Benefit Plan as amended December 31, 2008 (filed as Exhibit 10.1 to Unit’s Form 8-K dated January
6, 2009, which is incorporated herein by reference).
Special Separation Benefit Plan as amended December 31, 2008 (filed as Exhibit 10.2 to Unit’s Form 8-K dated
January 6, 2009, 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 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 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 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).
Subsidiaries of the Registrant (filed herein).
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (filed herein).
Consent of Ryder Scott Company, L.P. (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).
115
32
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).
99.1
Ryder Scott Company, L.P. Summary 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.
116
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, 2013........................................... $
Year ended December 31, 2012........................................... $
Year ended December 31, 2011........................................... $
5,343
5,343
5,083
$
$
$
(In thousands)
— $
90
260
$
$
(1) $
(90) $
— $
5,342
5,343
5,343
117
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
UNIT CORPORATION
DATE: February 25, 2014
By:
/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 25th day of February, 2014.
Name
Title
/s/ JOHN G. NIKKEL
John G. Nikkel
/s/ LARRY D. PINKSTON
Larry D. Pinkston
/s/ DAVID T. MERRILL
David T. Merrill
/s/ DON A. HAYES
Don A. Hayes
Chairman of the Board and Director
President and Chief Executive Officer,
Chief Operating Officer and Director
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and
Treasurer (Principal Financial Officer)
Vice President, Controller
(Principal Accounting Officer)
/s/ J. MICHAEL ADCOCK
Director
J. Michael Adcock
/s/ GARY CHRISTOPHER
Director
Gary Christopher
/s/ STEVEN B. HILDEBRAND
Director
Steven B. Hildebrand
/s/ WILLIAM B. MORGAN
Director
William B. Morgan
/s/ LARRY C. PAYNE
Larry C. Payne
Director
/s/ G. BAILEY PEYTON IV
Director
G. Bailey Peyton IV
/s/ ROBERT SULLIVAN, JR.
Director
Robert Sullivan, Jr.
118
EXHIBIT INDEX
Exhibit No.
21
Description
Subsidiaries of the Registrant.
23.1
23.2
31.1
31.2
32
99.1
101.INS
101.SCH
101.CAL
101.DEF
101.LAB
101.PRE
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
Consent of Ryder Scott Company, L.P.
Certification of Chief Executive Officer under Rule 13a—14(a) of the Exchange Act.
Certification of Chief Financial Officer under Rule 13a—14(a) of the Exchange Act.
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.
Ryder Scott Company, L.P. Summary Report.
XBRL Instance Document.
XBRL Taxonomy Extension Schema Document.
XBRL Taxonomy Extension Calculation Linkbase Document.
XBRL Taxonomy Extension Definition Linkbase Document.
XBRL Taxonomy Extension Labels Linkbase Document.
XBRL Taxonomy Extension Presentation Linkbase Document.
119
CORPORATE INfORMATION
Board of Directors
Management
Transfer Agent & Registrar
John G. nikkel
Chairman of the board
J. Michael adcock
Chairman of the board of
arvest bank, shawnee
and Trustee, Don bodard Trust
shawnee, oklahoma
Gary r. Christopher
investments
Tulsa, oklahoma
steven b. Hildebrand
investments
Tulsa, oklahoma
William b. Morgan
investments
Chandler, arizona
larry C. payne
president and Ceo of lesa and
associates, llC
Tulsa, oklahoma
G. bailey peyton iV
president, peyton Holdings
Canadian, Texas
John G. nikkel
Chairman of the board
larry D. pinkston
president and
Chief executive officer
Mark e. schell
senior Vice president,
General Counsel, and secretary
David T. Merrill
senior Vice president,
Chief financial officer,
and Treasurer
Compensation Committee
J. Michael adcock
Chairman
William b. Morgan
steven b. Hildebrand
Gary r. Christopher
Nominating
& Governance Committee
larry D. pinkston
Chief executive officer and president
robert J. sullivan, Jr.
Manager of sullivan and Company llC
Tulsa, oklahoma
William b. Morgan
Chairman
J. Michael adcock
larry C. payne
robert J. sullivan Jr.
Director Emeritus
Audit Committee
King p. Kirchner
Co-founder, Unit Corporation
Tulsa, oklahoma
steven b. Hildebrand
Chairman
Gary r. Christopher
William b. Morgan
J. Michael adcock
larry C. payne
Communications concerning the transfer of shares, lost
certificates and changes of address should be directed to:
american stock Transfer & Trust Co.
59 Maiden lane, plaza level
new York, nY 10038
800.710.0929
amstock.com
Stock Listing
our common stock trades on the new York stock exchange
under the symbol: “UnT.”
During 2013, our average daily trading volume on the nYse
was 228,000 shares.
approximately 49.1 million shares were outstanding at the
end of 2013.
Annual Meeting
of Shareholders
May 7, 2014, 11:00 a.m. Central Time
Tulsa room, bank of oklahoma Tower, 9th floor, Tulsa,
oklahoma
Shareholder Profile
We had 1,030 shareholders of record
at year-end 2013.
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 web site 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
7130 south lewis avenue, suite 1000
Tulsa, oklahoma 74136
918.493.7700
Independent Registered Public
Accounting firm
pricewaterhouseCoopers llp
Tulsa, oklahoma
Independent Petroleum
Engineers
ryder scott Company, l.p.
Houston, Texas
Unit Corporation
www.unitcorp.com