Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the fourth quarter and year end 2017. Fourth
quarter and year end highlights include:
-
Fourth quarter net income of $89.2 million, which reflects an $81.3
million net tax benefit related to tax legislation enacted in the
quarter, and adjusted net income of $11.3 million. -
Oil and natural gas segment production increased 6% over the third
quarter of 2017. -
Total year-end 2017 proved oil and natural gas reserves increased 27%
over 2016. - Replaced 300% of 2017 production with new reserves.
-
Contract drilling segment placed its 10th BOSS rig into service in
2017; all ten BOSS rigs continuously operated under contract during
the year. - Average drilling rigs used in 2017 increased 72% over 2016.
-
Midstream segment increased liquids sold and gas processed volumes 10%
and 6%, respectively, over the third quarter.
FOURTH QUARTER AND YEAR END 2017 FINANCIAL RESULTS
Unit recorded net income of $89.2 million for the quarter, or $1.71 per
diluted share, compared to net income of $1.7 million, or $0.03 per
share, for the fourth quarter of 2016. Net income for the quarter
included an $81.3 million income tax benefit associated with the
revaluation of the net deferred tax liability due to the Tax Cuts and
Jobs Act (the Tax Act) enacted during the quarter by the U.S.
government. Adjusted net income (which excludes the effect of non-cash
commodity derivatives and the effect of the Tax Act) for the quarter was
$11.3 million, or $0.22 per diluted share (see Non-GAAP financial
measures below). Total revenues for the quarter were $204.8 million (49%
oil and natural gas, 23% contract drilling, and 28% midstream), compared
to $174.3 million (51% oil and natural gas, 19% contract drilling, and
30% midstream) for the fourth quarter of 2016. Adjusted EBITDA was $91.2
million, or $1.75 per diluted share (see Non-GAAP financial measures
below).
For 2017, Unit recorded net income of $117.8 million, or $2.28 per
diluted share, compared to a net loss of $135.6 million, or a loss of
$2.71 per share, for 2016. Net income for the year included the $81.3
million income tax benefit associated with the revaluation of the net
deferred tax liability due to the Tax Act. Unit recorded adjusted net
income (which excludes the effect of non-cash commodity derivatives and
the effect of the Tax Act) of $27.7 million, or $0.54 per diluted share
(see Non-GAAP financial measures below). Total revenues for the year
were $739.6 million (48% oil and natural gas, 24% contract drilling, and
28% midstream), compared to $602.2 million (49% oil and natural gas, 20%
contract drilling, and 31% midstream) for 2016. Adjusted EBITDA for 2017
was $315.7 million, or $6.10 per diluted share (see Non-GAAP financial
measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total equivalent production was 4.3 million barrels of
oil equivalent (MMBoe), a 6% increase over the third quarter of 2017.
Oil and natural gas liquids (NGLs) production represented 46% of total
equivalent production. Oil production was 7,877 barrels per day. NGLs
production was 13,713 barrels per day. Natural gas production was 151.6
million cubic feet (MMcf) per day. Total production for 2017 was 16.0
MMBoe, a 7% decrease from 2016.
Unit’s average realized per barrel equivalent price for the quarter was
$23.25, a 13% increase over the third quarter of 2017. Unit’s average
natural gas price was $2.38 per Mcf, an increase of 1% over the third
quarter of 2017. Unit’s average oil price was $54.45 per barrel, an
increase of 15% over the third quarter of 2017. Unit’s average NGLs
price was $21.88 per barrel, an increase of 19% over the third quarter
of 2017. All prices in this paragraph include the effects of derivative
contracts.
In the Wilcox area, Unit continued its exploration and recompletion
programs during the quarter. In the Cherry Creek prospect, production
from the Trinity #1 well was brought online with an initial 30-day
production (IP30) rate of 6 MMcfe per day. The Trinity is a discovery
well with several additional zones to be developed. Unit is planning to
drill the second well in the prospect later in 2018. In the Brandt
prospect, Unit successfully drilled and completed a new discovery well,
the Engel #1, with an IP30 rate of 8.3 MMcfe per day. In addition, there
were 10 new behind pipe recompletions, increasing combined production
for those wells 16 MMcf per day and 500 barrels of oil per day at a cost
of $3 million. Unit’s plan for 2018 is for 13-15 recompletions and 10
new wells (8 vertical and 2 horizontal).
In the Texas Panhandle Granite Wash area, during the quarter, Unit
completed the Dixon 5554 CXL #5H well and the Dixon 5554 CXL #6H well.
The Dixon 5554 CXL #6H is Unit’s first extended length lateral well
targeting the B interval of the Granite Wash and had an IP30 rate of 9.4
MMcfe per day, which is above type curve expectations. Unit also drilled
three of its longest laterals to date, which range from 8,700 feet to
9,700 feet, targeting the C1 interval of the Granite Wash. The three
wells were completed in January and are in the early stages of flowing
back. Unit’s plan is to continuously operate at least one drilling rig
in the Granite Wash during 2018, which is planned to result in 11 new
extended length lateral wells.
In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, during the
quarter, Unit completed two new Marchand horizontal wells. Production
for both wells was brought online in late November. The Nina #1-22H had
an IP30 rate of 1,114 Boe per day and the Schmidt #1-10H had an IP30
rate of 691 Boe per day, both of which are above type curve
expectations. Unit began drilling its first extended lateral Marchand
well, the Schenk Trust 1-17HXL, in late November. Production from this
well was brought online in late January with strong results at an IP20
rate of 2,468 Boe per day. During 2018, Unit plans to continue with a
one rig drilling program, which should result in nine new wells, with
six being extended lateral wells.
In western Oklahoma, Unit owns approximately 17,000 net acres in the
STACK play. Unit continues its effort to acquire and concentrate its
acreage position to facilitate horizontal well development, and Unit
plans to initiate drilling in this area during the first quarter of 2018.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Our
oil and natural gas segment had its third consecutive quarter of
production growth. We are very pleased to be on a solid production
growth trajectory. We continue to be encouraged by the results in each
of our three core areas. All three have provided rates of return that
compare favorably with other active basins.”
This table illustrates certain comparative production, realized prices,
and operating profit for the periods indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||||||
|
Dec 31, |
Dec 31, |
Change |
Dec 31, |
Sept 30, |
Change |
Dec 31, |
Dec 31, |
Change | |||||||||||||||||||
| Oil and NGLs Production, MBbl | 1,986 | 1,983 | – | % | 1,986 | 1,876 | 6 | % | 7,453 | 7,988 | (7 | )% | |||||||||||||||
| Natural Gas Production, Bcf | 13.9 | 13.4 | 4 | % | 13.9 | 13.1 | 7 | % | 51.3 | 55.7 | (8 | )% | |||||||||||||||
| Production, MBoe | 4,310 | 4,209 | 2 | % | 4,310 | 4,057 | 6 | % | 15,996 | 17,277 | (7 | )% | |||||||||||||||
| Production, MBoe/day | 46.8 | 45.8 | 2 | % | 46.8 | 44.1 | 6 | % | 43.8 | 47.2 | (7 | )% | |||||||||||||||
| Avg. Realized Natural Gas Price, Mcf (1) | $ | 2.38 | $ | 2.37 | – | % | $ | 2.38 | $ | 2.36 | 1 | % | $ | 2.46 | $ | 2.07 | 19 | % | |||||||||
| Avg. Realized NGL Price, Bbl (1) | $ | 21.88 | $ | 14.57 | 50 | % | $ | 21.88 | $ | 18.35 | 19 | % | $ | 18.35 | $ | 11.26 | 63 | % | |||||||||
| Avg. Realized Oil Price, Bbl (1) | $ | 54.45 | $ | 46.14 | 18 | % | $ | 54.45 | $ | 47.29 | 15 | % | $ | 49.44 | $ | 40.50 | 22 | % | |||||||||
| Realized Price / Boe (1) | $ | 23.25 | $ | 19.73 | 18 | % | $ | 23.25 | $ | 20.63 | 13 | % | $ | 21.72 | $ | 16.92 | 28 | % | |||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2) |
$ | 66.6 | $ | 60.4 | 10 | % | $ | 66.6 | $ | 51.6 | 29 | % | $ | 227.0 | $ | 174.0 | 30 | % | |||||||||
| (1) |
Realized price includes oil, NGLs, natural gas, and associated derivatives. |
|
| (2) |
Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See Non-GAAP financial measures below.) |
|
YEAR END 2017 ESTIMATED PROVED RESERVES
The discount rate (PV-10) value of Unit’s estimated year end 2017 proved
reserves increased 56% over 2016 to $897.5 million. Estimated year end
2017 proved oil and natural gas reserves were 149.8 MMBoe, or 898.6
billion cubic feet of natural gas equivalents (Bcfe), as compared with
117.8 MMBoe, or 706.6 Bcfe, at year end 2016, a 27% increase. Estimated
reserves were 13% oil, 30% NGLs, and 57% natural gas.
The following details the changes to Unit’s proved oil, NGLs, and
natural gas reserves during 2017:
|
Oil |
NGLs |
Natural Gas |
Proved |
|||||||||
| Proved Reserves, at December 31, 2016 | 15.7 | 34.5 | 405.6 | 117.8 | ||||||||
| Revisions of previous estimates | 0.7 | 4.3 | 38.4 | 11.4 | ||||||||
|
Extensions, discoveries, and other
additions |
3.9 | 10.3 | 101.6 | 31.1 | ||||||||
| Purchases of minerals in place | 2.0 | 1.2 | 15.3 | 5.8 | ||||||||
| Production | (2.7 | ) | (4.7 | ) | (51.3 | ) | (16.0 | ) | ||||
| Sales | (0.1 | ) | (0.1 | ) | (0.9 | ) | (0.3 | ) | ||||
| Proved Reserves, at December 31, 2017 | 19.5 | 45.5 | 508.7 | 149.8 | ||||||||
Estimated 2017 year-end proved reserves included proved developed
reserves of 113.0 MMBoe, or 677.8 Bcfe, (13% oil, 30% NGLs, and 57%
natural gas) and proved undeveloped reserves of 36.8 MMBoe, or 220.9
Bcfe, (13% oil, 33% NGLs, and 54% natural gas). Overall, 75% of the
estimated proved reserves are proved developed.
The present value of the estimated future net cash flows from 2017
estimated proved reserves (before income taxes and using a PV-10), is
approximately $897.5 million. The present value was determined using the
required SEC’s pricing methodology. The aggregate price used for all
future reserves was $51.34 per barrel of oil, $31.83 per barrel of NGLs,
and $2.98 per Mcf of natural gas (then adjusted for price
differentials). Unit’s 2017 year-end proved reserves were independently
audited by Ryder Scott Company, L.P. Their audit covered properties
accounting for 86% of the discounted future net cash flow (PV-10). See
below for the reconciliation of PV-10 to the Standardized Measure of
discounted future net cash flows as defined by GAAP.
Pinkston said: “Our goal is to replace at least 150% of each year’s
production with new reserves. In 2017, we achieved our goal by replacing
300% of production with new reserves, our second highest production
replacement percentage in the last 15 years. We achieved this growth
while maintaining a capital expenditure program in line with cash flow.”
CONTRACT DRILLING SEGMENT INFORMATION
Unit’s average number of drilling rigs working during the quarter was
31.2, a decrease of 10% from the third quarter of 2017. Per day drilling
rig rates averaged $16,645, a 1% increase over the third quarter of
2017. Average per day operating margin for the quarter was $5,550
(before elimination of intercompany drilling rig profit of $0.6
million). This compares to third quarter 2017 average operating margin
of $5,495 (before elimination of intercompany drilling rig profit of
$0.6 million), an increase of 1%, or $55.
Pinkston said: “Our contract drilling segment’s level of utilization
grew through the third quarter to a high of 36 operating rigs.
Utilization pared back in the fourth quarter as operators approached the
limits of their 2017 capital budgets. We have 95 drilling rigs in our
fleet after adding our tenth BOSS rig during the second quarter. All 10
of our BOSS rigs are under contract, and we currently have a total of 32
drilling rigs operating. Long-term contracts (contracts with original
terms ranging from six months to two years in length) are in place for
nine of our drilling rigs. Of the nine contracts, four are up for
renewal in the first quarter of 2018, three in the second quarter, one
in the fourth quarter and one in 2019.”
This table illustrates certain comparative results for the periods
indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||||||
|
Dec 31, |
Dec 31, |
Change |
Dec 31, |
Sept 30, |
Change |
Dec 31, |
Dec 31, |
Change | |||||||||||||||||||
| Rigs Utilized | 31.2 | 19.5 | 60 | % | 31.2 | 34.6 | (10 | )% | 30.0 | 17.4 | 72 | % | |||||||||||||||
| Operating Profit Before Depreciation (MM) (1) | $ | 15.3 | $ | 11.6 | 31 | % | $ | 15.3 | $ | 16.9 | (9 | )% | $ | 52.1 | $ | 33.9 | 54 | % | |||||||||
| (1) |
Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation. (See Non-GAAP financial measures below.) |
|
MIDSTREAM SEGMENT INFORMATION
For the quarter, gas processed and liquids sold volumes per day
increased 6% and 10%, respectively, while gas gathered volumes per day
remained relatively unchanged, as compared to the third quarter of 2017.
Operating profit (as defined in the footnote below) for the quarter was
$13.1 million, a decrease of 2% from the third quarter of 2017.
For 2017, per day gas gathered and gas processed volumes decreased 8%
and 11%, respectively, while liquids sold volumes remained relatively
unchanged as compared to 2016. Operating profit (as defined in the
footnote below) for 2017 was $51.7 million, an increase of 7% over 2016.
This table illustrates certain comparative results for the periods
indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||||||
|
Dec 31, |
Dec 31, |
Change |
Dec 31, |
Sept 30, |
Change |
Dec 31, |
Dec 31, |
Change | |||||||||||||||||||
| Gas Gathering, Mcf/day | 383,319 | 423,669 | (10 | )% | 383,319 | 383,787 | – | % | 385,209 | 419,217 | (8 | )% | |||||||||||||||
| Gas Processing, Mcf/day | 148,422 | 140,719 | 5 | % | 148,422 | 140,246 | 6 | % | 137,625 | 155,461 | (11 | )% | |||||||||||||||
| Liquids Sold, Gallons/day | 581,874 | 535,253 | 9 | % | 581,874 | 530,028 | 10 | % | 534,140 | 536,494 | – | % | |||||||||||||||
| Operating Profit Before Depreciation and Amortization (MM) (1) | $ | 13.1 | $ | 14.7 | (11 | )% | $ | 13.1 | $ | 13.3 | (2 | )% | $ | 51.7 | $ | 48.3 | 7 | % | |||||||||
| (1) |
Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and amortization. (See Non-GAAP financial measures below.) |
|
Pinkston said: “Our midstream segment operated in ethane rejection mode
during the quarter at all processing facilities except Bellmon and
Cashion, where it is more beneficial to recover under the existing
contracts. Processing and liquids sold volumes reflected quarter over
quarter improvement due to increasing processing volumes at the Hemphill
and Cashion facilities. Overall, our midstream segment continues to post
solid results as operator activity levels increase; in fact, we set a
new record operating profit before depreciation and amortization for the
year.”
2018 CAPITAL BUDGET AND PRODUCTION GUIDANCE
Pinkston said: “The outlook for commodity prices continues to be
volatile. We continue to be diligent with our capital expenditure plans
to maintain our spending in line with anticipated cash flow plus any
proceeds derived from non-core asset sales. Our focus is to continue to
grow all three business segments while retaining the financial
discipline our shareholders have grown to expect.”
Unit’s 2018 capital expenditures budget is $352 million, which
represents a 27% increase over 2017, excluding acquisitions. The capital
expenditures plan by segment is: $272 million for the oil and natural
gas segment, $47 million for the contract drilling segment, and $32
million for the midstream segment, representing an increase of 26%, 30%
and 44%, respectively, over 2017. The budget for the year includes no
costs for potential acquisitions and is based on prices, after applying
differentials and hedges, averaging $53.19 per barrel for oil, $22.18
per barrel for NGLs, and $2.16 per Mcf for natural gas. As always,
Unit’s capital budget is subject to periodic review based on prevailing
conditions.
In 2017, year over year production in Unit’s oil and natural gas segment
declined 7%; however, in each of the last three quarters of 2017
production grew sequentially. It is anticipated that 2018 production
should grow to 17.1 to 17.4 MMBoe, or 7% to 9% year over year from 2017.
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $820.3 million, consisting
of $642.3 million of senior subordinated notes (net of unamortized
discount and debt issuance costs) and $178.0 million of borrowings under
the company’s credit agreement. During October, Unit’s borrowing base
was re-determined with no resulting change. Under the credit agreement,
the amount Unit can borrow is the lesser of the amount it elects as the
commitment amount ($475 million) or the value of its borrowing base as
determined by the lenders ($475 million).
WEBCAST
Unit uses its website to disclose material nonpublic information and for
complying with its disclosure obligations under Regulation FD. Those
disclosures will be included on its website in the ‘Investor
Information’ sections. Accordingly, investors should monitor that
portion of the website, besides following the press releases, SEC
filings, and public conference calls and webcasts.
Unit will webcast its fourth quarter earnings conference call live over
the Internet on February 22, 2018 at 10:00 a.m. Central Time (11:00 a.m.
Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm
at least fifteen minutes before the start of the call to download and
install any necessary audio software. For those who are not available to
listen to the live webcast, a replay will be available shortly after the
call and will remain on the site for 90 days.
_____________________________________________________
Unit Corporation is a Tulsa-based, publicly held energy company engaged
through its subsidiaries in oil and gas exploration, production,
contract drilling, and gas gathering and processing. Unit’s Common Stock
is on the New York Stock Exchange under the symbol UNT. For more
information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
This news release contains forward-looking statements within the meaning
of the private Securities Litigation Reform Act. All statements, other
than statements of historical facts, included in this release that
address activities, events, or developments that the company expects,
believes, or anticipates will or may occur are forward-looking
statements. Several risks and uncertainties could cause actual results
to differ materially from these statements, including changes in
commodity prices, the productive capabilities of the company’s wells,
future demand for oil and natural gas, future drilling rig utilization
and dayrates, projected rate of the company’s oil and natural gas
production, the amount available to the company for borrowings, its
anticipated borrowing needs under its credit agreement, the number of
wells to be drilled by the company’s oil and natural gas segment, the
potential productive capability of its prospective plays including the
STACK play, the number of additional shares (if any) it may sell under
its “at the market” offering, and other factors described occasionally
in the company’s publicly available SEC reports. The company assumes no
obligation to update publicly such forward-looking statements, whether
because of new information, future events, or otherwise.
| Unit Corporation | ||||||||||||||||
| Selected Financial Highlights | ||||||||||||||||
|
(In thousands except per share amounts) |
||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Statement of Operations: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil and natural gas | $ | 101,503 | $ | 87,903 | $ | 357,744 | $ | 294,221 | ||||||||
| Contract drilling | 46,661 | 33,300 | 174,720 | 122,086 | ||||||||||||
| Gas gathering and processing | 56,683 | 53,077 | 207,176 | 185,870 | ||||||||||||
| Total revenues | 204,847 | 174,280 | 739,640 | 602,177 | ||||||||||||
| Expenses: | ||||||||||||||||
| Operating costs: | ||||||||||||||||
| Oil and natural gas | 34,916 | 27,493 | 130,789 | 120,184 | ||||||||||||
| Contract drilling | 31,387 | 21,665 | 122,600 | 88,154 | ||||||||||||
| Gas gathering and processing | 43,621 | 38,424 | 155,483 | 137,609 | ||||||||||||
| Total operating costs | 109,924 | 87,582 | 408,872 | 345,947 | ||||||||||||
| Depreciation, depletion, and amortization | 57,712 | 48,925 | 209,257 | 208,353 | ||||||||||||
| Impairments | – | – | – | 161,563 | ||||||||||||
| General and administrative | 11,185 | 8,517 | 38,087 | 33,337 | ||||||||||||
| (Gain) loss on disposition of assets | 826 | (1,717 | ) | (327 | ) | (2,540 | ) | |||||||||
| Total expenses | 179,647 | 143,307 | 655,889 | 746,660 | ||||||||||||
| Income (loss) from operations | 25,200 | 30,973 | 83,751 | (144,483 | ) | |||||||||||
| Other income (expense): | ||||||||||||||||
| Interest, net | (9,527 | ) | (9,604 | ) | (38,334 | ) | (39,829 | ) | ||||||||
| Gain (loss) on derivatives not designated as hedges | (6,287 | ) | (18,039 | ) | 14,732 | (22,813 | ) | |||||||||
| Other | 7 | 318 | 21 | 307 | ||||||||||||
| Total other income (expense) | (15,807 | ) | (27,325 | ) | (23,581 | ) | (62,335 | ) | ||||||||
| Income (loss) before income taxes | 9,393 | 3,648 | 60,170 | (206,818 | ) | |||||||||||
| Income tax expense (benefit): | ||||||||||||||||
| Current | 5 | 15 | 5 | 15 | ||||||||||||
| Deferred | (79,767 | ) | 1,950 | (57,683 | ) | (71,209 | ) | |||||||||
| Total income taxes | (79,762 | ) | 1,965 | (57,678 | ) | (71,194 | ) | |||||||||
| Net income (loss) | $ | 89,155 | $ | 1,683 | $ | 117,848 | $ | (135,624 | ) | |||||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | 1.74 | $ | 0.03 | $ | 2.31 | $ | (2.71 | ) | |||||||
| Diluted | $ | 1.71 | $ | 0.03 | $ | 2.28 | $ | (2.71 | ) | |||||||
| Weighted average shares outstanding: | ||||||||||||||||
| Basic | 51,394 | 50,081 | 51,113 | 50,029 | ||||||||||||
| Diluted | 52,201 | 50,949 | 51,748 | 50,029 | ||||||||||||
| December 31, | December 31, | |||||||
| 2017 | 2016 | |||||||
| Balance Sheet Data: | ||||||||
| Current assets | $ | 119,672 | $ | 121,196 | ||||
| Total assets | $ | 2,581,452 | $ | 2,479,303 | ||||
| Current liabilities | $ | 181,936 | $ | 164,915 | ||||
| Long-term debt | $ | 820,276 | $ | 800,917 | ||||
| Other long-term liabilities | $ | 100,203 | $ | 103,479 | ||||
| Deferred income taxes | $ | 133,477 | $ | 215,922 | ||||
| Shareholders’ equity | $ | 1,345,560 | $ | 1,194,070 | ||||
| Twelve Months Ended December 31, | ||||||||
| 2017 | 2016 | |||||||
| Statement of Cash Flows Data: | ||||||||
|
Cash flow from operations before changes in operating assets and liabilities |
$ | 276,811 | $ | 205,888 | ||||
| Net change in operating assets and liabilities | 2,777 | 34,242 | ||||||
| Net cash provided by operating activities | $ | 279,588 | $ | 240,130 | ||||
| Net cash used in investing activities | $ | (306,998 | ) | $ | (110,971 | ) | ||
| Net cash provided by (used in) financing activities | $ | 27,218 | $ | (129,101 | ) | |||
Non-GAAP Financial Measures
Unit Corporation reports its financial results under generally accepted
accounting principles (“GAAP”). The company believes certain Non-GAAP
performance measures provide users of its financial information and its
management additional meaningful information to evaluate the performance
of the company.
This press release includes net income (loss) and earnings (loss) per
share excluding impairment adjustments, the effect of the cash settled
commodity derivatives and the effect of the tax benefit from the Tax
Act, its exploration and production segment’s reconciliation of PV-10 to
Standard Measure, its reconciliation of segment operating profit, its
drilling segment’s average daily operating margin before elimination of
intercompany drilling rig profit and bad debt expense, its cash flow
from operations before changes in operating assets and liabilities, and
its reconciliation of net income (loss) to adjusted EBITDA.
Below is a reconciliation of GAAP financial measures to Non-GAAP
financial measures for the three and twelve months ended December 31,
2017 and 2016. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported under GAAP. This
Non-GAAP information should be considered by the reader besides, but not
instead of, the financial statements prepared under GAAP. The Non-GAAP
financial information presented may be determined or calculated
differently by other companies and may not be comparable to similarly
titled measures.
| Unit Corporation | ||||||||||||||||
| Reconciliation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) per Share |
||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| (In thousands except earnings per share) | ||||||||||||||||
| Adjusted net income: | ||||||||||||||||
| Net income (loss) | $ | 89,155 | $ | 1,683 | $ | 117,848 | $ | (135,624 | ) | |||||||
| Impairment adjustment (net of income tax) | – | – | – | 100,573 | ||||||||||||
| (Gain) loss on derivatives (net of income tax) | 2,930 | 11,845 | (8,949 | ) | 14,960 | |||||||||||
|
Settlements during the period of matured derivative contracts (net of income tax) |
517 | (1,322 | ) | 105 | 6,333 | |||||||||||
| Tax Act income tax benefit | (81,307 | ) | – | (81,307 | ) | – | ||||||||||
| Adjusted net income (loss) | $ | 11,295 | $ | 12,206 | $ | 27,697 | $ | (13,758 | ) | |||||||
| Adjusted diluted earnings per share: | ||||||||||||||||
| Diluted earnings (loss) per share | $ | 1.71 | $ | 0.03 | $ | 2.28 | $ | (2.71 | ) | |||||||
| Diluted earnings per share from the impairments | – | – | – | 2.01 | ||||||||||||
| Diluted earnings per share from the (gain) loss on derivatives | 0.06 | 0.23 | (0.17 | ) | 0.30 | |||||||||||
|
Diluted earnings (loss) per share from the settlements of matured derivative contracts |
0.01 | (0.03 | ) | – | 0.12 | |||||||||||
| Diluted earnings (loss) per share from the Tax Act income tax benefit | (1.56 | ) | – | (1.57 | ) | – | ||||||||||
| Adjusted diluted earnings (loss) per share | $ | 0.22 | $ | 0.23 | $ | 0.54 | $ | (0.28 | ) | |||||||
________________
The company has included the net income and diluted earnings per share
including only the cash settled commodity derivatives because:
-
It uses the adjusted net income to evaluate the operational
performance of the company. -
The adjusted net income is more comparable to earnings estimates
provided by securities analysts.
Unaudited Reconciliation of PV-10 to Standard Measure
December
31, 2017
PV-10 is the estimated future net cash flows from proved reserves
discounted at an annual rate of 10 percent before giving effect to
income taxes. Standardized Measure is the after-tax estimated future
cash flows from proved reserves discounted at an annual rate of 10
percent, determined under GAAP. The company uses PV-10 as one measure of
the value of its proved reserves and to compare relative values of
proved reserves among exploration and production companies without
regard to income taxes. The company believes that securities analysts
and rating agencies use PV-10 in similar ways. The company’s management
believes PV-10 is a useful measure for comparison of proved reserve
values among companies because, unlike Standardized Measure, it excludes
future income taxes that often depend principally on the characteristics
of the owner of the reserves rather than on the nature, location and
quality of the reserves themselves. Below is a reconciliation of PV-10
to Standardized Measure:
| 2017 | ||||||
| (In millions) | ||||||
| PV-10 at December 31, 2017 | $ | 897.5 | ||||
| Discounted effect of income taxes | (90.3 | ) | ||||
| Standardized Measure at December 31, 2017 | $ | 807.2 | ||||
| Unit Corporation | ||||||||||||||||||||
| Reconciliation of Segment Operating Profit | ||||||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||||||
| September 30, | December 31, | December 31, | ||||||||||||||||||
| 2017 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Oil and natural gas | $ | 51,559 | $ | 66,587 | $ | 60,410 | $ | 226,955 | $ | 174,037 | ||||||||||
| Contract drilling | 16,872 | 15,274 | 11,635 | 52,120 | 33,932 | |||||||||||||||
| Gas gathering and processing | 13,283 | 13,062 | 14,653 | 51,693 | 48,261 | |||||||||||||||
|
Total operating profit |
81,714 | 94,923 | 86,698 | 330,768 | 256,230 | |||||||||||||||
| Depreciation, depletion and amortization | (54,533 | ) | (57,712 | ) | (48,925 | ) | (209,257 | ) | (208,353 | ) | ||||||||||
| Impairments | – | – | – | – | (161,563 | ) | ||||||||||||||
| Total operating income (loss) | 27,181 | 37,211 | 37,773 | 121,511 | (113,686 | ) | ||||||||||||||
| General and administrative | (9,235 | ) | (11,185 | ) | (8,517 | ) | (38,087 | ) | (33,337 | ) | ||||||||||
| Gain (loss) on disposition of assets | 81 | (826 | ) | 1,717 | 327 | 2,540 | ||||||||||||||
| Interest, net | (9,944 | ) | (9,527 | ) | (9,604 | ) | (38,334 | ) | (39,829 | ) | ||||||||||
| Gain (loss) on derivatives | (2,614 | ) | (6,287 | ) | (18,039 | ) | 14,732 | (22,813 | ) | |||||||||||
| Other | 5 | 7 | 318 | 21 | 307 | |||||||||||||||
| Income (loss) before income taxes | $ | 5,474 | $ | 9,393 | $ | 3,648 | $ | 60,170 | $ | (206,818 | ) | |||||||||
________________
The company has included segment operating profit because:
-
It considers segment operating profit to be an important supplemental
measure of operating performance for presenting trends in its core
businesses. -
Segment operating profit is useful to investors because it provides a
means to evaluate the operating performance of the segments and
company on an ongoing basis using criteria used by management.
| Unit Corporation | |||||||||||||||
| Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit |
|||||||||||||||
| and Bad Debt Expense | |||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||
| September 30, | December 31, | December 31, | |||||||||||||
| 2017 | 2017 | 2016 | 2017 | 2016 | |||||||||||
| (In thousands except for operating days and operating margins) | |||||||||||||||
| Contract drilling revenue | $ | 51,619 | $ | 46,661 | $ | 33,300 | $ | 174,720 | $ | 122,086 | |||||
| Contract drilling operating cost | 34,747 | 31,387 | 21,665 | 122,600 | 88,154 | ||||||||||
| Operating profit from contract drilling | 16,872 | 15,274 | 11,635 | 52,120 | 33,932 | ||||||||||
| Add: | |||||||||||||||
| Elimination of intercompany rig profit and bad debt expense | 602 | 642 | – | 1,620 | 235 | ||||||||||
|
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense |
17,474 | 15,916 | 11,635 | 53,740 | 34,167 | ||||||||||
| Contract drilling operating days | 3,180 | 2,868 | 1,796 | 10,964 | 6,374 | ||||||||||
|
Average daily operating margin before elimination of intercompany rig profit and bad debt expense |
$ | 5,495 | $ | 5,550 | $ | 6,478 | $ | 4,901 | $ | 5,360 | |||||
________________
The company has included the average daily operating margin before
elimination of intercompany rig profit and bad debt expense because:
-
Its management uses the measurement to evaluate the cash flow
performance of its contract drilling segment and to evaluate the
performance of contract drilling management. -
It is used by investors and financial analysts to evaluate the
performance of the company.
| Unit Corporation | ||||||||
| Reconciliation of Cash Flow from Operations Before Changes in Operating Assets and Liabilities |
||||||||
|
Twelve Months Ended |
||||||||
| 2017 | 2016 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 279,588 | $ | 240,130 | ||||
| Net change in operating assets and liabilities | (2,777 | ) | (34,242 | ) | ||||
|
Cash flow from operations before changes in operating assets and liabilities |
$ | 276,811 | $ | 205,888 | ||||
________________
The company has included the cash flow from operations before changes in
operating assets and liabilities because:
-
It is an accepted financial indicator used by its management and
companies in the industry to measure the company’s ability to generate
cash used to internally fund its business activities. -
It is used by investors and financial analysts to evaluate the
performance of the company.
| Unit Corporation | ||||||||||||||||
| Reconciliation of Adjusted EBITDA | ||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| (In thousands except earnings per share) | ||||||||||||||||
| Net income (loss) | $ | 89,155 | $ | 1,683 | $ | 117,848 | $ | (135,624 | ) | |||||||
| Income taxes | (79,762 | ) | 1,965 | (57,678 | ) | (71,194 | ) | |||||||||
| Depreciation, depletion and amortization | 57,712 | 48,925 | 209,257 | 208,353 | ||||||||||||
| Amortization of debt issuance costs and debt discounts | 543 | 536 | 2,159 | 2,122 | ||||||||||||
| Impairments | – | – | – | 161,563 | ||||||||||||
| Interest expense | 9,527 | 9,604 | 38,334 | 39,829 | ||||||||||||
| (Gain) loss on derivatives | 6,287 | 18,039 | (14,732 | ) | 22,813 | |||||||||||
| Settlements during the period of matured derivative contracts | 902 | (2,077 | ) | 173 | 9,658 | |||||||||||
| Stock compensation plans | 5,269 | 3,148 | 17,747 | 13,812 | ||||||||||||
| Other non-cash items | 774 | 632 | 2,886 | 2,779 | ||||||||||||
| (Gain) loss on disposition of assets | 826 | (1,717 | ) | (327 | ) | (2,540 | ) | |||||||||
| Adjusted EBITDA | $ | 91,233 | $ | 80,738 | $ | 315,667 | $ | 251,571 | ||||||||
| Diluted earnings (loss) per share | $ | 1.71 | $ | 0.03 | $ | 2.28 | $ | (2.71 | ) | |||||||
| Diluted earnings per share from income taxes | (1.53 | ) | 0.04 | (1.11 | ) | (1.42 | ) | |||||||||
|
Diluted earnings per share from depreciation, depletion and amortization |
1.11 | 0.96 | 4.04 | 4.12 | ||||||||||||
|
Diluted earnings per share from amortization of debt issuance costs and debt discounts |
0.01 | 0.01 | 0.04 | 0.04 | ||||||||||||
| Diluted earnings per share from impairments | – | – | – | 3.24 | ||||||||||||
| Diluted earnings per share from interest expense | 0.18 | 0.19 | 0.74 | 0.79 | ||||||||||||
| Diluted earnings per share from the (gain) loss on derivatives | 0.12 | 0.35 | (0.28 | ) | 0.45 | |||||||||||
|
Diluted earnings per share from the settlements during the period of matured derivative contracts |
0.02 | (0.04 | ) | – | 0.20 | |||||||||||
| Diluted earnings per share from stock compensation plans | 0.10 | 0.06 | 0.34 | 0.27 | ||||||||||||
| Diluted earnings per share from other non-cash items | 0.01 | 0.01 | 0.06 | 0.05 | ||||||||||||
| Diluted earnings per share (gain) loss on disposition of assets | 0.02 | (0.03 | ) | (0.01 | ) | (0.05 | ) | |||||||||
| Adjusted EBITDA per diluted share | $ | 1.75 | $ | 1.58 | $ | 6.10 | $ | 4.98 | ||||||||
________________
The company has included adjusted EBITDA, which excludes gain or loss on
disposition of assets and includes only the cash settled commodity
derivatives because:
-
It uses adjusted EBITDA to evaluate the operational performance of the
company. -
Adjusted EBITDA is more comparable to estimates provided by securities
analysts.
View source version on businesswire.com: http://www.businesswire.com/news/home/20180222005322/en/
Unit Corporation
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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