Unit Corporation (NYSE – UNT) today reported its financial and
operational results for the fourth quarter and year-end 2018. Fourth
quarter and 2018 operational highlights include:
-
Oil and natural gas segment production increased 7% year-over-year
from 2017. -
Total year-end 2018 proved oil and natural gas reserves increased 7%
over 2017, and 158% of 2018 production was replaced with new reserves. -
In December, Unit acquired approximately 8,700 net acres in the Penn
sands play in western Oklahoma adding additional oil prospects similar
to Unit’s existing Southern Oklahoma Hoxbar Oil Trend (SOHOT) play.
The final adjusted price of the acquisition totaled approximately
$29.6 million and included net proved reserves of 2.6 million barrels
of oil equivalent (MMBoe). The acquisition provides Unit with 20 to 30
horizontal drilling locations and 82% of the acreage is held by
production. -
Contract drilling segment placed its 11th BOSS rig into service during
the second quarter. Its 12th BOSS rig was placed into service during
January 2019. Further, its 13th BOSS rig was recently
placed into service under a long-term contract. -
During the quarter, the mid-stream segment completed the connection of
the Miller Pad to its Pittsburgh Mills gathering system. The wells
from the new pad began being placed online in late January 2019. -
The mid-stream segment’s natural gas gathering, processing and liquids
sold volumes increased 2%, 15% and 24% year-over-year, respectively. -
Unit amended its bank credit agreement during the quarter, in part
extending its maturity until October 2023.
FOURTH QUARTER AND YEAR-END 2018 FINANCIAL RESULTS
Net loss attributable to Unit for the quarter was $77.8 million, or
$1.49 loss per diluted share, compared to net income attributable to
Unit of $89.2 million, or $1.71 per diluted share, for the fourth
quarter of 2017. (For the fourth quarter of 2017, Unit recorded an $81.3
million net tax benefit related to tax legislation enacted during the
quarter.) For the fourth quarter of 2018, Unit recorded a pre-tax
non-cash write-down of $147.9 million associated with the removal of 41
drilling rigs from its drilling fleet along with some other equipment.
The drilling rigs removed from service included our remaining 29
mechanical drilling rigs and 12 SCR drilling rigs. The company
strategically decided to focus on its new BOSS drilling rigs and
specific SCR drilling rigs (good candidates for modification) and sell
the other drilling rigs it now chooses not to market. Adjusted net
income attributable to Unit for the quarter (which excludes the effect
of non-cash commodity derivatives and the write-down) was $13.8 million,
or $0.27 per diluted share compared to $0.22 per diluted share for the
same quarter for 2017, a 22% increase in adjusted net income (see
Non-GAAP financial measures below). Total revenues for the quarter were
$214.8 million (49% oil and natural gas, 25% contract drilling, and 26%
mid-stream), compared to $204.8 million (49% oil and natural gas, 23%
contract drilling, and 28% mid-stream) for the fourth quarter of 2017.
Adjusted EBITDA attributable to Unit was $88.2 million, or $1.69 per
diluted share (see Non-GAAP financial measures below).
For 2018, net loss attributable to Unit was $45.3 million, or $0.87 loss
per diluted share, compared to net income of $117.8 million, or $2.28
per diluted share, for 2017 (which included the net tax benefit
discussed above). For the same period, adjusted net income attributable
to Unit (which excludes the effect of non-cash commodity derivatives and
the write-down) was $51.9 million, or $1.00 per diluted share, compared
to $0.54 per diluted share for 2017, an 87% increase in adjusted net
income (see Non-GAAP financial measures below). Total revenues for the
year were $843.3 million (50% oil and natural gas, 23% contract
drilling, and 27% mid-stream), compared to $739.6 million (48% oil and
natural gas, 24% contract drilling, and 28% mid-stream) for 2017.
Adjusted EBITDA attributable to Unit for 2018 was $349.7 million, or
$6.73 per diluted share (see Non-GAAP financial measures below).
MANAGEMENT COMMENTS
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“During the fourth quarter, as part of our periodic evaluation process,
we removed 41 drilling rigs from our fleet as well as some other
equipment. Those rigs included our 29 remaining mechanical drilling rigs
and 12 of our SCR drilling rigs that were not considered to be economic
to upgrade to meet market demands. Our remaining rig fleet includes 13
BOSS AC drilling rigs as well as upgraded SCR rigs that are well suited
for current operator requirements. Additionally, we have other SCR rigs
that are available to return to service as market conditions and demand
improve or are good candidates for upgrade to meet future customer
demands and requirements. Our drilling rig fleet now totals 57 rigs.”
“For our oil and natural gas segment, we are focusing on increasing the
proportion of oil in our production mix. As part of this effort, we are
building a position in western Oklahoma to add drilling inventory in
prospective areas we believe have a greater concentration of oil. We
continue to look for bolt-on opportunities near our existing core areas.”
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total equivalent production was 4.3 MMBoe, a 1%
decrease from the third quarter of 2018. Oil and natural gas liquids
(NGLs) production represented 46% of total equivalent production, of
which, oil production increased 9% over the third quarter of 2018. Oil
production was 8,187 barrels per day. NGLs production was 13,290 barrels
per day. Natural gas production was 152.8 million cubic feet (MMcf) per
day. Overall, total production for 2018 was 17.1 MMBoe, a 7% increase
over 2017.
Unit’s average realized per barrel equivalent price for the quarter was
$23.99, a 1% decrease from the third quarter of 2018. Unit’s average oil
price was $54.01 per barrel, a decrease of 6% from the third quarter of
2018. Unit’s average NGLs price was $19.61 per barrel, a decrease of 24%
from the third quarter of 2018. Unit’s average natural gas price was
$2.77 per Mcf, an increase of 22% over the third quarter of 2018. All
prices in this paragraph include the effects of derivative contracts.
Late in the third quarter 2018, Unit drilled the Schrock 22/15 #1HX in
the Penn sands prospect area in western Oklahoma, the first Red Fork
extended lateral well drilled in Oklahoma. The Schrock IP30 was over
2,000 barrels of oil equivalent (Boe) per day with an approximate 80%
oil cut. In addition, Unit brought on the Frymire 1-18H, a second Red
Fork lateral well in late October, which had an IP30 of 850 Boe per day
that was primarily high BTU natural gas with some oil. The well cost for
the Red Fork wells was approximately $6 million for a one-mile lateral
and $7.5 million for a two-mile lateral. Subsequent to these well
results, Unit acquired offsetting oil and natural gas assets in December
for $29.6 million. The acquired properties added approximately 8,700 net
acres largely held by production to the Penn sands area, including 44
wells and approximately 2.6 MMBoe of proved reserves. The acquisition
provides Unit approximately 20 to 30 horizontal Red Fork drilling
locations, which are anticipated to have a significant percentage of oil
in the total production stream.
In the SOHOT play, in western Oklahoma, primarily in Grady County, Unit
continues to drill horizontal wells in the oily Marchand sand. Unit is
having success adding small parcels of acreage at a reasonable cost
which should permit the company to add a second rig to its drilling
program in the second quarter.
In the Texas Panhandle Granite Wash play, Unit continued its one rig
drilling program. The results from its first two Granite Wash “G”
extended lateral wells in the field have been good with initial rates
from each well exceeding 10 MMcfe per day. Unit is continuing with its
Granite Wash drilling program through the first quarter of 2019 before
moving the rig to its western Oklahoma assets that are likely to have a
higher oil cut. Unit’s land position in the Texas Panhandle area is
largely held by production allowing it to drill when pricing is most
optimal.
In the Wilcox play, Unit continued its development drilling and
re-completion program during the fourth quarter. Additionally, Unit
drilled a successful delineation well in its Shoal Creek prospect that
has continued to increase in production since coming online in October
and is currently producing approximately 8.5 MMcfe per day of high BTU
gas and oil. Unit will continue delineating this and other prospects in
2019, one of which will be the Wolf Pasture #1, the first delineation
well in its Cherry Creek prospect. In addition, Unit plans to complete
approximately 10 behind pipe gas and liquids zones during 2019.
Pinkston said: “Our oil and natural gas segment continues to focus on
expanding the favorable results we have obtained western Oklahoma by
increasing our footprint in that area. Our acquisition in the Penn sands
area follows the strong results from our two Red Fork wells described in
the operations update. We remain focused on adding to this position.”
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 | ||||||||||||||||
| 2018 | 2017 | 2018 | 2018 | 2018 | 2017 | |||||||||||||||||||
| Oil and NGLs Production, MBbl | 1,976 | 1,986 | (1)% | 1,976 | 1,970 | -% | 7,799 | 7,453 | 5% | |||||||||||||||
| Natural Gas Production, Bcf | 14.1 | 13.9 | 1% | 14.1 | 14.3 | (2)% | 55.6 | 51.3 | 9% | |||||||||||||||
| Production, MBoe | 4,318 | 4,310 | -% | 4,318 | 4,359 | (1)% | 17,070 | 15,996 | 7% | |||||||||||||||
| Production, MBoe/day | 46.9 | 46.8 | -% | 46.9 | 47.4 | (1)% | 46.8 | 43.8 | 7% | |||||||||||||||
| Avg. Realized Natural Gas Price, Mcf (1) | $ | 2.77 | $ | 2.38 | 16% | $ | 2.77 | $ | 2.27 | 22% | $ | 2.46 | $ | 2.46 | -% | |||||||||
| Avg. Realized NGL Price, Bbl (1) | $ | 19.61 | $ | 21.88 | (10)% | $ | 19.61 | $ | 25.66 | (24)% | $ | 22.18 | $ | 18.35 | 21% | |||||||||
|
Avg. Realized Oil Price, Bbl (1) |
$ | 54.01 | $ | 54.45 | (1)% | $ | 54.01 | $ | 57.72 | (6)% | $ | 55.78 | $ | 49.44 | 13% | |||||||||
|
Realized Price / Boe (1) |
$ | 23.99 | $ | 23.25 | 3% | $ | 23.99 | $ | 24.15 | (1)% | $ | 23.80 | $ | 21.72 | 10% | |||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2) |
$ | 74.9 | $ | 66.6 | 12% | $ | 74.9 | $ | 79.5 | (6)% | $ | 291.4 | $ | 227.0 | 28% | |||||||||
| 1. |
Realized price includes oil, NGLs, natural gas, and associated derivatives. |
|
| 2. |
Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See Non-GAAP financial measures below.) |
YEAR-END 2018 ESTIMATED PROVED RESERVES
The discount rate (PV-10) value of Unit’s estimated year-end 2018 proved
reserves increased 23% over 2017 to $1.1 billion. Estimated year-end
2018 proved oil and natural gas reserves were 159.7 MMBoe, or 958.1
billion cubic feet of natural gas equivalents (Bcfe), as compared with
149.8 MMBoe, or 898.6 Bcfe, at year-end 2017, a 7% increase. Estimated
reserves were 14% oil, 30% NGLs, and 56% natural gas.
The following details the changes to Unit’s proved oil, NGLs, and
natural gas reserves during 2018:
| Proved | ||||||||
| Oil | NGLs | Natural Gas | Reserves | |||||
| (MMbls) | (MMbls) | (Bcf) | (MMBoe) | |||||
| Proved Reserves, at December 31, 2017 | 19.5 | 45.5 | 508.7 | 149.8 | ||||
| Revisions of previous estimates | 0.2 | (1.4) | (17.9) | (4.1) | ||||
|
Extensions, discoveries, and other
additions |
5.2 | 7.9 | 99.6 | 29.7 | ||||
| Purchases of minerals in place | 0.7 | 0.9 | 6.9 | 2.7 | ||||
| Production | (2.9) | (4.9) | (55.6) | (17.1) | ||||
| Sales | (0.1) | (0.2) | (5.7) | (1.3) | ||||
| Proved Reserves, at December 31, 2018 | 22.6 | 47.8 | 536.0 | 159.7 |
Estimated 2018 year-end proved reserves included proved developed
reserves of 111.6 MMBoe, or 669.5 Bcfe, (14% oil, 30% NGLs, and 56%
natural gas) and proved undeveloped reserves of 48.1 MMBoe, or 288.6
Bcfe, (15% oil, 30% NGLs, and 55% natural gas). Overall, 70% of the
estimated proved reserves are proved developed.
The present value of the estimated future net cash flows from 2018
estimated proved reserves (before income taxes and using a PV-10), is
approximately $1.1 billion. The present value was determined using the
required SEC’s pricing methodology. The benchmark price used for all
future reserves was $65.56 per barrel of oil, $37.68 per barrel of NGLs,
and $3.10 per Mcf of natural gas (then adjusted for price
differentials). Ryder Scott Company, L.P. independently audited Unit’s
2018 year-end proved reserves. Their audit covered properties accounting
for 82% 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 2018, we achieved our goal by replacing
158% of production with new reserves and maintained a capital
expenditure program in line with our cash flow and proceeds from
divestitures.”
CONTRACT DRILLING SEGMENT INFORMATION
Unit’s average number of working drilling rigs during the quarter was
33.1, a decrease of 3% from the third quarter of 2018. Per day drilling
rig rates averaged $18,047, a 3% increase over the third quarter of
2018. Average per day operating margin for the quarter was $5,859
(before elimination of intercompany drilling rig profit and bad debt
expense of $0.6 million). This compares to third quarter 2018 average
operating margin of $6,291 (before elimination of intercompany drilling
rig profit of $1.2 million), a decrease of 7%, or $432.
Pinkston said: “During the quarter, drilling rig demand declined as
operators made adjustments because of the decrease in commodity prices.
During January, we completed and placed into service our 12th
BOSS rig. And this month our 13th BOSS rig was placed into
service under a long-term contract. Currently, we have 32 rigs
operating. We had 24 long-term contracts (contracts with original terms
ranging from six months to three years in length) as of the end of the
quarter. Included in these 24 term contracts are the two new BOSS rigs
that have been placed into service, noted above, and two term contracts
that rolled over in the first quarter of 2019 to two year terms. Of the
remaining 20 long-term contracts, seven are up for renewal in the first
quarter of 2019, seven in the second quarter, one in the third quarter,
two in the fourth quarter, and three in 2020 and thereafter.”
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 | ||||||||||||||||
| 2018 | 2017 | 2018 | 2018 | 2018 | 2017 | |||||||||||||||||||
| Rigs Utilized | 33.1 | 31.2 | 6% | 33.1 | 34.2 | (3)% | 32.8 | 30.0 | 9% | |||||||||||||||
| Operating Profit Before Depreciation (MM) (1) | $ | 17.2 | $ | 15.3 | 12% | $ | 17.2 | $ | 18.6 | (8)% | $ | 65.1 | $ | 52.1 | 25% | |||||||||
| 1. |
Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. (See Non-GAAP financial measures below.) |
MID-STREAM SEGMENT INFORMATION
For the quarter, gas gathering and liquids sold volumes per day
decreased 5% and 1%, respectively, while gas processing volumes per day
remained relatively unchanged, as compared to the third quarter of 2018.
Operating profit (as defined in the footnote below) for the quarter was
$12.5 million, a decrease of 15% from the third quarter of 2018.
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 | ||||||||||||||||
| 2018 | 2017 | 2018 | 2018 | 2018 | 2017 | |||||||||||||||||||
| Gas Gathering, Mcf/day | 394,203 | 383,319 | 3% | 394,203 | 415,862 | (5)% | 393,613 | 385,209 | 2% | |||||||||||||||
| Gas Processing, Mcf/day | 160,786 | 148,422 | 8% | 160,786 | 160,294 | -% | 158,189 | 137,625 | 15% | |||||||||||||||
| Liquids Sold, Gallons/day | 697,161 | 581,874 | 20% | 697,161 | 700,523 | (1)% | 663,367 | 534,140 | 24% | |||||||||||||||
| Operating Profit Before Depreciation and Amortization (MM) (1) | $ | 12.4 | $ | 13.1 | (5)% | $ | 12.4 | $ | 14.7 | (16)% | $ | 55.9 | $ | 51.7 | 8% | |||||||||
| 1. |
Unit calculates operating profit before depreciation by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. (See Non-GAAP financial measures below.) |
Pinkston said: “Our mid-stream segment completed the connection of the
J. R. Miller pad to its Pittsburgh Mills gathering system during the
fourth quarter. The operator of that pad began bringing two of the seven
new wells on line in January. Superior continues to make progress on the
construction of its new Reeding gas processing plant, which will be
integrated into its Cashion gathering system. The new gas processing
plant is anticipated to commence operation by the end of the first
quarter.”
2019 CAPITAL BUDGET AND PRODUCTION GUIDANCE
Unit’s 2019 capital budget is anticipated to range from $336 million to
$422 million, a decrease of 27% to 8% from 2018, excluding acquisitions.
The decrease is in response to the current commodity price environment
and keeps the budget in-line with anticipated cash flow plus proceeds
from any non-core asset sales. The capital budget is allocated, as
follows, among the three business segments: $271 million to $315 million
for the oil and natural gas segment; $30 million to $65 million for the
contract drilling segment; and $35 million to $42 million for the
mid-stream segment. The budget does not include amounts for any possible
acquisitions and is based on realized prices for the year averaging
$55.04 per barrel of oil, $24.73 per barrel of natural gas liquids, and
$3.00 per Mcf of natural gas (all prices are before differentials and
hedges are applied).
Unit’s oil and natural gas segment’s 2019 production is anticipated to
be 17.4 to 17.9 MMBoe (an increase of 2% to 5%, year-over-year) based on
the capital budget range.
Pinkston said: “We have considerably reduced our 2019 capital
expenditure plans from 2018 levels. Historically, we have focused on
keeping our capital expenditure budget in line with anticipated cash
flow, adjusting our spending mid-year if conditions warranted a change.
We begin 2019 with the same objective of maintaining our capital
spending in line with anticipated cash flow.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $644.5 million, consisting
solely of senior subordinated notes (net of unamortized discount and
debt issuance costs) and no borrowings under the Unit or Superior credit
agreements. In October, Unit signed the Fifth Amendment to its credit
agreement providing in part for the extension of the maturity to October
18, 2023. The Unit credit agreement is subject to an elected commitment
and borrowing base of $425 million. Besides extending the term, the
amendment increased the company’s flexibility around issuing senior
notes and lowered the pricing on certain borrowings and fees.
WEBCAST
Unit uses its website to disclose material nonpublic information and for
complying with its disclosure obligations under Regulation FD. The
website includes those disclosures in the ‘Investor Information’
sections. So, 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 21, 2019, 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, 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, | |||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| Statement of Operations: | ||||||||||||
| Revenues: | ||||||||||||
| Oil and natural gas | $ | 106,019 | $ | 101,503 | $ | 423,059 | $ | 357,744 | ||||
| Contract drilling | 52,965 | 46,661 | 196,492 | 174,720 | ||||||||
| Gas gathering and processing | 55,804 | 56,683 | 223,730 | 207,176 | ||||||||
| Total revenues | 214,788 | 204,847 | 843,281 | 739,640 | ||||||||
| Expenses: | ||||||||||||
| Operating costs: | ||||||||||||
| Oil and natural gas | 31,156 | 34,916 | 131,675 | 130,789 | ||||||||
| Contract drilling | 35,792 | 31,387 | 131,385 | 122,600 | ||||||||
| Gas gathering and processing | 43,395 | 43,621 | 167,836 | 155,483 | ||||||||
| Total operating costs | 110,343 | 109,924 | 430,896 | 408,872 | ||||||||
| Depreciation, depletion, and amortization | 64,629 | 57,712 | 243,605 | 209,257 | ||||||||
| Impairments | 147,884 | – | 147,884 | – | ||||||||
| General and administrative | 9,955 | 11,185 | 38,707 | 38,087 | ||||||||
| (Gain) loss on disposition of assets | (129) | 826 | (704) | (327) | ||||||||
| Total expenses | 332,682 | 179,647 | 860,388 | 655,889 | ||||||||
| Income (loss) from operations | (117,894) | 25,200 | (17,107) | 83,751 | ||||||||
| Other income (expense): | ||||||||||||
| Interest, net | (7,816) | (9,527) | (33,494) | (38,334) | ||||||||
| Gain (loss) on derivatives not designated as hedges | 22,424 | (6,287) | (3,184) | 14,732 | ||||||||
| Other | 5 | 7 | 22 | 21 | ||||||||
| Total other income (expense) | 14,613 | (15,807) | (36,656) | (23,581) | ||||||||
| Income (loss) before income taxes | (103,281) | 9,393 | (53,763) | 60,170 | ||||||||
| Income tax expense (benefit): | ||||||||||||
| Current | (3,131) | 5 | (3,131) | 5 | ||||||||
| Deferred | (23,245) | (79,767) | (10,865) | (57,683) | ||||||||
| Total income taxes | (26,376) | (79,762) | (13,996) | (57,678) | ||||||||
| Net income (loss) | (76,905) | 89,155 | (39,767) | 117,848 | ||||||||
| Net income attributable to non-controlling interest | 935 | – | 5,521 | – | ||||||||
| Net income (loss) attributable to Unit Corporation | $ | (77,840) | $ | 89,155 | $ | (45,288) | $ | 117,848 | ||||
| Net income (loss) attributable to Unit Corporation per common share: | ||||||||||||
| Basic | $ | (1.49) | $ | 1.71 | $ | (0.87) | $ | 2.31 | ||||
| Diluted | $ | (1.49) | $ | 1.71 | $ | (0.87) | $ | 2.28 | ||||
| Weighted average shares outstanding: | ||||||||||||
| Basic | 52,070 | 51,394 | 51,981 | 51,113 | ||||||||
| Diluted | 52,070 | 52,201 | 51,981 | 51,748 | ||||||||
| Unit Corporation | ||||||
| Selected Financial Highlights – continued | ||||||
|
(In thousands) |
||||||
| Twelve Months Ended December 31, | ||||||
| 2018 | 2017 | |||||
| Statement of Cash Flows Data: | ||||||
|
Cash flow from operations before changes in operating assets and liabilities |
$ | 345,582 | $ | 276,811 | ||
| Net change in operating assets and liabilities | 2,177 | (10,855) | ||||
| Net cash provided by operating activities | $ | 347,759 | $ | 265,956 | ||
| Net cash used in investing activities | $ | (450,342) | $ | (293,366) | ||
| Net cash provided by (used in) financing activities | $ | 108,334 | $ | 27,218 | ||
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, 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,
2018 and 2017. 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 beside, 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, | |||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| (In thousands except earnings per share) | ||||||||||||
| Adjusted net income attributable to Unit Corporation: | ||||||||||||
| Net income (loss) attributable to Unit Corporation | $ | (77,840) | $ | 89,155 | $ | (45,288) | $ | 117,848 | ||||
| Impairment adjustment (net of income tax) | 111,652 | – | 111,652 | – | ||||||||
| (Gain) loss on derivatives (net of income tax) | (16,198) | 2,930 | 2,356 | (8,949) | ||||||||
|
Settlements during the period of matured derivative contracts (net of income tax) |
(3,796) | 517 | (16,867) | 105 | ||||||||
| Tax Act income tax benefit | – | (81,307) | – | (81,307) | ||||||||
| Adjusted net income (loss) | $ | 13,818 | $ | 11,295 | $ | 51,853 | $ | 27,697 | ||||
| Adjusted diluted earnings per share attributable to Unit Corporation: | ||||||||||||
| Diluted earnings (loss) per share | $ | (1.49) | $ | 1.71 | $ | (0.87) | $ | 2.28 | ||||
| Diluted earnings per share from the impairments | 2.14 | – | 2.14 | – | ||||||||
| Diluted earnings per share from the (gain) loss on derivatives | (0.31) | 0.06 | 0.05 | (0.17) | ||||||||
|
Diluted earnings (loss) per share from the settlements of matured derivative contracts |
(0.07) | 0.01 | (0.32) | – | ||||||||
| Diluted earnings (loss) per share from the Tax Act income tax benefit | – | (1.56) | – | (1.57) | ||||||||
|
Adjusted diluted earnings (loss) per share attributable to Unit Corporation |
$ | 0.27 | $ | 0.22 | $ | 1.00 | $ | 0.54 | ||||
| Weighted Shares (Denominator) | 52,070 | 52,201 | 51,981 | 51,748 | ||||||||
________________
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, 2018
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:
| 2018 | |||
| (In millions) | |||
| PV-10 at December 31, 2018 | $ | 1,105.7 | |
| Discounted effect of income taxes | (122.0) | ||
| Standardized Measure at December 31, 2018 | $ | 983.7 | |
| Unit Corporation | |||||||||||||||
| Reconciliation of Segment Operating Profit | |||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||
| September 30, | December 31, | December 31, | |||||||||||||
| 2018 | 2018 | 2017 | 2018 | 2017 | |||||||||||
| (In thousands) | |||||||||||||||
| Oil and natural gas | $ | 79,484 | $ | 74,863 | $ | 66,587 | $ | 291,384 | $ | 226,955 | |||||
| Contract drilling | 18,580 | 17,173 | 15,274 | 65,107 | 52,120 | ||||||||||
| Gas gathering and processing | 14,689 | 12,409 | 13,062 | 55,894 | 51,693 | ||||||||||
| Total operating profit | 112,753 | 104,445 | 94,923 | 412,385 | 330,768 | ||||||||||
| Depreciation, depletion and amortization | (63,537) | (64,629) | (57,712) | (243,605) | (209,257) | ||||||||||
| Impairments | – | (147,884) | – | (147,884) | – | ||||||||||
| Total operating income (loss) | 49,216 | (108,068) | 37,211 | 20,896 | 121,511 | ||||||||||
| General and administrative | (9,278) | (9,955) | (11,185) | (38,707) | (38,087) | ||||||||||
| Gain (loss) on disposition of assets | 253 | 129 | (826) | 704 | 327 | ||||||||||
| Interest, net | (7,945) | (7,816) | (9,527) | (33,494) | (38,334) | ||||||||||
| Gain (loss) on derivatives | (4,385) | 22,424 | (6,287) | (3,184) | 14,732 | ||||||||||
| Other | 6 | 5 | 7 | 22 | 21 | ||||||||||
| Income (loss) before income taxes | $ | 27,867 | $ | (103,281) | $ | 9,393 | $ | (53,763) | $ | 60,170 | |||||
________________
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 ongoing operating performance of the segments
and company 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, | |||||||||||||
| 2018 | 2018 | 2017 | 2018 | 2017 | |||||||||||
| (In thousands except for operating days and operating margins) | |||||||||||||||
| Contract drilling revenue | $ | 50,612 | $ | 52,965 | $ | 46,661 | $ | 196,492 | $ | 174,720 | |||||
| Contract drilling operating cost | 32,032 | 35,792 | 31,387 | 131,385 | 122,600 | ||||||||||
| Operating profit from contract drilling | 18,580 | 17,173 | 15,274 | 65,107 | 52,120 | ||||||||||
| Add: | |||||||||||||||
| Elimination of intercompany rig profit and bad debt expense | 1,186 | 644 | 642 | 3,078 | 1,620 | ||||||||||
|
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense |
19,766 | 17,817 | 15,916 | 68,185 | 53,740 | ||||||||||
| Contract drilling operating days | 3,142 | 3,041 | 2,868 | 11,960 | 10,964 | ||||||||||
|
Average daily operating margin before elimination of intercompany rig profit and bad debt expense |
$ | 6,291 | $ | 5,859 | $ | 5,550 | $ | 5,701 | $ | 4,901 | |||||
________________
The company has included the average daily operating margin before
elimination of intercompany rig profit and bad debt expense because:
-
Its management uses the measurement to evaluate the cash flow
performance of its contract drilling segment and to evaluate the
performance of contract drilling management. -
It is used by investors and financial analysts to evaluate the
performance of the company.
| Unit Corporation | ||||||
| Reconciliation of Cash Flow from Operations Before Changes in Operating Assets and Liabilities |
||||||
| Twelve Months Ended | ||||||
| December 31, | ||||||
| 2018 | 2017 | |||||
| (In thousands) | ||||||
| Net cash provided by operating activities | $ | 347,759 | $ | 265,956 | ||
| Net change in operating assets and liabilities | (2,177) | 10,855 | ||||
|
Cash flow from operations before changes in operating assets and liabilities |
$ | 345,582 | $ | 276,811 | ||
________________
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, | |||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| (In thousands except earnings per share) | ||||||||||||
| Net income (loss) | $ | (76,905) | $ | 89,155 | $ | (39,767) | $ | 117,848 | ||||
| Income taxes | (26,376) | (79,762) | (13,996) | (57,678) | ||||||||
| Depreciation, depletion and amortization | 64,629 | 57,712 | 243,605 | 209,257 | ||||||||
| Impairments | 147,884 | – | 147,884 | – | ||||||||
| Interest expense | 7,816 | 9,527 | 33,494 | 38,334 | ||||||||
| (Gain) loss on derivatives | (22,424) | 6,287 | 3,184 | (14,732) | ||||||||
| Settlements during the period of matured derivative contracts | (4,763) | 902 | (22,803) | 173 | ||||||||
| Stock compensation plans | 5,502 | 5,269 | 22,899 | 17,747 | ||||||||
| Other non-cash items | (735) | 774 | (2,576) | 2,886 | ||||||||
| (Gain) loss on disposition of assets | (129) | 826 | (704) | (327) | ||||||||
| Adjusted EBITDA | 94,499 | 90,690 | 371,220 | 313,508 | ||||||||
| Adjusted EBITDA attributable to non-controlling interest | 6,315 | – | 21,488 | – | ||||||||
| Adjusted EBITDA attributable to Unit Corporation | $ | 88,184 | $ | 90,690 | $ | 349,732 | $ | 313,508 | ||||
| Diluted earnings (loss) per share attributable to Unit | $ | (1.49) | $ | 1.71 | $ | (0.87) | $ | 2.28 | ||||
| Diluted earnings per share from income taxes | (0.52) | (1.53) | (0.26) | (1.11) | ||||||||
|
Diluted earnings per share from depreciation, depletion and amortization |
1.13 | 1.11 | 4.36 | 4.04 | ||||||||
| Diluted earnings per share from impairments | 2.84 | – | 2.84 | – | ||||||||
| Diluted earnings per share from interest expense | 0.15 | 0.18 | 0.63 | 0.74 | ||||||||
| Diluted earnings per share from the (gain) loss on derivatives | (0.43) | 0.12 | 0.06 | (0.28) | ||||||||
|
Diluted earnings per share from the settlements during the period of matured derivative contracts |
(0.09) | 0.02 | (0.44) | – | ||||||||
| Diluted earnings per share from stock compensation plans | 0.10 | 0.10 | 0.43 | 0.34 | ||||||||
| Diluted earnings per share from other non-cash items | – | 0.01 | (0.01) | 0.06 | ||||||||
| Diluted earnings per share (gain) loss on disposition of assets | – | 0.02 | (0.01) | (0.01) | ||||||||
| Adjusted EBITDA per diluted share | $ | 1.69 | $ | 1.74 | $ | 6.73 | $ | 6.06 | ||||
| Weighted Shares (Denominator) | 52,070 | 52,201 | 51,981 | 51,748 | ||||||||
________________
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: https://www.businesswire.com/news/home/20190221005262/en/
Michael D. Earl
Vice President, Investor Relations
(918)
493-7700
www.unitcorp.com
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