Unit Aktie
WKN: 874868 ISIN: US9092181091
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Unit Corporation Reports 2018 Fourth Quarter and Year-End Results

Donnerstag, 21.02.19 13:00
Unit Corporation Reports 2018 Fourth Quarter and Year-End Results
Bildquelle: iStock by Getty Images
TULSA, Okla, –

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   Hier geht's zur Aktien-Startseite

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