Quarterly / Earnings Reports | Second Quarter (2Q) Update

Unit Corp. Reports Q2 2019 Results

Email    |    Print    |    Bookmark

You Need to login first

   |    Tuesday,August 06,2019

Unit Corp. reported its financial and operational results for the second quarter of 2019.

Operational highlights include:

Oil and natural gas segment:

• Exploration efforts continue to focus on increasing oil production with second quarter 2019 oil production increasing 6% over first quarter 2019.
• In the Red Fork play, the Wingard Farms 2128 well's peak 24-hour IP was 2,850 barrels of oil equivalent (Boe) (80% oil).
• In the Red Fork play, the Schrock 2215 well, which started production in October 2018, is producing 600 Boe per day (52% oil) and has cumulatively produced 420 thousand barrels of oil equivalent (MBoe) as of June 30, 2019.
• Approximately 2,100 net acres were added to the Penn Sands prospect area inclusive of both Marchand and Red Fork prospects.

Contract drilling segment:

• BOSS drilling rigs continue to be 100% contracted.
• Obtained a long-term contract with an operator to build the 14^th BOSS drilling rig. The operator for this new rig also agreed to long-term extensions on two existing BOSS drilling rigs.

Mid-stream segment:

• Completed the installation of the new 60 million cubic feet (MMcf) per day Reeding processing plant on the Cashion system.
• The Cashion system throughput volumes increased by 27% over the second quarter of 2018.
• During the first half of 2019, a new well pad was added to the Pittsburgh Mills gathering system resulting in an 82% increase in throughput volume over the second quarter of 2018.

Larry Pinkston, Chief Executive Officer and President, said: "We begin each year setting our capital expenditures budget based on what we then anticipate our cash flow for the year will be. For 2019, we projected a budget range of $336 million to $422 million for the year, consistent with our projected cash flow. At this point in the year and given current commodity prices, we anticipate that both our cash flow and our capital expenditures will end up at the low end of our budget range.

"We concentrated our oil and natural gas segment capital expenditures during the first half of the year so we would have the time needed to allow the new wells to be completed and producing by year-end. Consequently (and by design), borrowings under our bank credit agreement increased during the first and second quarters. Having, for the most part, completed our intended exploration operations, our plans are to now substantially reduce those borrowings by year-end."

Oil & Gas Segment Summary

For the quarter, total equivalent production was 4.2 million barrels of oil equivalent (MMBoe), a 1% increase over the first quarter of 2019. Oil and NGLs production represented 47% of total equivalent production. Oil production was 7,979 barrels per day, an increase of 4% over the first quarter of 2019. NGLs production was 13,298 barrels per day, a 1% decrease from the first quarter of 2019. Natural gas production was 146.0 MMcf per day, a 2% decrease from the first quarter of 2019. Total equivalent production for the first six months of 2019 was 8.3 MMBoe.

Unit's average realized per barrel equivalent price for the quarter was $18.75, a 10% decrease from the first quarter of 2019. Unit's average natural gas price was $1.86 per Mcf, a decrease of 26% from the first quarter of 2019. Unit's average oil price was $59.94 per barrel, an increase of 6% over the first quarter of 2019. Unit's average NGLs price was $12.52 per barrel, a decrease of 22% from the first quarter of 2019. All prices in this paragraph include the effects of derivative contracts.

Unit continued to focus on increasing oil production for the quarter. At year-end 2018, oil represented slightly over 17% of Unit's production stream. Unit's expectation is to increase oil production to approximately 19% to 20% by year-end. As such, capital has been deployed in a fashion to provide the best opportunity to achieve this objective.

In the Penn Sands prospect in western Oklahoma, during the quarter, Unit completed the Wingard 1522 #2HX, a Red Fork well that had been drilled to a 7,500-foot lateral length. Following completion, during the drill out, it was determined that the casing had collapsed. The well was brought on-line with an open lateral of only about 1,500 feet and had an IP30 of 413 Boe per day from approximately 20% of the intended lateral length. At the end of the quarter, Unit completed and brought on-line the Wingard Farms 2128 1HX, a Red Fork well in the same play. The Wingard Farms had a peak 24-hour IP rate of approximately 2,850 Boe with an oil cut of approximately 80%. Unit currently has three additional Red Fork wells in various stages of completion.

In the Gulf Coast area, Unit continued delineation of its Shoal Creek prospect with the drilling of its successful Blackstone G #3 well currently flowing at 3.0 MMcf of natural gas per day and 175 barrels of oil per day. Also, the Blackstone G #3 has three up-hole intervals that have not been completed yet. During the quarter, Unit continued drilling in this prospect with two additional delineation wells, the Sentinel #1 and the Guardian #1, which are currently in the early stages of completion.

Pinkston said: "Our oil and natural gas segment's focus remains on expanding on our favorable results in western Oklahoma in both our Red Fork and SOHOT prospect areas. This allows us to increase our oil production and our footprint in a very cost-effective manner.

"As previously stated, it is our objective to maintain a capital budget in-line with anticipated cash flows. As a result, the oil and natural gas segment currently has no rigs operating, which is down from a peak of six during the first half of the year. By design, our acreage positions in our various prospect areas are over 80% held by production. This allows us to govern our drilling pace by our cash flow and not lease expiration.

"We expect year-over-year production for 2019 to be 17.0 MMBoe to 17.2 MMBoe, which is consistent with our capital expenditures being at the low end of our guidance coupled with the first quarter third-party plant shut-down impact of our Wilcox play production."

This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:

Contract Drilling

Unit's average number of drilling rigs working during the quarter was 28.6, a decrease of 9% from the first quarter of 2019. Per day drilling rig rates averaged $18,491, a 1% increase over the first quarter of 2019. For the first six months of 2019, per day drilling rig rates averaged $18,412, a 7% increase over the first six months of 2018. Average per day operating margin for the quarter was $5,526 (before elimination of intercompany drilling rig profit of $0.7 million). This compares to first quarter 2019 average operating margin of $7,376 (before elimination of intercompany drilling rig profit of $1.1 million), a decrease of 25%, or $1,850. Average operating margins for the first quarter included early termination fees of approximately $4.8 million, or $1,684 per day, from the cancellation of certain third-party long-term contracts. Average per day operating margin for the first six months of 2019 was $6,488 (before elimination of intercompany drilling rig profit of $1.7 million). This compares to the first six months of 2018 average operating margin of $5,298 (before elimination of intercompany drilling rig profit of $1.2 million), an increase of 22%, or $1,190 (in each case regarding eliminating intercompany drilling rig profit - see non-GAAP financial measures below). Average operating margins for the first six months included early termination fees of approximately $4.8 million, or $875 per day, from the cancellation of certain third-party long-term contracts.

Pinkston said: "Our BOSS drilling rigs continue to maintain 100% utilization. We obtained a long-term contract for our 14^th BOSS drilling rig, which is currently under construction. The operator that contracted the drilling rig also agreed to long-term extensions of the contracts for two other BOSS drilling rigs that they are currently operating. Term contracts (contracts with original terms ranging from six months to three years in length) are in place for 14 of our drilling rigs at the end of the quarter. Of the 14 contracts, two are up for renewal in the third quarter of 2019, four in the fourth quarter, five in 2020, and three after 2020."

This table illustrates certain comparative results for the periods indicated:

Midstream

For the quarter, gas processed, gas gathered, and liquids sold volumes per day increased by 2%, 4%, and 9%, respectively, as compared to the first quarter of 2019. Operating profit (as defined in the footnote below) for the quarter was $11.8 million, a 10% decrease from the first quarter of 2019.

For the first six months of 2019, gas processed, gas gathered, and liquids sold volumes per day increased 5%, 20%, and 9%, respectively, as compared to the first six months of 2018. Operating profit (as defined in the footnote below) for the first six months of 2019 was $24.9 million, a decrease of 14% from the first six months of 2018.

This table illustrates certain comparative results for the periods indicated:

Pinkston said: "The mid-stream segment completed the installation of the new 60 MMcf per day Reeding processing plant, which was added to the Cashion system. This system has seen a strong increase in throughput volume on a year-over-year basis, having enjoyed the benefit of the activity levels of three third-party operators in the area. Our Pittsburgh Mills gathering system has also realized a strong increase in throughput volumes because of a third-party operator's addition of the Miller pad."

Q2 Financials

Unit ended the quarter with long-term debt of $756.6 million, consisting of $645.6 million in senior subordinated notes (net of unamortized discount and debt issuance costs), $103.5 million in borrowings under the Unit credit agreement, and $7.5 million in borrowings under the Superior credit facility. The Unit credit agreement was re-determined in April and is subject to an elected commitment and borrowing base of $425 million. The Superior credit agreement has a facility size of $200 million.

Net loss attributable to Unit for the quarter was $8.5 million, or $0.16 per diluted share, compared to net income attributable to Unit of $5.8 million, or $0.11 per diluted share, for the second quarter of 2018. Adjusted net loss attributable to Unit (which excludes the effect of non-cash commodity derivatives) for the quarter was $12.9 million, or $0.24 per diluted share, as compared to adjusted net income attributable to Unit of $11.3 million, or $0.21 per diluted share, for the same quarter for 2018 (see non-GAAP financial measures below). The loss is primarily attributable to the deterioration in realized natural gas liquids (NGLs) prices and natural gas prices experienced during the quarter. Total revenues for the quarter were $165.1 million (47% oil and natural gas, 26% contract drilling, and 27% mid-stream), compared to $203.3 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream) for the second quarter of 2018. Adjusted EBITDA attributable to Unit was $59.3 million, or $1.12 per diluted share (see non-GAAP financial measures below).

For the first six months of 2019, net loss attributable to Unit was $12.0 million, or $0.23 per diluted share, compared to net income attributable to Unit of $13.7 million, or $0.26 per diluted share, for the first six months of 2018. Adjusted net loss attributable to Unit (which excludes the effect of non-cash commodity derivatives) was $8.4 million, or $0.16 per diluted share, as compared to adjusted net income attributable to Unit of $22.4 million, or $0.43 per diluted share, for the same period for 2018 (see non-GAAP financial measures below). Total revenues for the first six months were $354.8 million (46% oil and natural gas, 27% contract drilling, and 27% mid-stream), compared to $408.4 million (50% oil and natural gas, 23% contract drilling, and 27% mid-stream) for the first six months of 2018. Adjusted EBITDA attributable to Unit for the first six months was $136.4 million, or $2.59 per diluted share (see non-GAAP financial measures below).