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Unit Corporation (UNT) today reported its financial and operational results for the third quarter of 2014. Highlights include:

  • Revenue of $401.0 million, an increase of 20% over the third quarter of 2013.
  • Oil and natural gas segment’s total equivalent production increased 9% over the third quarter of 2013.
  • Oil and natural gas liquids (NGLs) production increased 19% and 4% over the third quarter of 2013 and the second quarter of 2014, respectively.
  • Three additional BOSS drilling rigs contracted for third-party operators.
  • Average drilling rigs working increased 5.6 drilling rigs over the second quarter of 2014.
  • Midstream segment’s per day gas processed volumes and liquids sold volumes increased 17% and 32%, respectively, over the third quarter of 2013.

Net income for the quarter was $67.5 million, or $1.37 per diluted share, compared to $34.2 million, or $0.70 per diluted share, for the third quarter of 2013. Adjusted net income for the quarter, which excludes the effect of non-cash commodity derivatives, was $54.7 million, or $1.11 per diluted share, compared to $41.2 million, or $0.85 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the quarter were $401.0 million (47% oil and natural gas, 30% contract drilling, and 23% mid-stream), compared to $333.8 million (47% oil and natural gas, 30% contract drilling, and 23% mid-stream) for the third quarter of 2013.

Net income for the nine months ended September 30, 2014 was $178.8 million, or $3.65 per diluted share, compared to $133.4 million, or $2.75 per diluted share, for the first nine months of 2013. Adjusted net income for the first nine months of 2014, which excludes the effect of non-cash commodity derivatives, was $172.9 million, or $3.52 per diluted share, compared to $134.5 million, or $2.77 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the first nine months of 2014 were $1,194.4 million (48% oil and natural gas, 29% contract drilling, and 23% mid-stream), compared to $992.7 million (48% oil and natural gas, 32% contract drilling, and 20% mid-stream) for the first nine months of 2013.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production for the quarter was 4.6 million barrels of oil equivalent (MMBoe), an increase of 9% over the third quarter of 2013 and essentially unchanged compared to the second quarter of 2014. The third quarter of 2014 production was negatively impacted by approximately 0.5 billion cubic feet of natural gas equivalent (Bcfe) due to a third-party plant being shut down in the Wilcox play for approximately seven days. Liquids (oil and NGLs) production represented 47% of total equivalent production for the quarter. Oil production for the quarter was 11,307 barrels per day, an increase of 28% over the third quarter of 2013 and an increase of 8% over the second quarter of 2014. NGLs production for the quarter was 12,473 barrels per day, an increase of 13% over the third quarter of 2013 and a decrease of 2% from the second quarter of 2014. Natural gas production for the quarter was 158,075 thousand cubic feet (Mcf) per day, an increase of 2% over the third quarter of 2013 and a decrease of 4% from the second quarter of 2014. Total production for the first nine months of 2014 was 13.4 MMBoe.

For 2014, Unit has derivative contracts covering 7,000 Bbls per day of oil production and 90,000 MMBtu per day of natural gas production. The contracts for the oil production are swap contracts covering 3,000 Bbls per day and collars for 4,000 Bbls per day. The swap transactions are at a comparable average NYMEX price of $91.77. The collar transactions are at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The contracts for natural gas production are swaps covering 80,000 MMBtu per day and a collar covering 10,000 MMBtu per day. The swap transactions are at a comparable average NYMEX price of $4.24. The collar transaction is at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37.

For 2015, Unit has a derivative contract covering 1,000 Bbls per day of oil production. This swap transaction is at a comparable average NYMEX price of $95.00.

The following table illustrates this segment’s comparative production, realized prices and operating profit for the periods indicated:

Three Months Ended Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, June 30, Sept. 30, Sept. 30,
2014 2013 Change 2014 2014 Change 2014 2013 Change
Oil and NGLs Production, MBbl 2,188 1,833 19% 2,188 2,113 4% 6,176 5,228 18%
Natural Gas Production, Bcf 14.5 14.3 2% 14.5 15.0 (3)% 43.4 42.4 2%
Production, MBoe 4,612 4,217 9% 4,612 4,618 —% 13,414 12,296 9%
Production, MBoe/day 50.1 45.8 9% 50.1 50.7 (1)% 49.1 45.0 9%
Avg. Realized Natural Gas Price, Mcfe (1) $ 3.68 $ 3.11 18% $ 3.68 $ 4.05 (9)% $ 3.99 $ 3.35 19%

Avg. Realized NGL Price, Bbl (1)

$ 30.11 $ 28.10 7% $ 30.11 $ 29.99 —% $ 33.05 $ 30.87 7%

Avg. Realized Oil Price, Bbl (1)

$ 91.57 $ 95.49 (4)% $ 91.57 $ 94.17 (3)% $ 92.44 $ 95.20 (3)%
Realized Price / Boe (1) $ 39.76 $ 35.77 11% $ 39.76 $ 40.10 (1)% $ 40.53 $ 37.60 8%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2) $ 139.6 $ 107.2 30% $ 139.6 $ 153.8 (9)% $ 441.2 $ 337.6 31%

(1) Realized price includes oil, natural gas liquids, natural gas and associated derivatives.

(2) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

At the end of the quarter, 15 Unit drilling rigs were operating for our exploration segment. Six were operating in the Granite Wash, three in the Southern Oklahoma Hoxbar Oil Trend (SOHOT), two in the Wilcox, two in the Marmaton, one in the Mississippian, and one in the Cherokee. Unit anticipates that three of these drilling rigs will be released during the fourth quarter, one in the Granite Wash, one in the Marmaton, and one in the Cherokee.

In the SOHOT area, production increased 56% during the quarter as compared to the second quarter of 2014, primarily because of two new operated horizontal Marchand completions. The Unit Earl # 2-30H (80% working interest) started producing on August 3, 2014. The 30-day, 60-day and 90-day initial rate for that well was approximately 1,581 barrels of oil equivalent (Boe) per day, 1,342 Boe per day, and 1,151 Boe per day, respectively. The second well, the Unit Rosey Havenstrite #1H (80% working interest), started production on September 11, 2014. The 30-day initial rate for that well was approximately 1,414 Boe per day. The average production mix of the two wells is 86% oil, 4% NGLs, and 10% natural gas. Currently, there are five new operated Hoxbar wells scheduled to be fracture stimulated during the fourth quarter. The majority of the production impact from these wells will not be realized until the first quarter 2015.

In the Granite Wash (GW) Buffalo Wallow field, Unit recently successfully fracture stimulated a three well pad (GW “B”, “C1” and “G”) using an upsized frac design. The new design pumps approximately 4.4 million pounds of sand, an increase of approximately 80% over the previous fracs in the field. The number of stages, perf clusters, and concentration of 100 mesh sand has also been increased. First gas production from the pad should start in mid-December. A second three well pad (GW “B”, “C1” and “A”) is scheduled to be fracture stimulated during the fourth quarter, also using the new frac design, with first gas production scheduled for the first quarter of 2015.

In the Gilly Wilcox field, Unit completed the Jackson GU #1 (84% working interest) from a previously untested shallower “Gilchrease” Wilcox sand. The well had first gas sales on September 21st at a 30-day unstimulated rate of approximately 1,022 Boe per day with approximately 5,600 psi of flowing casing pressure. The production stream is 12% oil, 37% NGLs, and 51% natural gas. The Gilchrease zone is present behind pipe and appears productive in all 13 of the current Gilly field wells.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “For our oil and natural gas segment, production was essentially unchanged between the third quarter and second quarter of 2014, although third quarter 2014 production was up 9% over the comparable quarter of 2013. Delays in availability for fracture stimulation in the Wilcox, delays in infrastructure completion in the Granite Wash, and delays in drilling pilot holes in the SOHOT have slowed our anticipated rate of growth for the year. As a result, we are revising our production guidance for 2014 to 9% to 10% growth over 2013, which anticipates production growth of at least 4% in the fourth quarter 2014 over the third quarter 2014.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 79.1, an increase of 25% over the third quarter of 2013, and an increase of 8% over the second quarter of 2014. Per day drilling rig rates for the quarter averaged $20,070, an increase of 2% over the third quarter of 2013 and 1% over the second quarter of 2014. Average per day operating margin for the quarter was $8,449 (before elimination of intercompany drilling rig profit and bad debt expense of $7.6 million). This compares to $7,920 (before elimination of intercompany drilling rig profit and bad debt expense of $4.6 million) for the third quarter of 2013, an increase of 7%, or $529. As compared to the second quarter of 2014 ($8,317 before elimination of intercompany drilling rig profit and bad debt expense of $7.8 million), third quarter 2014 operating margin increased 2% or $132 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense – see Non-GAAP Financial Measures below).

For the first nine months of 2014, Unit averaged 73.5 drilling rigs working, an increase of 13% over the 65.0 drilling rigs working during the first nine months of 2013. Average per day operating margin for the first nine months of 2014 was $8,229 (before elimination of intercompany drilling rig profit and bad debt expense of $20.7 million) as compared to $7,682 (before elimination of intercompany drilling rig profit and bad debt expense of $11.7 million) for the first nine months of 2013, an increase of 7% (in each case regarding eliminating intercompany drilling rig profit and bad debt expense – see Non-GAAP Financial Measures below).

Larry Pinkston said: “Drilling rig demand continued at a steady increase during the quarter. Almost all of our drilling rigs working today are drilling for oil or NGLs. During the third quarter, our second BOSS drilling rig began operating, and recently our third BOSS drilling rig was delivered and began operating, bringing our fleet to a total of 120 drilling rigs. Of the 120 drilling rigs, we currently have 82 drilling rigs working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 38 of the 82 drilling rigs. Of the 38 long term contracts, 14 are up for renewal in the fourth quarter, and 24 are up for renewal in 2015. Our first BOSS drilling rig, which originally was placed into service with our oil and natural gas segment, has now been contracted to a third-party operator that plans to take delivery this month. Our fourth BOSS drilling rig will be delivered later this quarter, and five additional BOSS drilling rigs have been contracted to be built for third-party operators and are expected to be placed into service during 2015. In addition, we have ordered the long lead time components for three additional BOSS drilling rigs. Operator reception of this new drilling rig design has been very positive, and we are pleased to have more of them working in the field to demonstrate the advantages of this new design.”

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

Three Months Ended Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, June 30, Sept. 30, Sept. 30,
2014 2013 Change 2014 2014 Change 2014 2013 Change
Rigs Utilized 79.1 63.5 25% 79.1 73.5 8% 73.5 65.0 13%
Operating Margins (1) 45% 41% 10% 45% 42% 7% 42% 40% 5%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) $ 53.9 $ 41.7 29% $ 53.9 $ 47.8 13% $ 144.5 $ 124.6 16%

(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

MID-STREAM SEGMENT INFORMATION

Per day liquids sold and processed volumes increased 32% and 17%, respectively, as compared to the third quarter of 2013. For the quarter, per day gathered volumes were 319,692 Mcf, a 2% decrease from the third quarter of 2013. Compared to the second quarter of 2014, liquids sold and processed volumes per day increased 1% and 5%, respectively, while gathered volumes per day decreased 2%. Operating profit (as defined in the footnote below) for the quarter was $13.3 million, an increase of 5% over the third quarter of 2013 and a decrease of 5% from the second quarter of 2014.

The following table illustrates certain comparative results from this segment’s operations for the periods indicated:

Three Months Ended Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, June 30, Sept. 30, Sept. 30,
2014 2013 Change 2014 2014 Change 2014 2013 Change
Gas Gathering, Mcf/day 319,692 326,474 (2)% 319,692 326,028 (2)% 316,658 308,645 3%
Gas processing, Mcf/day 169,357 145,020 17% 169,357 161,509 5% 160,373 137,725 16%
Liquids Sold, Gallons/day 771,334 586,446 32% 771,334 762,205 1% 748,805 505,584 48%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) $ 13.3 $ 12.7 5% $ 13.3 $ 14.0 (5)% $ 39.5 $ 31.8 24%

(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.

Larry Pinkston said: “Our midstream segment continues to benefit from prior capital investments, and as a result we have seen solid growth throughout the year. We are nearing completion of the Buffalo Wallow system connection to our Hemphill processing system which is anticipated to start operation at the end of the fourth quarter. We have also entered into a fee-based contract for our new Snowshoe project in the Marcellus. This project will consist of the construction of a seven-mile, 16 inch and 24 inch trunkline to gather production in Centre County, Pennsylvania for delivery to an interstate pipeline. Construction has started with an expected completion date in the third quarter of 2015.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $676.8 million (consisting of $646.0 million of senior subordinated notes, net of unamortized discount, and $30.8 million of credit agreement borrowings), and a debt to capitalization ratio of 22%. Unit’s credit agreement provides that the amount Unit could borrow is the lesser of the amount it elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $900 million), but in either event not to exceed $900 million.

WEBCAST

Unit will webcast its third quarter earnings conference call live over the Internet on November 4, 2014 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go tohttp://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to 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 or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the company’s oil and natural gas production, oil and gas reserve information, and its ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the company’s inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company’s oil and natural gas segment, development, operational, implementation, and opportunity risks, possible delays caused by limited availability of third-party services needed in its operations, unexpected delays or operational issues associated with the company’s new drilling rig design, possibility of future growth opportunities, and other factors described from time to time 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 and Operations Highlights

(In thousands except per share amounts)

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013
Statement of Operations:
Revenues:
Oil and natural gas $ 188,471 $ 157,320 $ 575,176 $ 475,728
Contract drilling 120,652 100,647 341,530 313,180
Gas gathering and processing 91,851 75,809 277,687 203,821
Total revenues 400,974 333,776 1,194,393 992,729
Expenses:
Oil and natural gas:
Operating costs 48,841 50,139 133,979 138,171

Depreciation, depletion, and amortization

70,033 56,294 200,958 163,612
Contract drilling:
Operating costs 66,727 58,988 197,025 188,580
Depreciation 22,560 17,402 61,194 52,570
Gas gathering and processing:
Operating costs 78,558 63,098 238,166 172,065
Depreciation and amortization 10,272 8,773 29,972 24,143
General and administrative 10,172 9,936 30,409 28,288
(Gain) loss on disposition of assets 529 (4,345 ) (9,092 ) (7,744 )
Total operating expenses 307,692 260,285 882,611 759,685
Income from operations 93,282 73,491 311,782 233,044
Other income (expense):
Interest, net (4,280 ) (3,625 ) (12,201 ) (11,777 )
Gain (loss) on derivatives 19,841 (13,760 ) (9,234 ) (3,340 )
Other (68 ) (14 ) 3 (171 )
Total other income (expense) 15,493 (17,399 ) (21,432 ) (15,288 )
Income before income taxes 108,775 56,092 290,350 217,756
Income tax expense:
Current 5,451 2,111 23,721 6,745
Deferred 35,802 19,749 87,802 77,566
Total income taxes 41,253 21,860 111,523 84,311
Net income $ 67,522 $ 34,232 $ 178,827 $ 133,445
Net income per common share:
Basic $ 1.39 $ 0.71 $ 3.68 $ 2.77
Diluted $ 1.37 $ 0.70 $ 3.65 $ 2.75
Weighted average shares outstanding:
Basic 48,650 48,254 48,596 48,193
Diluted 49,177 48,658 49,054 48,510
September 30, December 31,
2014 2013
Balance Sheet Data:
Current assets $ 220,127 $ 212,031
Total assets $ 4,431,811 $ 4,022,390
Current liabilities $ 351,339 $ 243,573
Long-term debt $ 676,843 $ 645,696
Other long-term liabilities $ 147,214 $ 158,331
Deferred income taxes $ 888,915 $ 801,398
Shareholders’ equity $ 2,367,500 $ 2,173,392
Nine Months Ended September 30,
2014 2013
Statement of Cash Flows Data:

Cash flow from operations before changes in operating assets and liabilities

$ 565,135 $ 468,537
Net change in operating assets and liabilities (15,608 ) 32,424
Net cash provided by operating activities $ 549,527 $ 500,961
Net cash used in investing activities $ (636,761 ) $ (422,658 )
Net cash provided by (used in) financing activities $ 69,536 $ (77,536 )

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with 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 cash flow from operations before changes in operating assets and liabilities, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, and net income and earnings per share including only the effect of the cash settled commodity derivatives.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2014 and 2013. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.

Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Nine Months Ended
September 30,
2014 2013
(In thousands)
Net cash provided by operating activities $ 549,527 $ 500,961
Net change in operating assets and liabilities 15,608 (32,424 )

Cash flow from operations before changes in operating assets and liabilities

$ 565,135 $ 468,537

________________

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 which is 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 Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense
Three Months Ended Nine Months Ended
June 30, September 30, September 30,
2014 2014 2013 2014 2013
(In thousands except operating days and operating margins)
Contract drilling revenue $ 114,278 $ 120,652 $ 100,647 $ 341,530 $ 313,180
Contract drilling operating cost 66,494 66,727 58,988 197,025 188,580
Operating profit from contract drilling 47,784 53,925 41,659 144,505 124,600

Add:

Elimination of intercompany rig profit and bad debt expense

7,808

7,553

4,579

20,674

11,674

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense

55,592 61,478 46,238 165,179 136,274
Contract drilling operating days 6,684 7,276 5,838 20,073 17,739

Average daily operating margin before elimination of intercompany rig profit and bad debt expense

$ 8,317 $ 8,449 $ 7,920 $ 8,229 $ 7,682

________________

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 Adjusted Net Income and Adjusted Diluted Earnings per Share

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013

(In thousands except earnings per share)

Adjusted net income:
Net income $ 67,522 $ 34,232 $ 178,827 $ 133,445

(Gain) loss on derivatives not designated as hedges and hedge ineffectiveness (net of income tax)

(12,163 ) 8,455 5,659 2,047

Settlements during the period of matured derivative contracts (net of income tax)

(630 ) (1,493 ) (11,635 ) (965 )
Adjusted net income $ 54,729 $ 41,194 $ 172,851 $ 134,527
Adjusted diluted earnings per share:
Diluted earnings per share $ 1.37 $ 0.70 $ 3.65 $ 2.75

Diluted earnings per share from the (gain) loss on derivatives

(0.25 ) 0.18 0.11 0.04

Diluted earnings per share from the settlements of matured derivative contracts

(0.01 ) (0.03 ) (0.24 ) (0.02 )
Adjusted diluted earnings per share $ 1.11 $ 0.85 $ 3.52 $ 2.77

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