Unit Corporation Reports 2014 First Quarter Results Business Wire TULSA, Okla. -- May 8, 2014 Unit Corporation (NYSE:UNT) today reported its financial and operational results for the first quarter 2014. Larry Pinkston, Unit’s Chief Executive Officer and President, stated, “For the quarter, Unit reported net income of $56.9 million, or $1.17 per diluted share, and adjusted net income of $62.8 million, or $1.29 per diluted share (see Non-GAAP Financial Measures below). We continue to make progress on our key initiatives within each business segment. “For the oil and natural gas segment, production for the quarter increased 5% over the first quarter of 2013 with oil and natural gas liquids (NGLs) production increasing from 40% to 45% of total equivalent production. Compared to the fourth quarter of 2013, production decreased 4%, or 1,745 barrels of oil equivalent (Boe) per day. The decrease was due primarily to weather related factors. The combination of weather related issues and mechanical issues reduced anticipated 2014 production by approximately 2.2 billion cubic feet equivalent (Bcfe), representing approximately 2% of our original production guidance for 2014. Fortunately, the weather related issues appear to be behind us and the mechanical issues are mostly resolved. Going forward, we plan to accelerate our development operations in the Granite Wash and our SOHOT (Southern Oklahoma Hoxbar Oil Trend) emerging play while slowing our drilling schedule in the Mississippian play. Our original capital budget of $718 million for this segment remains unchanged. We remain confident in our prospect inventory and our ability to continue to provide solid growth in production throughout the balance of 2014 and beyond. “Rig utilization in our contract drilling segment improved through the first quarter. Average utilization increased 4% to 68 drilling rigs working compared to 65 drilling rigs working in the fourth quarter of 2013. The improvement is continuing into the second quarter. We sold four idle 3,000 horsepower drilling rigs to an international contractor during the quarter. Our first BOSS drilling rig was placed into service in late March, bringing our total rig fleet to 118 drilling rigs. We have contracts for three additional BOSS drilling rigs. Those drilling rigs are currently being built and scheduled to go into service in the second and third quarters of this year. “Our midstream segment continues to benefit from our previous capital investments in several of its projects including the Bellmon facility in the Mississippian play in Oklahoma and the Pittsburgh Mills facility in the Appalachian area. Operating profit for the quarter benefitted from strong NGLs pricing, particularly propane, and we are now operating in full ethane recovery mode at all of our processing facilities. Our goal is to position this segment for sustainable growth with less exposure to commodity price volatility. As appropriate, we continue to restructure expiring commodity price based contracts to fee based contracts.” Notable items for the quarter include: *Adjusted non-GAAP net income of $62.8 million, or $1.29 per diluted share (see Non-GAAP Financial Measures below). *Total production of 4.2 million barrels of oil equivalent (MMBoe), a 5% increase over the first quarter of 2013. *The first BOSS drilling rig went into service, with three additional BOSS drilling rigs under construction. *Average drilling rig utilization increased 4% over the prior quarter. *Mid-stream segment’s liquids sold volumes per day increased by 69% over the first quarter of 2013. Net income for the quarter was $56.9 million, or $1.17 per diluted share, compared to $40.2 million, or $0.83 per diluted share, for the first quarter of 2013. Adjusted net income, which excludes the effect of non-cash commodity derivatives, was $62.8 million, or $1.29 per diluted share (see Non-GAAP Financial Measures below). Total revenues were $388.0 million (49% oil and natural gas, 27% contract drilling, and 24% mid-stream), compared to $318.5 million (48% oil and natural gas, 34% contract drilling, and 18% mid-stream) for the first quarter of 2013. OIL AND NATURAL GAS SEGMENT INFORMATION Total equivalent production for the quarter was 46,500 Boe per day, an increase of 5% over the first quarter of 2013 and a decrease of 4% from the fourth quarter of 2013. Liquids (oil and NGLs) production represented 45% of total equivalent production for the quarter. Liquids production has increased 155% since the first quarter of 2009. Oil production for the quarter was 9,000 barrels per day, an increase of 2% over the first quarter of 2013 and a decrease of 7% from the fourth quarter of 2013. NGLs production for the quarter was 11,800 barrels per day, an increase of 32% over the first quarter of 2013 and a decrease of 6% from the fourth quarter of 2013. Natural gas production for the quarter was 153,900 Mcf per day, a decrease of 3% from the first quarter of 2013 and a decrease of 1% from the fourth quarter of 2013. Unit’s average realized per barrel equivalent price for the quarter was $41.84, an increase of 10% and 9% over the first quarter of 2013 and the fourth quarter of 2013, respectively. Unit’s average natural gas price for the quarter was $4.24 per thousand cubic feet (Mcf), an increase of 28% and 32% over the first quarter of 2013 and the fourth quarter of 2013, respectively. Unit’s average oil price for the quarter was $91.53 per barrel, a decrease of 4% and 3% from the first quarter of 2013 and the fourth quarter of 2013, respectively. Unit’s average NGLs price for the quarter was $39.56 per barrel, an increase of 13% and 17% over the first quarter of 2013 and the fourth quarter of 2013, respectively. All prices in this paragraph include the effects of derivatives. For 2014, Unit has derivative contracts for 7,250 Bbls per day of oil production and 90,000 MMBtu per day of natural gas production. The contracts for oil production are swap contracts for 3,250 Bbls per day and collars for 4,000 Bbls per day. The swap transactions were done at a comparable average NYMEX price of $92.35. The collar transactions were done at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The contracts for natural gas production are swaps for 80,000 MMBtu per day and a collar for 10,000 MMBtu per day. The swap transactions were done at a comparable average NYMEX price of $4.24. The collar transaction was done at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37. The following table illustrates Unit’s production and realized prices for the periods indicated: 1^st 4^th 3^rd 2^nd 1^st 4^th 3^rd 2^nd 1^st Qtr 14 Qtr 13 Qtr 13 Qtr 13 Qtr 13 Qtr 12 Qtr 12 Qtr 12 Qtr 12 Oil and NGL Production, 1,875.2 2,046.7 1,832.9 1,794.1 1,600.6 1,694.1 1,545.8 1,460.2 1,375.2 MBbl Natural Gas Production, 13.9 14.3 14.3 13.9 14.2 14.5 11.7 11.3 11.4 Bcf Production, 4,184 4,438 4,217 4,109 3,971 4,115 3,498 3,341 3,275 MBoe Production, 46.5 48.2 45.8 45.2 44.1 44.7 38.0 36.7 36.0 MBoe/day Realized Price, Boe $41.84 $38.24 $35.77 $39.10 $37.99 $39.56 $37.99 $38.49 $40.51 (1) (1) Realized price includes oil, natural gas liquids, natural gas and associated derivatives. During the quarter, Unit experienced two factors that contributed to the estimated production loss of approximately 2.2 Bcfe. The first was weather. Well freeze offs and operational delays caused by inclement weather, primarily in the company’s Mid-Continent plays, resulted in a reduction in production from the impacted wells. Second, Unit incurred mechanical issues on nine separate wells primarily within its Granite Wash play. These problems involved either liner issues in the horizontal component of the wells or casing leaks just above the liner top packer. As a result, the wells required remediation work before they could be completed. To date, six of the nine wells have been repaired. Work is continuing on the remaining three wells. Although the company believes it will successfully repair all nine wells, the flow rate from five of the nine wells may experience reduced rates as a result of these problems. On average, first production from these nine wells has been delayed approximately three months as compared to their initial forecasted production date. Going forward, Unit has modified its casing and liner program which should eliminate any further problems. In response to these production delays, Unit plans to accelerate its drilling program in both the Granite Wash and its new emerging play (SOHOT, discussed below) in an effort to make up part of the incurred production losses; however, the company forecasts that its first production resulting from these increased drilling efforts will not occur until mid-to-late third quarter primarily due to the production timing of pad drilling. As a result, Unit is reducing its current 2014 production guidance to 13% - 15%. The capital required for the increased drilling in the Granite Wash and SOHOT will be reallocated from its Mississippian play (as discussed below). Unit’s newest core play, SOHOT, is an emerging play located in southwest Grady County. The Hoxbar is a Pennsylvanian sand/shale sequence that is approximately 2,000’ thick that contains four to six potentially productive stacked sand benches. Unit recently completed horizontal wells in two of the Hoxbar sand benches, indicating the discovery of an oil zone (Marchand) and a natural gas zone (Medrano) at true vertical depths of approximately 11,000’ and 9,800’ respectively. The completed well cost for the Marchand with a 4,300’ lateral is approximately $7.0 million. The estimated ultimate reserves (EUR) are projected at 300 MBoe to 500 MBoe for this well, consisting of approximately 85% to 90% oil. The Medrano completed well cost with a 4,200’ lateral is approximately $4.2 million with an EUR of 3.0 to 4.5 Bcfe, consisting of an average of approximately 30% liquids. In its current focus area in southwest Grady County, Unit has 50,560 gross acres and 12,810 net acres. The company has one rig drilling in the play and plans to add two additional rigs in June for a total of three rigs running during the second half of 2014. The 2014 capital drilling budget in this area has been increased approximately 49% to $82 million. In the Granite Wash (GW) play, all nine wells in the initial horizontal program in the Buffalo Wallow field have been successfully completed. Unit will move one drilling rig back into the Buffalo Wallow field in late May. Unit will add an additional rig in the GW play in July. After adding these two drilling rigs, there will be a total of six drilling rigs running in the GW with expectations to maintain that pace through the rest of the year. The Wilcox play, located in southeast Texas, achieved its fifth consecutive quarter of production growth with production up 32% for the first quarter 2014 compared to the first quarter 2013. The Gilly field continues to be a first class Basal Wilcox field discovery with excellent results obtained from four recent well recompletions. For 2014, the company plans to run two rigs supplemented by a strategic recompletion program throughout the Wilcox play area. In the Marmaton horizontal oil play, three horizontally stacked lateral wells have recently been drilled targeting both the Upper and Lower Marmaton benches in the same wellbore. The production from these wells will be evaluated to determine the feasibility of drilling a greater portion of our Marmaton well program with this design. Currently, Unit anticipates maintaining the two drilling rig program in the play. In the Mississippian play, located in south central Kansas, the current drilling program is being modified to reduce from two drilling rigs to one drilling rig while Unit evaluates the well production results and explores the potential of shooting a 3-D seismic survey over a portion of its leasehold. Unit’s revised budgeted capital for this play is approximately $89 million, which is a reduction of approximately $48 million. The $48 million will be reallocated to the company’s GW and SOHOT plays. CONTRACT DRILLING SEGMENT INFORMATION The average number of drilling rigs used in the first quarter of 2014 was 67.9, an increase of 2% and 4% over the first quarter of 2013 and the fourth quarter of 2013, respectively. Per day drilling rig rates for the first quarter of 2014 averaged $19,615, relatively flat with the first quarter of 2013 and the fourth quarter of 2013. Average per day operating margin for the first quarter of 2014 was $7,870 (before elimination of intercompany drilling rig profit of $5.3 million). This compares to $7,534 (before elimination of intercompany drilling rig profit of $3.4 million) for the first quarter of 2013, an increase of 4%, or $336. As compared to the fourth quarter of 2013 ($8,132 before elimination of intercompany drilling rig profit of $5.7 million), first quarter 2014 operating margin decreased 3% or $262 (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For the fourth quarter of 2013 average operating margins included early termination fees of approximately $161 per day from the cancellation of certain long-term contracts. Larry Pinkston said: “Drilling rig demand continued at a steady increase during the first quarter of 2014. Almost all of our drilling rigs working today are drilling for oil or NGLs. With the sale of the four idle 3,000 horsepower drilling rigs and adding our first BOSS drilling rig, our drilling fleet currently totals 118 drilling rigs. Of the 118 drilling rigs, we currently have 73 under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 30 of the 73 drilling rigs. Of the 30 long-term contracts, one is up for renewal during the second quarter, nine in the third quarter, eight in the fourth quarter, and 12 are up for renewal in 2015. We are currently building three additional BOSS rigs. All three are contracted to third party operators and are anticipated to be placed into service in the second and third quarters of 2014.” The following table illustrates Unit’s drilling segment drilling rig count at the end of each period and average utilization rate during the period: 1^st 4^th 3^rd 2^nd 1^st 4^th 3^rd 2^nd 1^st Qtr Qtr Qtr Qtr Qtr Qtr Qtr Qtr Qtr 14 13 13 13 13 12 12 12 12 Drilling 118 121 124 126 127 127 127 128 127 Rigs Utilization 57% 53% 51% 51% 52% 50% 58% 60% 64% MID-STREAM SEGMENT INFORMATION First quarter per day liquids sold were 712,225 gallons, an increase of 69% over the first quarter of 2013. Per day gas gathered and processed volumes increased 11% and 16%, respectively, as compared to the first quarter of 2013. Compared to the fourth quarter of 2013, gathered volumes per day decreased 3%, while liquids sold volumes per day and processed volumes per day increased 9% and 1%, respectively. Operating profit (as defined in the Selected Financial and Operational Highlights) for the quarter was $12.2 million, an increase of 53% over the first quarter of 2013 and relatively flat compared to the fourth quarter of 2013. The following table illustrates certain results from this segment’s operations for the periods indicated: 1^st 4^th 3^rd 2^nd 1^st 4^th 3^rd 2^nd 1^st Qtr 14 Qtr 13 Qtr 13 Qtr 13 Qtr 13 Qtr 12 Qtr 12 Qtr 12 Qtr 12 Gas gathered 304,083 312,254 326,474 326,039 272,831 279,990 241,271 262,269 217,404 Mcf/day Gas processed 150,042 149,069 145,020 138,130 129,857 131,570 134,907 144,257 125,231 Mcf/day Liquids sold 712,225 656,415 586,446 508,189 420,291 441,973 576,889 629,350 522,829 Gallons/day Larry Pinkston said: “During the quarter, we continued to see improvement in NGLs pricing primarily associated with propane price increases due to seasonal demand and shortages of supply. In order to maximize our propane recovery, we began recovering all liquids. We operated in full ethane recovery mode at all of our processing systems during the quarter, which resulted in a significant increase in liquids sold volumes. As a result of prior capital investment, we have positioned the segment for growth with limited incremental capital investment required to more efficiently utilize our system capacity. During the quarter, we connected 46 new wells as compared to 31 wells in the fourth quarter of 2013. These activities resulted in achieving new records for gas processed volumes at three of our Central Oklahoma processing plants. We believe this speaks positively to the activity levels in the plays in which we have made investments.” FINANCIAL INFORMATION Unit ended the quarter with long-term debt of $645.8 million (comprising senior subordinated notes), and a debt to capitalization ratio of 22%. Unit currently has no borrowings under its credit agreement. Under the credit agreement, 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 first quarter conference call live over the Internet on May 8, 2014 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 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 and operations data) Three Months Ended March 31, 2014 2013 Statement of Income: Revenues: Oil and natural gas $ 188,207 $ 153,609 Contract drilling 106,600 107,528 Gas gathering and processing 93,181 57,395 Total revenues 387,988 318,532 Expenses: Oil and natural gas: Operating costs 40,415 43,038 Depreciation, depletion, and amortization 59,680 51,983 Contract drilling: Operating costs 63,804 66,002 Depreciation 18,395 17,260 Gas gathering and processing: Operating costs 80,960 49,410 Depreciation and amortization 9,591 7,156 General and administrative 9,637 8,673 (Gain) loss on disposition of assets (9,426 ) 84 Total expenses 273,056 243,606 Income from operations 114,932 74,926 Other income (expense): Interest, net (3,790 ) (3,561 ) Loss on derivatives not designated as hedges and (18,366 ) (5,924 ) hedge ineffectiveness, net Other 120 (66 ) Total other income (expense) (22,036 ) (9,551 ) Income before income taxes 92,896 65,375 Income tax expense: Current 9,795 2,517 Deferred 26,156 22,652 Total income taxes 35,951 25,169 Net income $ 56,945 $ 40,206 Net income per common share: Basic $ 1.17 $ 0.84 Diluted $ 1.17 $ 0.83 Weighted average shares outstanding: Basic 48,493 48,117 Diluted 48,872 48,412 March 31, December 31, 2014 2013 Balance Sheet Data: Current assets $ 223,263 $ 212,031 Total assets $ 4,116,836 $ 4,022,390 Current liabilities $ 263,237 $ 243,573 Long-term debt $ 645,809 $ 645,696 Other long-term liabilities $ 145,454 $ 158,331 Deferred income taxes $ 827,554 $ 801,398 Shareholders’ equity $ 2,234,782 $ 2,173,392 Three Months Ended March 31, 2014 2013 Statement of Cash Flows Data: Cash flow from operations before changes in operating assets and liabilities (1) $ 178,224 $ 153,314 Net change in operating assets and (54,764 ) 26,346 liabilities Net cash provided by operating $ 123,460 $ 179,660 activities Net cash used in investing activities $ (160,518 ) $ (191,471 ) Net cash provided by financing $ 19,517 $ 11,990 activities Three Months Ended March 31, 2014 2013 Oil and Natural Gas Operations Data: Production: Oil – MBbls 810 797 Natural Gas Liquids - MBbls 1,065 804 Natural Gas - MMcf 13,854 14,220 Average Prices: Oil price per barrel received $ 91.53 $ 95.23 Oil price per barrel received, excluding $ 95.05 $ 91.94 derivatives NGLs price per barrel received $ 39.56 $ 34.99 NGLs price per barrel received, excluding derivatives $ 39.56 $ 34.99 Natural gas price per Mcf received $ 4.24 $ 3.30 Natural gas price per Mcf received, excluding derivatives $ 4.68 $ 3.14 Operating profit before depreciation, depletion, and amortization (2) ($MM) $ 147.8 $ 110.6 Contract Drilling Operations Data: Rigs utilized 67.9 66.3 Operating margins (2) 40 % 39 % Operating profit before depreciation (2) $ 42.8 $ 41.5 ($MM) Mid-Stream Operations Data: Gas gathering - Mcf/day 304,083 272,831 Gas processing - Mcf/day 150,042 129,857 Liquids sold – Gallons/day 712,225 420,291 Operating profit before depreciation and amortization (2) ($MM) $ 12.2 $ 8.0 (1) The company considers its cash flow from operations before changes in operating assets and liabilities an important measure in meeting the performance goals of the company (see Non-GAAP Financial Measures below). (2) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, general and administrative, and gain (loss) on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue. 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, 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 months ended March 31, 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 Three Months Ended March 31, 2014 2013 (In thousands) Net cash provided by operating activities $ 123,460 $ 179,660 Net change in operating assets and liabilities 54,764 (26,346 ) Cash flow from operations before changes in operating assets and liabilities $ 178,224 $ 153,314 ________________ 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 Three Months Ended December 31, March 31, 2013 2014 2013 (In thousands except operating days and operating margins) Contract drilling revenue $ 101,598 $ 106,600 $ 107,528 Contract drilling operating cost 58,700 63,804 66,002 Operating profit from contract 42,898 42,796 41,526 drilling Add: 5,741 5,313 3,409 Elimination of intercompany rig profit Operating profit from contract drilling before elimination of intercompany rig profit 48,639 48,109 44,935 Contract drilling operating days 5,981 6,113 5,964 Average daily operating margin before elimination of intercompany rig $ 8,132 $ 7,870 $ 7,534 profit ________________ The Company has included the average daily operating margin before elimination of intercompany rig profit 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 March 31, 2014 2013 (In thousands except per share amounts) Adjusted net income: Net income $ 56,945 $ 40,206 Loss on derivatives not designated as hedges and hedge ineffectiveness (net of 11,258 3,644 income tax) Settlements during the period of matured derivative contracts (net of (5,438 ) 639 income tax) Adjusted net income $ 62,765 $ 44,489 Adjusted diluted earnings per share: Diluted earnings per share $ 1.17 $ 0.83 Diluted earnings per share from the loss on derivatives 0.23 0.08 Diluted earnings per share from the settlements of matured derivative contracts (0.11 ) 0.01 Adjusted diluted earnings per $ 1.29 $ 0.92 share ________________ The Company has included the net income and diluted earnings per share excluding the impairment of oil and natural gas properties and 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 analyst. Contact: Unit Corporation Michael D. Earl, 918-493-7700 Vice President, Investor Relations www.unitcorp.com
Unit Corporation Reports 2014 First Quarter Results
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