Attached files
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| 8-K - 8-K - UNIT CORP | form8-k_4q13.htm |
News | UNIT CORPORATION |
7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136 | |
Telephone 918 493-7700, Fax 918 493-7714 | |
Contact: | Michael D. Earl |
Vice President, Investor Relations | |
(918) 493-7700 | |
www.unitcorp.com | |
For Immediate Release…
February 25, 2014
UNIT CORPORATION REPORTS 2013 FOURTH QUARTER & YEAR END RESULTS
A PROMISING LOOK TO THE FUTURE
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the fourth quarter and year 2013.
Larry Pinkston, Unit’s Chief Executive Officer and President, stated “During 2013, the company continued to progress on several strategic initiatives. Our production in the fourth quarter increased 5% over the third quarter and overall production increased 18% year over year. Throughout the fourth quarter we increased the number of operated drilling rigs drilling for our oil and natural gas segment under our previously stated plans, and we initiated our pad drilling program in the Granite Wash. In our contract drilling segment, we completed the sale of five idle drilling rigs during the year, and we will place our first BOSS rig into service during the first quarter 2014. Our midstream segment continued to see the benefit of previous capital investments.”
“For the oil and natural gas segment, we are very pleased with our fourth quarter production growth. For the full year, we achieved the upper end of our production guidance. Fourth quarter production growth was primarily driven by the Wilcox and Granite Wash plays. During 2013, we completed sales of certain non-core oil and natural gas assets, with total proceeds of $78.8 million with the most significant portion coming from the sale of the majority of our non-operated Bakken assets. We ended 2013 with total proved reserves of 160 million barrels of oil equivalent (MMBoe), a 7% increase, despite the sale of non-core properties with total proved reserves of 3.5 MMBoe. Weather and operational delays will affect first quarter 2014 production; however, we continue to anticipate production growth for 2014 of between 15% and 18%.”
“Our contract drilling segment operated in a soft drilling market throughout 2013; however, we were able to maintain fairly consistent utilization. During the fourth quarter of 2013 we averaged 65 drilling rigs operating. We have seen improvement in utilization in the first quarter of 2014. Currently, we have 69 drilling rigs operating with continued improvement expected through the end of the first quarter. We also initiated a comprehensive evaluation of our drilling rig fleet that included a review regarding the possible realignment of our fleet’s capabilities and efficiencies. In view of the demand for drilling rigs using new technologies and capabilities, we determined we should pursue the sale of several of our older and larger drilling rigs that have not worked for some time. As a result, during 2013, we sold four of our idle 2,000 horsepower drilling rigs and one 3,000 horsepower drilling rig with proceeds totaling $32.4 million. In addition, the sale of four additional idle 3,000 horsepower drilling rigs was completed after year end. The proceeds from these sales will be used in our new drilling rig program, a program we launched to design and build a new proprietary drilling rig, the BOSS rig. We anticipate this drilling rig, coupled with continued enhancements to our existing fleet, will position us to continue to meet the demands of our existing customers and allow us to compete for the work of new customers. Our first BOSS drilling rig will work for our oil and natural gas segment during the first quarter of 2014. We are optimistic that the BOSS drilling rig will be well received by operators and will result in additional new-build contract opportunities.
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“The midstream segment is experiencing the benefit of previous capital investments in several of our projects including the Bellmon facility in the Mississippian play in Oklahoma and the Pittsburgh Mills facility in the Appalachian area. Downward price pressure on natural gas liquids (NGLs) during 2012 impacted this segment’s cash flows. Due to the increase in liquids pricing in the first quarter of 2014, particularly propane, we are now operating in full ethane recovery mode at all of our processing facilities. Our goal is to position this segment for more sustainable growth with less cash flow volatility. Where possible, we are restructuring existing commodity price based contracts as they expire to fee based contracts. These changes, while allowing us to remain competitive, should reduce this segment’s exposure to commodity price risks.”
Notable items for the company for the quarter include:
• | Adjusted non-GAAP net income of $54.3 million, or $1.11 per diluted share (see Non-GAAP Financial Measures below). |
• | Total production of 4.4 MMBoe, an increase of 8% over the fourth quarter of 2012. |
• | Total liquids (oil and NGLs) production increased 21% over the comparable quarter of 2012. |
• | Completed the sale of a 2,000 horsepower drilling rig and a 3,000 horsepower drilling rig, bringing to five the number of drilling rigs sold in 2013. |
• | Mid-stream segment’s gathered volumes per day, processed volumes per day and liquids sold volumes per day increased by 12%, 13% and 49%, respectively, over the fourth quarter of 2012. |
Net income for the quarter was $51.3 million, or $1.05 per diluted share, compared to a loss of $56.5 million, or $1.18 per diluted share, for the fourth quarter of 2012. Adjusted net income, which excludes the effect of non-cash commodity derivatives, was $54.3 million, or $1.11 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $359.1 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream), compared to $331.6 million (50% oil and natural gas, 33% contract drilling, and 17% mid-stream) for the fourth quarter of 2012.
Net income for 2013 was $184.7 million, or $3.80 per diluted share, compared to $23.2 million, or $0.48 per diluted share, for 2012. Adjusted net income for 2013, which excludes the effect of non-cash commodity derivatives, was $188.8 million, or $3.89 per diluted share (see Non-GAAP Financial Measures below). Total revenues for 2013 were $1.35 billion (48% oil and natural gas, 31% contract drilling, and 21% mid-stream), compared to $1.32 billion (43% oil and natural gas, 40% contract drilling, and 17% mid-stream) for 2012.
OIL AND NATURAL GAS SEGMENT INFORMATION
Unit’s production results reflect its focus on drilling oil or NGLs rich wells. Liquids production represented 46% of total equivalent production for the quarter. Total equivalent production for the quarter was 4.4 MMBoe, an increase of 8% and 5% over the fourth quarter of 2012 and third quarter of 2013, respectively. Liquids production has increased 178% since the first quarter of 2009 when Unit began to focus on increasing liquids production. Fourth quarter 2013 oil production was 891,000 barrels, a decrease of 2% from the fourth quarter of 2012 and an increase of 9% over the third quarter of 2013. NGLs production for the quarter was 1,156,000 barrels, an increase of 48% and 14% compared to the fourth quarter of 2012 and third quarter of 2013, respectively. Natural gas production for the fourth quarter of 2013 was 14.3 billion cubic feet (Bcf), a decrease of 1% from the fourth quarter of 2012 and relatively flat with the third quarter of 2013. Total production for 2013 was 16.7 MMBoe, an increase of 18% over 2012.
Unit’s average realized per barrel equivalent price for the fourth quarter of 2013 was $38.24, a decrease of 3% from the fourth quarter of 2012 and an increase of 7% over the third quarter of 2013. Unit’s average natural gas price for the fourth quarter of 2013 was $3.21 per thousand cubic feet (Mcf), a decrease of 12% from the fourth quarter of 2012 and a 3% increase over the third quarter of 2013. Unit’s average oil price for the quarter was $94.70 per barrel, an increase of 3% over the fourth quarter of 2012 and a decrease of 1% from the third quarter of 2013. Unit’s average NGLs price for the quarter was $33.94 per barrel, which was essentially unchanged from the fourth quarter of 2012 and an increase of 21% over the third quarter of 2013. For 2013, Unit’s average natural gas price decreased 1% to $3.32 per Mcf as compared to $3.37 per Mcf for 2012. Unit’s average oil price for 2013 was $95.06 per barrel compared to $92.60 per barrel during 2012, a 3% increase. Unit’s average NGLs price for 2013 was $31.79 per barrel compared to $31.58 per barrel during 2012, a 1% increase. All prices in this paragraph include the effects of hedges.
For 2013, Unit hedged 8,330 Bbls per day of its oil production and 100,000 MMBtu per day of natural gas production. The oil production was hedged under swap contracts at an average price of $97.94 per barrel. Of the natural gas production, 80,000 MMBtu per day were hedged with swaps and 20,000 MMBtu per day hedged with a collar. The swap transactions were at a comparable average NYMEX price of $3.65. The collar transaction was at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.
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For 2014, Unit has hedged 7,250 Bbls per day of its oil production and 90,000 MMBtu per day of natural gas production. Of the oil production, 3,250 Bbls per day are hedged with swaps and 4,000 Bbls per day are hedged with collars. The swap transactions have an average price of $92.35. The collar transactions have an average floor price of $90.00 and ceiling price of $96.08. Of the natural gas production, 80,000 MMBtu per day are hedged with swaps and 10,000 MMBtu per day are hedged with collars. The swap transactions are at a comparable average NYMEX price of $4.24. The collar transactions have 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:
4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | |||||||||||||||||||
Oil and NGL Production, MBbl | 2,046.7 | 1,832.9 | 1,794.1 | 1,600.6 | 1,694.1 | 1,545.8 | 1,460.2 | 1,375.2 | 1,359.9 | ||||||||||||||||||
Natural Gas Production, Bcf | 14.3 | 14.3 | 13.9 | 14.2 | 14.5 | 11.7 | 11.3 | 11.4 | 11.4 | ||||||||||||||||||
Production, MBoe | 4,438 | 4,217 | 4,109 | 3,971 | 4,115 | 3,498 | 3,341 | 3,275 | 3,255 | ||||||||||||||||||
Production, MBoe/day | 48.2 | 45.8 | 45.2 | 44.1 | 44.7 | 38 | 36.7 | 36 | 35.4 | ||||||||||||||||||
Realized Price, Boe (1) | $ | 38.24 | $ | 35.77 | $ | 39.1 | $ | 37.99 | $ | 39.56 | $ | 37.99 | $ | 38.49 | $ | 40.51 | $ | 42.65 | |||||||||
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
The Wilcox play in southeast Texas continues to deliver strong results with average daily production for the fourth quarter of 2013 increasing approximately 12% and 45% compared to the third quarter 2013 and the fourth quarter 2012, respectively. Production for 2013 increased 21% as compared to 2012. For 2013, Unit completed six vertical and one horizontal liquids rich Wilcox gas wells and drilled one dry hole. Unit owns 100% working interest in all eight wells. Unit’s first horizontal Wilcox well was completed in late November 2013 at an initial rate of approximately 4.4 MMcf per day and 73 barrels of condensate per day from approximately 1,500 feet of Basal Wilcox lateral. The initial results are encouraging, but additional production data is needed to better estimate the ultimate reserves of this well. There are currently two Unit rigs drilling in Unit’s Wilcox play with plans to add a third rig in the second half of the year, which should result in approximately 10 to 12 vertical wells and two to four horizontal wells drilled in this play in 2014.
In the Texas Panhandle District, which consists primarily of Granite Wash (GW) wells and to a lesser degree Cleveland wells, the average daily production for the fourth quarter of 2013 increased approximately 13% and 17% compared to the third quarter 2013 and the fourth quarter 2012, respectively. For 2013, production increased approximately 28% over 2012. Unit had first sales on 23 horizontal GW wells, having an average peak 30 day IP rate of 5.2 MMcfe per day and an average working interest of 85%. Unit also had first sales on three Cleveland wells with an average peak 30 day rate of 3.9 MMcfe per day at an average working interest of 80%. Unit recently completed drilling operations on three separate well pads located in different sections of the Buffalo Wallow GW field. Each pad has three wells resulting in nine total wells that will target five different GW sand intervals. Six of the wells have been fracture stimulated and the remaining three wells are scheduled to be fracture stimulated in the first quarter 2014. Unit plans to monitor production from these three pads for approximately 90 days prior to resuming pad drilling in the field. At the conclusion of the testing phase, the company will report the results from all nine wells. Unit plans to run three to five Unit rigs in the GW play and one Unit rig in the Cleveland play during 2014.
In Unit’s Mississippian play in south central Kansas, the average daily production for the fourth quarter of 2013 increased approximately 47% compared to the third quarter 2013. For 2013, production increased 218% as compared to 2012. Unit had first sales on eight Mississippian wells during 2013 with an average 30 day IP rate of 222 Boe per day consisting of an average of approximately 53% oil, 11% NGLs, and 36% natural gas with a 100% average working interest. The last four wells completed in the fourth quarter of 2013 had a significantly higher liquids cut consisting of approximately 79% oil, 6% NGLs, and 15% natural gas with an average 30 day IP rate of approximately 231 Boe per day. The company is currently considering altering its drilling program in this play in 2014 to drill extended lateral wells and to test different fracture stimulation designs. Unit is currently running two Unit rigs in the play.
In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit had first sales on 41 horizontal wells during 2013 with an average 30 day IP rate of 371 Boe per day with an approximate average working interest of 75%. The average daily production for the fourth quarter of 2013 was essentially unchanged from the third quarter 2013 but increased approximately 25% for
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the year as compared to 2012. Two additional potential horizontal targets in the play are scheduled to be tested in early 2014. Unit had two Unit rigs drilling in the play and plans to continue with this two rig drilling program.
YEAR END 2013 ESTIMATED PROVED RESERVES
The value of Unit’s estimated year-end 2013 proved reserves increased by 21% to $1.8 billion year over year. Unit’s estimated year-end 2013 proved oil and natural gas reserves were 160 MMBoe, or 960 billion cubic feet of natural gas equivalents (Bcfe), as compared with 150 MMBoe, or 899 Bcfe, at year-end 2012, a 7% increase in its estimated proved reserves. From all sources, Unit replaced approximately 161% of its 2013 production. Estimated reserves were 13% oil, 26% NGLs, and 61% natural gas. During 2013, Unit divested 3.5 MMBoe of non-core oil and natural gas reserves.
The following details the changes to Unit’s proved oil, NGLs, and natural gas reserves during 2013:
Oil (MMbls) | NGLs (MMbls) | Natural Gas (Bcf) | Proved Reserves (MMBoe) | ||||||
Proved Reserves, at December 31, 2012 | 22.0 | 35.2 | 555.6 | 149.8 | |||||
Revisions of previous estimates | (2.1 | ) | 0.8 | 2.4 | (0.9 | ) | |||
Extensions, discoveries, and other additions | 7.0 | 9.2 | 90.2 | 31.2 | |||||
Purchases of minerals in place | — | — | — | — | |||||
Production | (3.4 | ) | (3.9 | ) | (56.7 | ) | (16.7 | ) | |
Sales | (1.7 | ) | (0.1 | ) | (9.7 | ) | (3.5 | ) | |
Proved Reserves, at December 31, 2013 | 21.8 | 41.2 | 581.8 | 159.9 | |||||
The estimated 2013 year-end proved reserves included proved developed reserves of 123 MMBoe, or 740 Bcfe, (split 13% oil, 24% NGLs, and 63% natural gas) and proved undeveloped reserves of 37 MMBoe, or 219 Bcfe, (split 17% oil, 29% NGLs, and 54% natural gas). Overall, 77% of Unit’s estimated proved reserves are proved developed.
The present value of the estimated future net cash flows from the 2013 estimated proved reserves (before income taxes and using a 10% discount rate (PV-10)), was approximately $1.8 billion. The present value was determined using the 12 month 2013 average price received. The aggregate price used for all future reserves was $94.76 per barrel of oil, $34.61 per barrel of NGLs, and $3.58 per Mcf of natural gas. Unit’s 2013 year-end proved reserves were independently audited by Ryder Scott Company, L.P. Their audit covered properties which accounted for 84% 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.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2013 was 65.0, an increase of 2% over both the fourth quarter of 2012 and the third quarter of 2013. Per day drilling rig rates for the fourth quarter of 2013 averaged $19,630, a decrease of 1% from the fourth quarter of 2012 and the third quarter of 2013. Average per day operating margin for the fourth quarter of 2013 was $8,132 (before elimination of intercompany drilling rig profit of $5.7 million). This compares to $7,838 (before elimination of intercompany drilling rig profit of $2.6 million) for the fourth quarter of 2012, an increase of 4%, or $294. As compared to the third quarter of 2013 ($7,920 before elimination of intercompany drilling rig profit of $4.6 million), fourth quarter 2013 operating margin increased 3% or $212 (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, compared to $23 per day for the fourth quarter of 2012.
For 2013, Unit averaged 65.0 drilling rigs working, a decrease of 12% from 73.9 drilling rigs working during 2012. Average per day operating margin for 2013 was $7,796 (before elimination of intercompany drilling rig profit of $17.4 million) as compared to $9,578 (before elimination of intercompany drilling rig profit of $15.6 million) for 2012, a decrease of 19% (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For 2013, average operating margins included early termination fees of approximately $80 per day from the cancellation of certain long-term contracts, compared to $847 per day for 2012.
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Larry Pinkston said: “Drilling rig demand was fairly flat during 2013. Almost all of our drilling rigs working today are drilling for oil or NGLs. During the year, we sold four 2,000 horsepower drilling rigs, one 3,000 horsepower drilling rig, and retired one 700 horsepower drilling rig, bringing our fleet’s total to 121 drilling rigs at year end. Subsequent to year end, we sold four additional idle 3,000 horsepower drilling rigs, bringing our current fleet's total to 117 drilling rigs. Of the 117 drilling rigs, we have 69 under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 23 of those 69 drilling rigs. Of these contracts, seven are up for renewal during the first quarter of 2014, ten in the second quarter, five in the fourth quarter, and one is up for renewal in 2015. We are constructing a new prototype 1,500 horsepower AC electric drilling rig of proprietary design. This drilling rig, called our “BOSS” rig, will be operational in the first quarter of 2014 and will operate initially for our oil and natural gas segment. Two additional BOSS drilling rigs 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:
4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | |
Drilling Rigs | 121 | 124 | 126 | 127 | 127 | 127 | 128 | 127 | 127 |
Utilization | 53% | 51% | 51% | 52% | 50% | 58% | 60% | 64% | 65% |
MID-STREAM SEGMENT INFORMATION
Fourth quarter of 2013 per day gathered volumes were 312,254 Mcf, an increase of 12% over the fourth quarter of 2012. Per day liquids sold and processed volumes increased 49% and 13%, respectively, as compared to the fourth quarter of 2012. Compared to the third quarter of 2013, gathered volumes per day decreased 4%, while liquids sold volumes per day and processed volumes per day increased 12% and 3%, respectively. Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter of 2013 was $12.2 million, an increase of 89% over the fourth quarter of 2012 and a decrease of 4% from the third quarter of 2013. The decrease in operating profit during the fourth quarter was primarily due to an increase in operating expenses relating to cold weather.
The following table illustrates certain results from this segment’s operations for the periods indicated:
4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | ||||||||||
Gas gathered Mcf/day | 312,254 | 326,474 | 326,039 | 272,831 | 279,990 | 241,271 | 262,269 | 217,404 | 222,436 | |||||||||
Gas processed Mcf/day | 149,069 | 145,020 | 138,130 | 129,857 | 131,570 | 134,907 | 144,257 | 125,231 | 126,628 | |||||||||
Liquids sold Gallons/day | 656,415 | 586,446 | 508,189 | 420,291 | 441,973 | 576,889 | 629,350 | 522,829 | 511,410 | |||||||||
Larry Pinkston said: “In the first quarter of 2013, we completed the installation of a second processing plant at our Bellmon facility, a 30 MMcf per day cryogenic plant. The Bellmon facility is in the Mississippian play in north central Oklahoma and comprises approximately 185 miles of pipeline. Due to increasing volumes, we installed an additional 60 MMcf per day processing plant which became fully operational in February 2014. At our Hemphill facility in Hemphill County, Texas, we now can process 135 MMcf per day of our own and third party Granite Wash natural gas production after relocating two processing plants from Hemphill to the new Reno facility. In the fourth quarter of 2013, we completed two pipeline extension projects for a total cost of approximately $5.7 million, which will allow us to connect additional production from our oil and natural gas segment to this system. In Reno County, Kansas, we completed initial construction of a new gathering system and processing facility. This new system comprises approximately 20 miles of gathering pipeline and the two processing plants relocated from our Hemphill facility, a 5 MMcf per day refrigerated JT plant and a 20 MMcf per day turbo expander plant. We began gathering gas at this facility during the second quarter and processing gas in the third quarter of 2013.”
FINANCIAL INFORMATION
Unit ended the year with long-term debt of $645.7 million (comprising senior subordinated notes), and a debt to capitalization ratio of 23%. Under its credit agreement, the amount available to be borrowed is the lesser of the amount Unit elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $800 million), but in either event not to exceed $900 million. Unit currently has no borrowings under its credit agreement.
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MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with the performance of all three of our segments and are excited about their continued growth opportunities. Each segment is operating under key initiatives intended to create additional shareholder value for years to come. We continue to maintain a conservative financial profile. We are well positioned for sustained growth and to take advantage of new opportunities that may arise.”
WEBCAST
Unit will webcast its fourth quarter and year-end earnings conference call live over the Internet on February 25, 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.
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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.
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Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Statement of Income: | ||||||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas | $ | 173,990 | $ | 165,578 | $ | 649,718 | $ | 567,944 | ||||||||
Contract drilling | 101,598 | 108,521 | 414778 | 529,719 | ||||||||||||
Gas gathering and processing | 83,533 | 57,483 | 287354 | 217,460 | ||||||||||||
Total revenues | 359,121 | 331,582 | 1351850 | 1,315,123 | ||||||||||||
Expenses: | ||||||||||||||||
Oil and natural gas: | ||||||||||||||||
Operating costs | 45,830 | 45,177 | 184,001 | 150,212 | ||||||||||||
Depreciation, depletion, and amortization | 62,886 | 57,508 | 226,498 | 211,347 | ||||||||||||
Impairment of oil and natural gas properties | — | 167,732 | — | 283,606 | ||||||||||||
Contract drilling: | ||||||||||||||||
Operating costs | 58,700 | 65,544 | 247,280 | 289,524 | ||||||||||||
Depreciation | 18,624 | 18,347 | 71,194 | 81,007 | ||||||||||||
Gas gathering and processing: | ||||||||||||||||
Operating costs | 71,341 | 51,049 | 243,406 | 187,292 | ||||||||||||
Depreciation and amortization | 9,048 | 8,058 | 33,191 | 24,388 | ||||||||||||
General and administrative | 10,035 | 9,272 | 38,323 | 33,086 | ||||||||||||
Gain on disposition of assets | (9,332 | ) | 1,030 | (17,076 | ) | (253 | ) | |||||||||
Total expenses | 267,132 | 423,717 | 1,026,817 | 1,260,209 | ||||||||||||
Income (loss) from operations | 91,989 | (92,135 | ) | 325,033 | 54,914 | |||||||||||
Other income (expense): | ||||||||||||||||
Interest, net | (3,238 | ) | (2,682 | ) | (15,015 | ) | (14,137 | ) | ||||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | (5,034 | ) | 3,378 | (8,374 | ) | (1,243 | ) | |||||||||
Other | (4 | ) | (9 | ) | (175 | ) | (132 | ) | ||||||||
Total other income (expense) | (8,276 | ) | 687 | (23,564 | ) | (15,512 | ) | |||||||||
Income (loss) before income taxes | 83,713 | (91,448 | ) | 301,469 | 39,402 | |||||||||||
Income tax expense (benefit): | ||||||||||||||||
Current | 9,246 | 246 | 15,991 | 696 | ||||||||||||
Deferred | 23,166 | (35,147 | ) | 100,732 | 15,530 | |||||||||||
Total income taxes | 32,412 | (34,901 | ) | 116,723 | 16,226 | |||||||||||
Net income (loss) | $ | 51,301 | $ | (56,547 | ) | $ | 184,746 | $ | 23,176 | |||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 1.06 | $ | (1.18 | ) | $ | 3.83 | $ | 0.48 | |||||||
Diluted | $ | 1.05 | $ | (1.18 | ) | $ | 3.80 | $ | 0.48 | |||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 48,292 | 47,960 | 48,218 | 47,909 | ||||||||||||
Diluted | 48,795 | 47,960 | 48,572 | 48,154 | ||||||||||||
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December 31, | December 31, | ||||||
2013 | 2012 | ||||||
Balance Sheet Data: | |||||||
Current assets | $ | 212,031 | $ | 195,644 | |||
Total assets | $ | 4,022,390 | $ | 3,761,120 | |||
Current liabilities | $ | 243,573 | $ | 207,139 | |||
Long-term debt | $ | 645,696 | $ | 716,359 | |||
Other long-term liabilities | $ | 158,331 | $ | 167,545 | |||
Deferred income taxes | $ | 801,398 | $ | 695,776 | |||
Shareholders’ equity | $ | 2,173,392 | $ | 1,974,301 | |||
Twelve Months Ended December 31, | |||||||
2013 | 2012 | ||||||
Statement of Cash Flows Data: | |||||||
Cash flow from operations before changes in operating assets and liabilities (1) | $ | 637,936 | $ | 664,765 | |||
Net change in operating assets and liabilities | 36,395 | 26,146 | |||||
Net cash provided by operating activities | $ | 674,331 | $ | 690,911 | |||
Net cash used in investing activities | $ | (579,180 | ) | $ | (1,079,042 | ) | |
Net cash provided by (used in) financing activities | $ | (77,532 | ) | $ | 388,270 | ||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Oil and Natural Gas Operations Data: | |||||||||||||||
Production: | |||||||||||||||
Oil - MBbls | 891 | 912 | 3,360 | 3,279 | |||||||||||
Natural Gas Liquids - MBbls | 1,156 | 782 | 3,914 | 2,796 | |||||||||||
Natural Gas - MMcf | 14,346 | 14,527 | 56,757 | 48,930 | |||||||||||
Average Prices: | |||||||||||||||
Oil price per barrel received | $ | 94.70 | $ | 91.67 | $ | 95.06 | $ | 92.60 | |||||||
Oil price per barrel received, excluding hedges | $ | 94.34 | $ | 85.67 | $ | 95.18 | $ | 90.19 | |||||||
NGLs price per barrel received | $ | 33.94 | $ | 33.85 | $ | 31.79 | $ | 31.58 | |||||||
NGLs price per barrel received, excluding hedges | $ | 33.94 | $ | 33.39 | $ | 31.79 | $ | 30.70 | |||||||
Natural gas price per Mcf received | $ | 3.21 | $ | 3.63 | $ | 3.32 | $ | 3.37 | |||||||
Natural gas price per Mcf received, excluding hedges | $ | 3.19 | $ | 3.09 | $ | 3.33 | $ | 2.53 | |||||||
Operating profit before depreciation, depletion, amortization, and impairment (2) ($MM) | $ | 128.2 | $ | 120.4 | $ | 465.7 | $ | 417.7 | |||||||
Contract Drilling Operations Data: | |||||||||||||||
Rigs utilized | 65.0 | 64.0 | 65.0 | 73.9 | |||||||||||
Operating margins (2) | 42% | 40% | 40% | 45% | |||||||||||
Operating profit before depreciation (2) ($MM) | $ | 42.9 | $ | 43.0 | $ | 167.5 | $ | 240.2 | |||||||
Mid-Stream Operations Data: | |||||||||||||||
Gas gathering - Mcf/day | 312,254 | 279,990 | 309,554 | 250,290 | |||||||||||
Gas processing - Mcf/day | 149,069 | 131,570 | 140,584 | 133,987 | |||||||||||
Liquids sold - Gallons/day | 656,415 | 441,973 | 543,602 | 542,578 | |||||||||||
Operating profit before depreciation and amortization (2) ($MM) | $ | 12.2 | $ | 6.4 | $ | 43.9 | $ | 30.2 | |||||||
(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, impairment, general and administrative and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.
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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 and excluding the impairment of oil and natural gas properties, and its unaudited oil and natural gas reserves reconciliation of PV-10 to standard measure.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2013 and 2012. 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
Twelve Months Ended December 31, | |||||||
2013 | 2012 | ||||||
Net cash provided by operating activities | $ | 674,331 | $ | 690,911 | |||
Net change in operating assets and liabilities | (36,395 | ) | (26,146 | ) | |||
Cash flow from operations before changes in operating assets and liabilities | $ | 637,936 | $ | 664,765 | |||
________________
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 | Twelve Months Ended | ||||||||||||||||||
September 30, | December 31, | December 31, | |||||||||||||||||
2013 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
(In thousands except for operating days and operating margins) | |||||||||||||||||||
Contract drilling revenue | $ | 100,647 | $ | 101,598 | $ | 108,521 | $ | 414,778 | $ | 529,719 | |||||||||
Contract drilling operating cost | 58,988 | 58,700 | 65,544 | 247,280 | 289,524 | ||||||||||||||
Operating profit from contract drilling | 41,659 | 42,898 | 42,977 | 167,498 | 240,195 | ||||||||||||||
Add: | |||||||||||||||||||
Elimination of intercompany rig profit | 4,579 | 5,741 | 2,647 | 17,416 | 15,583 | ||||||||||||||
Operating profit from contract drilling before elimination of intercompany rig profit | 46,238 | 48,639 | 45,624 | 184,914 | 255,778 | ||||||||||||||
Contract drilling operating days | 5,838 | 5,981 | 5,821 | 23,720 | 26,704 | ||||||||||||||
Average daily operating margin before elimination of intercompany rig profit | $ | 7,920 | $ | 8,132 | $ | 7,838 | $ | 7,796 | $ | 9,578 | |||||||||
________________
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. |
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Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands except per share amounts) | |||||||||||||||
Adjusted net income: | |||||||||||||||
Net income (loss) | $ | 51,301 | $ | (56,547 | ) | $ | 184,746 | $ | 23,176 | ||||||
Impairment of oil and natural gas properties | — | 104,450 | — | 176,582 | |||||||||||
(Gain) loss on derivatives not designated as hedges and hedge ineffectiveness (net of income tax) | 3,095 | (2,053 | ) | 5,142 | 767 | ||||||||||
Settlements during the period of matured derivative contracts (net of income tax) | (116 | ) | — | (1,081 | ) | — | |||||||||
Adjusted net income | $ | 54,280 | $ | 45,850 | $ | 188,807 | $ | 200,525 | |||||||
Adjusted diluted earnings per share: | |||||||||||||||
Diluted earnings (loss) per share | $ | 1.05 | $ | (1.18 | ) | $ | 3.80 | $ | 0.48 | ||||||
Impairment of oil and natural gas properties | — | 2.17 | — | 3.67 | |||||||||||
Diluted earnings per share from the (gain) loss on derivatives | 0.06 | (0.04 | ) | 0.11 | 0.01 | ||||||||||
Diluted earnings per share from the settlements of matured derivative contracts | — | — | (0.02 | ) | — | ||||||||||
Adjusted diluted earnings per share | $ | 1.11 | $ | 0.95 | $ | 3.89 | $ | 4.16 | |||||||
________________
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. |
Unaudited Reconciliation of PV-10 to Standard Measure
December 31, 2013
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 in accordance with 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:
2013 | |||
($ in billions) | |||
PV-10 at December 31, 2013 | $ | 1.8 | |
Discounted effect of income taxes | (0.6) | ||
Standardized Measure at December 31, 2013 | $ | 1.2 | |
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