Attached files
| file | filename |
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| 8-K - FORM 8-K - UNIT CORP | Form8k02192013.htm |
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News
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UNIT CORPORATION
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7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
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Telephone 918 493-7700, Fax 918 493-7714
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Contact:
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Michael D. Earl
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Vice President, Investor Relations
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(918) 493-7700
www.unitcorp.com
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For Immediate Release…
February 19, 2013
UNIT CORPORATION REPORTS 2012 FOURTH QUARTER AND YEAR END RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported results for the fourth quarter of 2012. Those results included a previously announced non-cash ceiling test write down of $167.7 million ($104.5 million after tax, or $2.17 per diluted share). Because of the ceiling test write down, Unit incurred a net loss of $56.5 million, or $1.18 per diluted share, for the fourth quarter of 2012, compared to net income of $51.7 million, or $1.08 per diluted share for the fourth quarter of 2011. The ceiling test write down, which reduced the carrying value of the company’s oil and natural gas properties, resulted from significantly lower commodity prices during the fourth quarter of 2012. Without the ceiling test write down, net income for the fourth quarter of 2012 would have been $47.9 million, or $0.99 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the fourth quarter of 2012 were $331.6 million (50% oil and natural gas, 33% contract drilling, and 17% mid-stream), compared to $347.3 million (41% oil and natural gas, 41% contract drilling, and 18% mid-stream) for the fourth quarter of 2011.
For 2012, Unit reported net income of $23.2 million, or $0.48 per diluted share. For 2011, net income was $195.9 million, or $4.08 per diluted share. Included in the 2012 results were ceiling test write downs totaling $283.6 million ($176.6 million after tax, or $3.67 per diluted share). Excluding these ceiling test write downs, net income for 2012 would have been $199.8 million, or $4.15 per diluted share, a 2% increase over 2011 (see Non-GAAP Financial Measures below). Total revenues for 2012 were $1,315.1 million (43% oil and natural gas, 40% contract drilling, and 17% mid-stream), compared to $1,207.5 million (43% oil and natural gas, 40% contract drilling, and 17% mid-stream) for 2011.
OIL AND NATURAL GAS SEGMENT INFORMATION
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·
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During 2012, Unit’s oil and natural gas liquids (NGLs) reserves increased 9% and 59%, respectively.
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·
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Replaced 337% of 2012 production with new reserve additions.
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·
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Total production for 2012 was 14.2 MMBoe, an increase of 18% over 2011, and included an increase in oil and NGLs production of 28%.
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·
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Production guidance for 2013 is 16.0 to 16.5 MMBoe, an increase of 13% to 16% over 2012.
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The fourth quarter of 2012 marks the 12th consecutive quarter that liquids (oil and NGLs) production has increased. Unit’s strategy of drilling oil or NGLs rich wells is evident in its production results. Liquids production represented 41% of total equivalent production during the fourth quarter of 2012. Fourth quarter of 2012 total equivalent production increased 26% over the fourth quarter of 2011 to 4.1 MMBoe, while total liquids production for the fourth quarter of 2012 increased 25% over the comparable quarter of 2011. Liquids production for the fourth quarter of 2012 has increased 130% since the first quarter of 2009 when Unit began focusing almost entirely on increasing its liquids production. Fourth quarter 2012 oil production was 912,000 barrels, in comparison to 744,000 barrels for the same period of 2011, an increase of 23%. NGLs production during the fourth quarter of 2012 was 782,000 barrels, an increase of 27% when compared to 616,000 barrels for the same period of 2011. Fourth quarter 2012 natural gas production increased 28% to 14.5 billion cubic feet (Bcf) compared to 11.4 Bcf for the comparable quarter of 2011. Total production for all of 2012 was 14.2 MMBoe, an increase of 18% over the 12.1 MMBoe produced during 2011.
1
Unit’s average natural gas price for the fourth quarter of 2012 decreased 11% to $3.63 per thousand cubic feet (Mcf) as compared to $4.09 per Mcf for the fourth quarter of 2011. Unit’s average oil price for the fourth quarter of 2012 increased 4% to $91.67 per barrel compared to $88.06 per barrel for the fourth quarter of 2011. Unit’s average NGLs price for the fourth quarter of 2012 was $33.85 per barrel compared to $43.47 per barrel for the fourth quarter of 2011, a decrease of 22%. For 2012, Unit’s average natural gas price decreased 21% to $3.37 per Mcf as compared to $4.26 per Mcf for 2011. Unit’s average oil price for 2012 was $92.60 per barrel compared to $87.18 per barrel during 2011, a 6% increase. Unit’s average NGLs price for 2012 was $31.58 per barrel compared to $43.64 per barrel during 2011, a 28% decrease. All prices reflected in this paragraph include the effects of hedges.
For 2013, Unit has hedged 8,330 Bbls per day of its oil production and 100,000 MMBtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $97.94 per barrel. Of the natural gas production, 80,000 MMBtu per day is hedged with swaps and 20,000 MMBtu per day is hedged with a collar. The swap transactions were done at a comparable average NYMEX price of $3.65. The collar transaction was done at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.
The following table illustrates Unit’s production and certain results for the periods indicated:
| 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | |
| Oil and NGL Production, MBbl | 1,694.1 | 1,545.8 | 1,460.2 | 1,375.2 | 1,359.9 | 1,197.5 | 1,158.6 | 1,034.0 | 925.5 |
| Natural Gas Production, Bcf | 14.5 | 11.7 | 11.3 | 11.4 | 11.4 | 11.6 | 10.9 | 10.2 | 10.6 |
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Production, MBoe
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4,115 | 3,498 | 3,341 | 3,275 | 3,255 | 3,123 | 2,983 | 2,739 | 2,698 |
| Production, MBoe/day | 44.7 | 38.0 | 36.7 | 36.0 | 35.4 | 33.9 | 32.8 | 30.4 | 29.3 |
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Realized Price, Boe (1)
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$39.56 | $37.99 | $38.49 | $40.51 | $42.65 | $41.75 | $42.23 | $40.00 | $41.58 |
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
Unit recently acquired approximately 105,000 net acres located primarily in south central Kansas in the developing Mississippian play. Unit drilled its first horizontal well in Reno County, Kansas in the second quarter 2012 to a total measured depth of 8,115 feet including 3,850 feet of lateral. First production occurred in May 2012 with an average peak 30 day rate of 352 Boe per day consisting of 315 barrels of oil per day, 12 barrels of NGLs per day, and 150 Mcf of natural gas per day. The production components were approximately 89% oil, 3% NGLs, and 8% natural gas. Based on the production profile of this well, the reserve range estimate for a well in Unit’s Kansas Mississippian play would range somewhere between 125 MBoe to 180 MBoe. Using this estimated range and a completed well cost of $3.0 million along with flat pricing of $90 oil, $30 NGLs, and $3.25 natural gas, the typical Mississippian well would have a calculated rate of return (ROR) of approximately 30% to 66%. In addition to the initial well, Unit drilled three more horizontal Mississippian wells during 2012. Two of the wells had first sales in late December 2012, and the third is waiting on pipeline connection. In the first quarter of 2013, Unit plans to drill three additional wells before suspending drilling until pipeline infrastructure can be installed, which is scheduled for mid-year 2013. The estimated completion date for the pipeline is June 2013. Current plans are to move one Unit drilling rig back in the Mississippian play starting in July 2013 and possibly adding a second Unit drilling rig in September 2013. For 2013, Unit anticipates having first sales on approximately 13 gross wells and spending approximately $40 million for drilling and completion in its Mississippian play.
During 2012, Unit drilled 32 gross wells with an average working interest of 84% in its Marmaton horizontal oil play, located in Beaver County, Oklahoma. Thirty of the wells were short laterals with approximately 4,500 feet of lateral length and two of the wells were extended laterals with approximately 9,700 feet of lateral length. The net production from Unit’s Marmaton play for the fourth quarter of 2012 averaged 3,424 barrels of oil per day, 528 barrels of NGLs per day, and 1,775 Mcf of natural gas per day, an increase of 15% over the third quarter 2012 and a 61% year-over-year increase between 2012 and 2011. Included in the year-end reserve calculations are adjustments taken for wellbore communication that some of the wells have experienced. The company has adjusted its drilling program to address this issue. For 2013, Unit anticipates running a two drilling rig program in this play that should result in approximately 40 gross wells at an approximate net cost of $90 million. Due to current well spacing limitations associated with drilling extended lateral wells, the majority of 2013 wells are anticipated to be drilled as short lateral wells. Unit currently has leases on approximately 112,000 net acres in this play with about 44% of the leasehold held by production.
2
In its Granite Wash (GW) play located in the Texas Panhandle, Unit drilled and operated 29 gross horizontal wells during2012 with an average working interest of 87%. The net production from Unit’s GW play for the fourth quarter of 2012 averaged 1,822 barrels of oil per day, 4,988 barrels of NGLs per day and 46.2 MMcf of natural gas per day, or an equivalent rate of 87.0 MMcfe per day, an increase of 43% over the third quarter 2012 and a 41% year-over-year increase between 2012 and 2011. Unit expects to work four to six Unit drilling rigs drilling horizontal wells in both the newly acquired Noble leasehold and Unit’s existing leasehold in 2013, which equates to approximately 37 operated gross GW wells at an approximate net cost of $150 million. Unit currently owns leases on approximately 46,000 net acres with about 80% of the leasehold held by production.
In Unit’s Wilcox play, located primarily in Polk, Tyler, and Hardin Counties, Texas, Unit operated and completed 11 gross wells in 2012 with an average working interest of 88% and a success rate of 82%. Three of the 11 wells were completed in Unit’s “Gilly” Lower Wilcox field bringing the total number of wells completed in that field to five at year end 2012. Approximately 18% or 30 net Bcfe of the anticipated 168 net Bcfe (242 gross Bcfe) potential reserves are booked as proved producing or proved behind pipe at year end 2012. For 2013, Unit plans to run one Unit rig which should drill approximately 12 gross wells at an approximate net cost of $60 million. Seven of the 12 wells are planned to be drilled in the “Gilly” Lower Wilcox Field and the remaining five wells will be drilled on other Wilcox prospects.
On September 17, 2012, Unit closed its purchase of certain oil and natural gas assets from Noble Energy, Inc., with an effective date of April 1, 2012. The acquisition included various producing oil and gas properties and approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The adjusted purchase price was $592.6 million. The acquisition adds approximately 24,000 net acres to Unit’s Granite Wash core area in the Texas Panhandle with significant potential, including approximately 600 possible horizontal drilling locations. The total non-Granite Wash acreage acquired in the Texas Panhandle and western Oklahoma is approximately 59,000 net acres of which 95% is held by production and is characterized by high working interest and operatorship. Unit also received four gathering systems as part of the transaction and other miscellaneous assets.
Also in September 2012, Unit sold its interest in certain Bakken properties (representing approximately 35% of its total acreage in the Bakken play). The proceeds, net of related expenses were $226.6 million. In addition, Unit sold certain oil and natural gas assets in Brazos and Madison Counties, Texas for approximately $44.1 million.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results from our exploration operations, and we are excited about the acquisition from Noble and the growth opportunities that it provides. This acquisition more than doubled our acreage in our Granite Wash Texas Panhandle core area. It also provides us with additional inventory of drilling opportunities that will allow us to significantly grow our oil and liquids-rich gas production in the Anadarko Basin. Our recent divestiture of some non-core properties was a strategic move to enhance our overall liquidity for future growth opportunities. Unit’s annual production guidance for 2013 is approximately 16.0 to 16.5 MMBoe, an increase of 13% to 16% over 2012.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2012 was 64.0, a decrease of 22% from the fourth quarter of 2011, and a decrease of 13% from the third quarter of 2012. Per day drilling rig rates for the fourth quarter of 2012 averaged $19,828, an increase of 3%, or $498, from the fourth quarter of 2011, and a 1% decrease, or $161, from the third quarter of 2012. Average per day operating margin for the fourth quarter of 2012 was $7,838 (before elimination of intercompany drilling rig profit of $2.6 million). This compares to $9,037 (before elimination of intercompany drilling rig profit and bad debt expense of $4.9 million) for the fourth quarter of 2011, a decrease of 13%, or $1,199. As compared to the third quarter of 2012 ($9,672 before elimination of intercompany drilling rig profit of $4.0 million), fourth quarter 2012 operating margin decreased 19% or $1,834 (in each case regarding the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Approximately $1,007 per day of the third quarter 2012 average operating margin resulted from early termination fees resulting from the cancellation of certain long-term contracts.
For all of 2012, Unit averaged 73.9 drilling rigs working, a decrease of 3% from 76.1 drilling rigs working during 2011. Average per day operating margin for all of 2012 was $9,578 (before elimination of intercompany drilling rig profit of $15.6 million) as compared to $8,496 (before elimination of intercompany drilling rig profit and bad debt expense totaling $19.9 million) for 2011, an increase of 13% (in each case regarding the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Approximately $847 per day of the 2012 average operating margin resulted from early termination fees resulting from the cancellation of certain long-term contracts.
Larry Pinkston said: “Industry demand for drilling rigs softened throughout the year and more so during the latter part of the year as operators reduced their drilling efforts in order to stay within their 2012 budgets. Drilling activity should gradually improve as operators start with their new budgets for 2013, and as they get more comfortable with the outlook for NGLs prices. Approximately 99% of our drilling rigs working today are drilling for oil or NGLs. Currently, we have 127 drilling rigs in our fleet, of which 69 are
3
under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 29 of those 69 drilling rigs. Of these contracts, six are up for renewal during the first quarter of 2013, five during the second quarter of 2013, eight during the third quarter of 2013, two during the fourth quarter of 2013, and eight in 2014 and beyond.”
The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:
| 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | |
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Rigs
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127 | 127 | 128 | 127 | 127 | 126 | 123 | 122 | 121 |
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Utilization
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50% | 58% | 60% | 64% | 65% | 63% | 60% | 58% | 59% |
MID-STREAM SEGMENT INFORMATION
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·
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Increased fourth quarter of 2012 processed volumes per day and gathered volumes per day by 4% and 26%, respectively, over the fourth quarter of 2011.
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·
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A new gas gathering system and processing plant in Noble and Kay Counties, Oklahoma, known as the Bellmon system, is completed and operating. Extensions are underway to connect additional third party producers, and an additional capacity expansion is anticipated to be completed in the first quarter of 2013.
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Fourth quarter of 2012 per day processed volumes were 163,173 MMBtu while per day gathered volumes were 325,231 MMBtu, an increase of 4% and 26%, respectively, over the fourth quarter of 2011. Fourth quarter 2012 liquids sold volumes were 441,973 gallons per day, a decrease of 14% from the fourth quarter of 2011. Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter was $6.4 million, a decrease of 16% from the fourth quarter of 2011 and a decrease of 4% from the third quarter of 2012. The decrease from the fourth quarter 2011 was primarily due to lower liquids volumes recovered and lower prices. The decrease from the third quarter of 2012 was primarily due to lower liquids volumes recovered but somewhat offset by higher prices.
For 2012, processing volumes of 165,511 MMBtu per day, gathering volumes of 288,799 MMBtu per day, and liquids sold volumes of 542,578 gallons per day increased 43%, 34% and 32%, respectively, over 2011.
The following table illustrates certain results from this segment’s operations for the periods indicated:
| 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | |
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Gas gathered
MMBtu/day
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325,231 | 277,806 | 300,602 | 251,276 | 257,398 | 228,247 | 190,921 | 185,730 | 188,252 |
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Gas processed
MMBtu/day
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163,173 | 166,652 | 177,407 | 154,825 | 156,721 | 129,820 | 90,737 | 86,445 | 85,195 |
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Liquids sold
Gallons/day
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441,973 | 576,889 | 629,350 | 522,829 | 511,410 | 449,604 | 356,484 | 328,333 | 291,186 |
Larry Pinkston said: “During the second quarter of 2012, we completed the installation of our fifth processing plant at our Hemphill County, Texas facility. We now can process 160 MMcf per day of our own and third party Granite Wash natural gas production. Late in the second quarter, we completed and began operating our Bellmon system, a new gas gathering system and processing plant in Noble and Kay Counties in the Mississippian play of north central Oklahoma. This system consists of approximately 83 miles of pipe with a 20 MMcf per day gas processing plant. An additional 30 MMcf per day gas processing plant is scheduled to be installed at this facility in the first quarter of 2013. We have also connected our existing Remington gathering system to the new Bellmon system which required installing approximately 26 miles of pipeline and related compression services. Besides these projects, we also completed the installation of a natural gas liquids line from our Bellmon plant to Medford, Oklahoma. This project consists of approximately 20 miles of 6” pipe which was completed in the fourth quarter of 2012.”
“We are continuing to expand operations in the Appalachian region. Construction was completed on the first phase of our gathering facility in Allegheny and Butler counties, Pennsylvania, known as the Pittsburgh Mills system. The first phase of this project comprises approximately seven miles of gathering pipeline to which we have nine wells connected. The current gathered volume from these wells is approximately 28 MMcf per day. Construction activity to expand this gathering system continues as the producer is maintaining its drilling activity.”
4
FINANCIAL INFORMATION
Unit ended the year with long-term debt of $716.4 million, and a debt to capitalization ratio of 27%. On July 24, 2012, Unit completed a private offering to eligible purchasers of $400 million aggregate principal amount of senior subordinated notes due 2021, with an interest rate of 6.625% per year. The notes were sold at 98.75% of par plus accrued interest from May 15, 2012. Unit used the net proceeds to partially finance the acquisition from Noble. The notes have since been registered and exchanged and are now treated as a single series of debt securities with Unit's previously issued $250 million senior subordinated notes. Unit now has $645.3 million outstanding under its senior subordinated notes due 2021. Also with the acquisition, Unit increased commitments under its existing credit facility from $250 million ($600 million borrowing base) to $500 million ($800 million borrowing base).
MANAGEMENT COMMENT
Larry Pinkston said: “Weaker commodity prices created headwinds for all business segments in 2012. In spite of this, we experienced robust growth in reserves and production. The Noble acquisition will be an important growth step for Unit going forward. We plan to accelerate the drilling activity in the acquired properties and our other Granite Wash acreage over the next 12 to 18 months using up to six rigs from our contract drilling segment, and we plan to operate the acquired gathering systems and replace existing third party processing contracts beginning in 2015. We anticipate this acquisition will immediately be accretive to cash flow and to earnings beginning in 2013. We are optimistic about the outlook for 2013. We are well positioned, especially given the recent financing arrangements and property divestitures we have completed, to take advantage of growth opportunities that may arise for our business segments.”
WEBCAST
Unit will webcast its fourth quarter and year-end earnings conference call live over the Internet on February 19, 2013 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.
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 impact that the current decline in wells being drilled will have on production and drilling rig utilization, 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 exploration segment, development, operational, implementation and opportunity risks, possible delays caused by limited availability of third party services needed in its operations, 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.
5
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
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Three Months Ended
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Twelve Months Ended
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|||||||||||
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December 31,
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December 31,
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|||||||||||
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2012
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2011
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2012
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2011
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|||||||||
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Statement of Operations:
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Revenues:
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Contract drilling
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$
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108,521
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$
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142,553
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$
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529,719
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$
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484,651
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||||
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Oil and natural gas
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165,578
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141,371
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567,944
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514,614
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||||||||
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Gas gathering and processing
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57,483
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63,418
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217,460
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208,238
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||||||||
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Total revenues
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331,582
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347,342
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1,315,123
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1,207,503
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Expenses:
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Contract drilling:
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||||||||||||
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Operating costs
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65,544
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79,813
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289,524
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269,899
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||||||||
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Depreciation
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18,347
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22,334
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81,007
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79,667
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||||||||
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Oil and natural gas:
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||||||||||||
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Operating costs
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45,177
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37,475
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150,212
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131,271
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||||||||
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DD&A
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57,508 | 51,337 | 211,347 | 183,350 | ||||||||
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Impairment of oil and natural gas properties
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167,732
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---
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283,606
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---
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||||||||
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Gas gathering and processing:
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||||||||||||
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Operating costs
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51,049
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55,716
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187,292
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174,859
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||||||||
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Depreciation and amortization
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8,058 | 4,474 | 24,388 | 16,101 | ||||||||
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General and administrative
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9,272
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7,867
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33,086
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30,055
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||||||||
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Total operating expenses
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422,687
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259,016
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1,260,462
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885,202
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||||||||
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Income (Loss) from Operations
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(91,105
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) |
88,326
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54,661
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322,301
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|||||||
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Other Income (Expense):
|
||||||||||||
| Interest, net | (2,682 | ) | (2,089 | ) | (14,137 | ) | (4,167 | ) | ||||
| Gain (Loss) on Derivatives | 3,378 | (1,448 | ) | (1,243 | ) | 1,702 | ||||||
| Other | (1,039 | ) | (268 | ) | 121 | (834 | ) | |||||
| Total Other Income (Expense) | (343 | ) | (3,805 | ) | (15,259 | ) | (3,299 | ) | ||||
| Income (Loss) Before Income Taxes | (91,448 | ) | 84,521 | 39,402 | 319,002 | |||||||
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Income Tax Expense (Benefit):
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||||||||||||
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Current
|
246
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1,533
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|
696
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(2,416
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)
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|||||
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Deferred
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(35,147
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) |
31,327
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15,530
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125,551
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|||||||
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Total income taxes
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(34,901
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) |
32,860
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16,226
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123,135
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|||||||
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Net Income (Loss)
|
$
|
(56,547
|
) |
$
|
51,661
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$
|
23,176
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$
|
195,867
|
|||
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Net Income (Loss) per Common Share:
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||||||||||||
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Basic
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$
|
(1.18
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) |
$
|
1.08
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$
|
0.48
|
$
|
4.11
|
|||
|
Diluted
|
$
|
(1.18
|
) |
$
|
1.08
|
$
|
0.48
|
$
|
4.08
|
|||
|
Weighted Average Common
|
||||||||||||
|
Shares Outstanding:
|
||||||||||||
|
Basic
|
47,960
|
47,703
|
47,909
|
47,658
|
||||||||
|
Diluted
|
47,960
|
48,028
|
48,154
|
47,951
|
||||||||
6
|
December 31,
|
December 31,
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||||||||
|
2012
|
2011
|
||||||||
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Balance Sheet Data:
|
|||||||||
|
Current assets
|
$
|
195,644
|
$
|
228,465
|
|||||
|
Total assets
|
$
|
3,761,120
|
$
|
3,256,720
|
|||||
|
Current liabilities
|
$
|
207,139
|
$
|
212,750
|
|||||
|
Long-term debt
|
$
|
716,545
|
$
|
300,000
|
|||||
|
Other long-term liabilities
|
$
|
167,545
|
$
|
113,830
|
|||||
|
Deferred income taxes
|
$
|
695,776
|
$
|
683,123
|
|||||
|
Shareholders’ equity
|
$
|
1,974,301
|
$
|
1,947,017
|
|||||
|
Twelve Months Ended December 31,
|
|||||||||
|
2012
|
2011
|
||||||||
|
Statement of Cash Flows Data:
|
|||||||||
|
Cash Flow From Operations before Changes
|
|||||||||
|
in Operating Assets and Liabilities (1)
|
$
|
664,765
|
$
|
618,746
|
|||||
|
Net Change in Operating Assets and Liabilities
|
(308
|
)
|
(10,291
|
)
|
|||||
|
Net Cash Provided by Operating Activities
|
$
|
664,457
|
$
|
608,455
|
|||||
|
Net Cash Used in Investing Activities
|
$
|
(1,079,042
|
)
|
$
|
(768,236
|
)
|
|||
|
Net Cash Provided by
Financing Activities
|
$
|
414,724
|
$
|
159,257
|
|||||
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||
|
December 31,
|
December 31,
|
|||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||
|
Contract Drilling Operations Data:
|
||||||||||||
|
Rigs Utilized
|
64.0
|
82.1
|
73.9
|
76.1
|
||||||||
|
Operating Margins (2)
|
40%
|
44%
|
45%
|
44%
|
||||||||
|
Operating Profit Before Depreciation (2) ($MM)
|
$
|
43.0
|
$
|
62.7
|
$
|
240.2
|
$
|
214.8
|
||||
|
Oil and Natural Gas Operations Data:
|
||||||||||||
|
Production:
|
||||||||||||
|
Oil – MBbls
|
912
|
744
|
3,279
|
2,511
|
||||||||
|
Natural Gas Liquids - MBbls
|
782
|
616
|
2,796
|
2,239
|
||||||||
|
Natural Gas - MMcf
|
14,527
|
11,374
|
48,930
|
44,104
|
||||||||
|
Average Prices:
|
||||||||||||
|
Oil price per barrel received
Oil price per barrel received, excluding hedges
|
$
$
|
91.67
85.67
|
$
$
|
88.06
92.88
|
$
$
|
92.60
90.19
|
$
$
|
87.18
93.49
|
||||
|
NGLs price per barrel received
NGLs price per barrel received,
excluding hedges
|
$
$
|
33.85
33.39
|
$
$
|
43.47
43.85
|
$
$
|
31.58
30.70
|
$
$
|
43.64
44.44
|
||||
|
Natural Gas price per Mcf received
Natural Gas price per Mcf received,
excluding hedges
|
$
$
|
3.63
3.09
|
$
$
|
4.09
3.29
|
$
$
|
3.37
2.53
|
$
$
|
4.26
3.78
|
||||
|
Operating Profit Before DD&A (2) ($MM)
|
$
|
120.4
|
$
|
103.9
|
$
|
417.7
|
$
|
383.3
|
||||
|
Mid-Stream Operations Data:
|
||||||||||||
|
Gas Gathering - MMBtu/day
|
325,231
|
257,398
|
288,799
|
215,805
|
||||||||
|
Gas Processing - MMBtu/day
|
163,173
|
156,721
|
165,511
|
116,161
|
||||||||
|
Liquids Sold – Gallons/day
|
441,973
|
511,410
|
542,578
|
412,064
|
||||||||
|
Operating Profit Before Depreciation
|
||||||||||||
|
and Amortization (2) ($MM)
|
$
|
6.4
|
$
|
7.7
|
$
|
30.2
|
$
|
33.4
|
||||
_____________
(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 interest expense. Operating margins are calculated by dividing operating profit by segment revenue.
7
Non-GAAP Financial Measures
We report our financial results in accordance with generally accepted accounting principles (“GAAP”). We believe certain non-GAAP performance measures provide users of our financial information and our management additional meaningful information to evaluate the performance of our company.
This press release includes net income excluding the effect of the impairment of our oil and natural gas properties, diluted earnings per share excluding the effect of the impairment of our oil and natural gas properties, cash flow from operations before changes in operating assets and liabilities and our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twleve months ended December 31, 2012 and 2011. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.
Unit Corporation
Reconciliation of Net Income (Loss) and Diluted Earnings per Share
Excluding the Effect of Impairment of Oil and Natural Gas Properties
|
Three Months Ended
|
Twelve Months Ended
|
||||||||||||||
|
December 31,
|
December 31,
|
||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
||||||||||||
|
(In thousands)
|
|||||||||||||||
|
Net income (loss) excluding impairment of oil and
|
|||||||||||||||
|
natural gas properties:
|
|||||||||||||||
|
Net income (loss)
|
$
|
(56,547
|
)
|
$
|
51,661
|
$
|
23,176
|
$
|
195,867
|
||||||
|
Add:
|
|||||||||||||||
|
Impairment of oil and natural gas properties
|
|||||||||||||||
|
(net of income tax)
|
104,450
|
---
|
176,582
|
---
|
|||||||||||
|
Net income excluding impairment of oil and
|
|||||||||||||||
|
natural gas properties
|
$
|
47,903
|
$
|
51,661
|
$
|
199,758
|
$
|
195,867
|
|||||||
|
Diluted earnings (loss) per share excluding
|
|||||||||||||||
|
impairment of oil and natural gas properties:
|
|||||||||||||||
|
Diluted earnings (loss) per share
Add:
Diluted earnings per share from impairment
|
$
|
(1.18
|
)
|
$
|
1.08
|
$
|
0.48
|
$
|
4.08
|
||||||
|
of oil and natural gas properties
|
2.17
|
---
|
3.67
|
---
|
|||||||||||
|
Diluted earnings per share excluding
|
|||||||||||||||
|
impairment of oil and natural gas properties
|
$
|
0.99
|
$
|
1.08
|
$
|
4.15
|
$
|
4.08
|
|||||||
We have included the net income excluding impairment of oil and natural gas properties and diluted earnings per share excluding impairment of oil and natural gas properties because:
|
·
|
We use 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.
|
|
·
|
The impairment of oil and natural gas properties does not occur on a recurring basis and the amount and timing of impairments cannot be reasonably estimated for budgeting purposes and is therefore typically not included for forecasting operating results.
|
8
Non-GAAP Financial Measures (continued)
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
|
Twelve Months Ended
December 31,
|
|||||||||
|
2012
|
2011
|
||||||||
|
(In thousands)
|
|||||||||
|
Net cash provided by operating activities
|
$
|
664,457
|
$
|
608,455
|
|||||
|
Subtract:
|
|||||||||
|
Net change in operating assets and liabilities
|
308
|
10,291
|
|||||||
|
Cash flow from operations before changes
|
|||||||||
|
in operating assets and liabilities
|
$
|
664,765
|
$
|
618,746
|
|||||
________________
We have included the cash flow from operations before changes in operating assets and liabilities because:
|
·
|
It is an accepted financial indicator used by our management and companies in our industry to measure the company’s ability to generate cash which is used to internally fund our business activities.
|
|
·
|
It is used by investors and financial analysts to evaluate the performance of our company.
|
Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of
Intercompany Rig Profit and Bad Debt Expense
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
September 30,
|
December 31,
|
December 31,
|
||||||||||||||
|
2012
|
2012
|
2011
|
2012
|
2011
|
||||||||||||
|
(In thousands except operating days and daily operating margins)
|
||||||||||||||||
|
Contract drilling revenue
|
$
|
133,420
|
$
|
108,521
|
$
|
142,553
|
$
|
529,719
|
$
|
484,651
|
||||||
|
Contract drilling operating cost
|
72,988
|
65,544
|
79,813
|
289,524
|
269,899
|
|||||||||||
|
Operating profit from contract drilling
|
60,432
|
42,977
|
62,740
|
240,195
|
214,752
|
|||||||||||
|
Add:
Elimination of intercompany rig profit
and bad debt expense
|
3,983
|
2,647
|
4,945
|
15,583
|
19,900
|
|||||||||||
|
Operating profit from contract drilling
|
||||||||||||||||
|
before elimination of intercompany
|
||||||||||||||||
|
rig profit
|
64,415
|
45,624
|
67,685
|
255,778
|
234,652
|
|||||||||||
|
Contract drilling operating days
|
6,660
|
5,821
|
7,490
|
26,704
|
27,619
|
|||||||||||
|
Average daily operating margin before
|
||||||||||||||||
|
elimination of intercompany rig profit
and bad debt expense
|
$
|
9,672
|
$
|
7,838
|
$
|
9,037
|
$
|
9,578
|
$
|
8,496
|
||||||
________________
We have included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
|
·
|
Our management uses the measurement to evaluate the cash flow performance of our 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 our company.
|
9