Please read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and related notes included in Item 8 of this report.

General

We operate, manage, and analyze our results of operations through our three principal business segments:
• Contract Drilling - carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.

• Oil and Natural Gas - carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.

• Mid-Stream - carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.

Business Outlook

As discussed in other parts of this report, the success of our consolidated business, as well as that of each of our three operating segments depends, to a large extent, on: the prices we receive for our oil, NGLs, and natural gas production; the demand for oil, NGLs, and natural gas; and the demand for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. Although all of our current operations (with the exception of a minor amount of production in Canada) are located within the United States, events outside the United States can and do have an impact on us and our industry.

In addition to their direct impact on us, low commodity prices-if sustained for a long period of time-could impact the liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial obligations to us.

Our 2013 current capital budget for all of our business segments forecasts a 6% increase over our 2012 capital expenditures, excluding acquisitions. Our oil and natural gas segment's capital budget is $586.0 million, a 16% increase over 2012, excluding acquisitions and ARO liability. We plan to continue our aggressive drilling program into 2013 with a significant portion of the wells being horizontal. Our drilling segment's capital budget is $98.0 million, a 26% increase over 2012. Our plans for 2013 include continuing to refurbish and upgrade several of our existing drilling rigs in order that those drilling rigs can be used in horizontal drilling operations. Our mid-stream segment's capital budget is $105.0 million, a 36% decrease from 2012, excluding acquisitions. New and continued projects are discussed further in the Executive Summary.

Our 2013 current capital expenditures budget is based on realized prices for the year of $93.05 per barrel of oil, $32.05 per barrel of NGLs, and $3.56 per Mcf. This budget is subject to possible periodic adjustments for various reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from internally generated cash flow and, if necessary, borrowings under our credit agreement.

Executive Summary

Contract Drilling

The rate at which our drilling rigs were used ("our utilization rate") for the fourth quarter 2012 was 50%, compared to 58% and 65% for the third quarter of 2012 and the fourth quarter of 2011, respectively.

Dayrates for the fourth quarter of 2012 averaged $19,828, a 1% decrease from the third quarter of 2012 and an increase of 3% over the fourth quarter of 2011. The decrease from the third quarter of 2012 is due primarily to the terminated contracts having higher rates (drilling rigs that were under long-term contracts, but were terminated early by the operator). The increase over the fourth quarter of 2011 was due primarily to new drilling rigs going into service for which we received a higher rate, increased demand for drilling rigs in the 1,000 horsepower range which increased their rates somewhat offset by the decrease in higher dayrates associated with the terminated contracts.

Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2012 decreased 29% from the third quarter of 2012 and 32% from the fourth quarter of 2011. For both comparative periods utilization decreased. Additionally, during the fourth quarter of 2012, we received $0.1 million in termination fees compared to $6.7 million received in the third quarter of 2012 for three drilling rigs that were under long-term contracts but were terminated early by the operator.

Operating cost per day for the fourth quarter of 2012 increased 3% over the third quarter of 2012 and 6% over the fourth quarter of 2011. The increases over the third quarter were primarily due to increases in drilling rig servicing and workers' compensation costs while the increases over the fourth quarter of 2011 are primarily due to increases in direct expenses due to wage increases for rig personnel and to a lesser extent from higher worker's compensation and indirect costs.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. However, with the current weakened natural gas market, operators are now focusing on drilling for oil and NGLs. Today, approximately 99% of our working drilling rigs are drilling for oil or NGLs. Of those, approximately 97% are drilling horizontal or directional wells.

During 2011, we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. One was placed into service during the fourth quarter of 2011 and the other was placed in service during the first quarter of 2012, both in Wyoming.
During the first quarter of 2012, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third-party. Additionally, during the second quarter of 2012, we placed another new 1,500 horsepower, diesel-electric drilling rig in North Dakota (under a three year contract).
During the third quarter of 2012, we had a fire on one of our drilling rigs in the mid-continent region. The net book value of the damaged equipment on the rig was $3.2 million. We expect that all of the net book value of the damaged equipment will be recoverable from insurance proceeds. As a result of this loss, this segment now has 127 drilling rigs in its fleet. No personnel were injured in this incident.

Our anticipated 2013 capital expenditures for this segment are $98.0 million, a 26% increase over 2012.

As of December 31, 2012, we had 27 term drilling contracts with original terms ranging from six months to three years. Twenty-one of these contracts are up for renewal in 2013, six in the first quarter, five in the second quarter, eight in the third quarter and two in the fourth quarter and six are up for renewal in 2014 and later. Term contracts may contain a fixed rate for the duration of the contract or provide for rate adjustments within a specific range from the existing rate.

Oil and Natural Gas

Fourth quarter 2012 production from our oil and natural gas segment was 4,115,000 barrels of oil equivalent (Boe), an 18% increase over the third quarter of 2012 and a 26% increase over the fourth quarter of 2011. These increases came primarily from production associated with the Noble acquisition and, to a lesser extent, from new wells completed in oil and NGLs rich prospects. Oil and NGLs production during 2012 was 43% of our total production compared to 39% of our total production during 2011.

Fourth quarter 2012 oil and natural gas revenues increased 22% over the third quarter of 2012 and increased 17% over the fourth quarter of 2011. These increases were primarily due to increases in production and commodity prices.

Our NGLs, natural gas, and oil prices for the fourth quarter of 2012 increased 59%, 7%, and 1%, respectively, over the third quarter of 2012. Our oil prices increased 4% over the fourth quarter of 2011 while natural gas and NGLs prices decreased 11% and 22%, respectively.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 21% over the third quarter of 2012 and 16% over the fourth quarter of 2011. The increases were primarily attributable to increased production from developmental drilling and acquisitions, as well as increases in commodity prices over the third quarter of 2012.

Operating cost per Boe produced for the fourth quarter of 2012 increased 6% over the third quarter of 2012 and decreased 5% from the fourth quarter of 2011. The costs increased over the third quarter of 2012 due to increased gross production taxes and increases in lease operating expenses (LOE) due to increased workover expense and higher saltwater disposal fees. The decrease from the fourth quarter 2011 was primarily due to a decrease in well servicing and transportation charges and a decrease in production taxes due to tax credits applied to the 2012 rate.

For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at June 30, 2012, consisted of swaps and collars, covering production of 0.0 MMBoe in 2012 and 0.0 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties.

For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly resulting in a non-cash ceiling test write down of $167.7 million pre-tax ($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012, consisted of swaps and collars covering 0.0 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural gas hedging is discussed in Note 13 of the Notes to our Consolidated Financial Statements.

If there are further declines in the 12-month average prices, including the discounted value of our commodity hedges, we may be required to record a write-down in future periods.

For 2012 we hedged approximately 68% of our average daily oil production and approximately 37% of our average natural gas production to help manage our cash flow and capital expenditure requirements.

Currently for 2013 we have hedged approximately 8,330 Bbls per day of 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. The natural gas production is hedged by swaps for 80,000 Mmbtu per day and a collar for 20,000 Mmbtu per day. 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.

Currently for 2014 we have hedged 4,000 Bbls per day of oil production. The oil production is hedged by swaps for 2,000 Bbls per day and collars for 2,000 Bbls per day. The swap transactions were done at an average price of $91.40 per barrel. The collar transactions were done at an average floor price of $90.00 per barrel and ceiling price of $95.00 per barrel.

On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble. After final closing adjustments, the acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6 million.

As of April 1, 2012, the effective date of the Noble acquisition, the estimated proved reserves of the acquired properties were 44 MMBoe, The acquisition added approximately 24,000 net leasehold acres to our Granite Wash core area in the Texas Panhandle with significant potential including approximately 600 possible future horizontal drilling locations. The total acreage acquired in other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres and was characterized by high working interest and operatorship, 95% of which was held by production. We also received four gathering systems as part of the transaction and other miscellaneous assets.

Also in September 2012, we sold our interest in certain Bakken properties (representing approximately 35% of our total acreage in the Bakken play). The proceeds, net of related expenses were $226.6 million. In addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas for approximately $44.1 million. Both dispositions were accounted for as adjustments to the full cost pool with no gain or loss recognized.

During 2012, we drilled 171 wells (80.08 net wells). Our 2013 production guidance is approximately 16.0 to 16.5 MMBoe, an increase of 13% to 16% over 2012, although actual results will continue to be subject to many factors. For 2013, we plan to participate in the drilling of 180 wells. Our oil and natural gas segment's capital budget is $586.0 million, a 16% increase over 2012, excluding acquisitions and ARO liability.

Mid-Stream

Fourth quarter 2012 liquids sold per day decreased 23% from the third quarter of 2012 and decreased 14% from the fourth quarter of 2011. During the third quarter 2012, one of our customers completed construction of their own processing plant and moved their volumes off our system resulting in decreases in liquids sold, gas gathered, and gas processed. In addition, during the fourth quarter of 2012, certain processing plants were rejecting ethane due to weak ethane prices. For the fourth quarter of 2012, gas processed per day decreased 2% from the third quarter of 2012 and increased 4% over the fourth quarter of 2011. In 2011 and 2012, we upgraded several of our existing processing facilities and added processing plants which was the primary reason for increased volumes. In 2012, these increases were offset by the decrease of one of our customers discussed above. For the fourth quarter of 2012, gas gathered per day increased 17% over the third quarter of 2012 and increased 26% over the fourth quarter of 2011 primarily from well connects throughout 2012.

NGLs prices in the fourth quarter of 2012 increased 31% over the prices received in the third quarter of 2012 and decreased 11% from the prices received in the fourth quarter of 2011. Because certain of the contracts used by our mid-stream segment for NGLs transactions are percent of proceeds (POP) contracts -- under which we receive a share of the proceeds from the sale of the NGLs--our revenues from those POP contracts fluctuate based on the prices of NGLs.

Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2012 decreased 4% from the third quarter of 2012 and decreased 16% from the fourth quarter of 2011. The decreases were primarily due to decreases in NGLs volumes from the comparative periods. This was slightly offset by an increase in NGLs prices from the third quarter of 2012. Total operating cost for our mid-stream segment for the fourth quarter of 2012 increased 10% over the third quarter of 2012 and decreased 8% from the fourth quarter of 2011 due primarily to the increase and decrease in gas purchased in the respective period.

During the second quarter of 2012, we completed the installation of our fifth processing plant at our Hemphill County, Texas facility. We now have the capacity at that facility to process 160 MMcf per day of our own and third-party Granite Wash natural gas production.

At our Cashion facility, we have extended our gathering system to the north to connect wells that are being drilled in that area. Due to this increased activity, we installed a new 25 MMcf per day high efficiency turbo-expander processing plant at this facility that became operational in March 2012. With the installation of this additional plant, our total processing capacity increased to approximately 45 MMcf per day at our Cashion facility.

In the Mississippian play in north central Oklahoma, a new gas gathering system and processing plant in Noble and Kay Counties, Oklahoma, known as the Bellmon system, was completed and began operating late in the second quarter. This system currently consists of approximately 83 miles of pipelines with a 20 MMcf per day gas processing plant. An additional 30 MMcf per day gas processing plant is scheduled to be installed in the first quarter of 2013. We also connected our existing Remington system to the new Bellmon system which required laying approximately 26 miles of pipeline and installing related compression services. In addition to these projects, we completed the installation of a NGLs line from our Bellmon plant to Medford, Oklahoma. This project consists of approximately 20 miles of 6" pipeline and was completed in the 4th quarter of 2012.

We are continuing to expand operations in the Appalachian region. In the fourth quarter of 2012, construction was completed on the first phase of our Pittsburgh Mills gathering facility in Allegheny and Butler Counties, Pennsylvania. The first phase of this project consists of approximately seven miles of gathering pipeline. In the first quarter of 2013, the related compressor station will be completed. We currently have 10 wells connected to this gathering system. The current gathered volumes from these wells is approximately 28 MMcf per day. Construction activity for expansion of this pipeline continues as the producer is maintaining its drilling activity.

In December 2012, we had a $1.2 million write-down of our Erick system. There was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from this location and there is no future activity anticipated from this gathering system.

Our anticipated 2013 capital expenditures for this segment are $105.0 million, a 36% decrease from 2012, excluding acquisitions.

Critical Accounting Policies and Estimates

Summary

In this section, we identify those critical accounting policies we follow in preparing our financial statements and related disclosures. Many of these policies require us to make difficult, subjective, and complex judgments in the course of making estimates of matters that are inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In the following discussion we will attempt to explain the nature of these estimates, assumptions and judgments, as well as the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.

The following table lists the critical accounting policies, estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.

Accounting Policies          Estimates or Assumptions        Accounts Affected
Full cost method of         •  Oil, NGLs, and natural    •  Oil and natural gas
accounting for oil, NGLs,   gas reserves, estimates      properties
and natural gas             and related present value    •  Accumulated depletion,
properties                  of future net revenues       depreciation and
                            •  Valuation of unproved     amortization
                            properties                   •  Provision for
                            • Estimates of future        depletion, depreciation
                            development costs            and amortization
                            • Derivatives measured at    •  Impairment of oil and
                            fair value                   natural gas properties
                                                         •  Long-term debt and
                                                         interest expense

Accounting for ARO for      •  Cost estimates related    •  Oil and natural gas
oil, NGLs, and natural      to the plugging and          properties
gas properties              abandonment of wells         •  Accumulated depletion,
                            •  Timing of cost incurred   depreciation and
                                                         amortization
                                                         •  Provision for
                                                         depletion, depreciation
                                                         and amortization
                                                         •  Current and non-current
                                                         liabilities
                                                         •  Operating expense

Accounting for impairment   •  Forecast of               •  Drilling and mid-stream
of long-lived assets        undiscounted estimated       property and equipment
                            future net operating cash    •  Accumulated depletion,
                            flows                        depreciation and
                                                         amortization
                                                         •  Provision for
                                                         depletion, depreciation
                                                         and amortization
                                                         •  Other intangible assets

Goodwill                    •  Forecast of discounted    •  Goodwill
                            estimated future net
                            operating cash flows
                            •  Terminal value
                            •  Weighted average cost
                            of capital

Turnkey and footage         •  Estimates of costs to     •  Revenue and operating
drilling contracts          complete turnkey and         expense
                            footage contracts            •  Current assets and
                                                         liabilities

Accounting for value of     •  Estimates of stock        •  Oil and natural gas
stock compensation awards   volatility                   properties
                            •  Estimates of expected     •  Shareholder's equity
                            life of awards granted       •  Operating expenses
                            •  Estimates of rates of     •  General and
                            forfeitures                  administrative expenses

Accounting for derivative   •  Hedges measured for       •  Current and non-current
instruments and hedging     effectiveness and            derivative assets and
                            ineffectiveness              liabilities
                            •  Non-qualifying and        •  Other comprehensive
                            qualifying derivatives       income as a component of
                            measured at fair value       equity
                                                         •  Oil and natural gas
                                                         revenue
                                                         •  Gain (loss) on
                                                         derivatives not designated
                                                         as hedges and hedge
                                                         ineffectiveness, net

Significant Estimates and Assumptions

Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. The determination of our oil, NGLs, and natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner. The degree of accuracy of these estimates depends on a number of factors, including,

the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. The wells or locations for which estimates of reserves were audited were those that comprised the top 82% of the total proved developed discounted future net income and 87% of the total proved undeveloped discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by us as of December 31, 2012. Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and our personnel responsible for the preparation of our reserve reports.

As a general rule, the degree of accuracy of oil, NGLs, and natural gas reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table:

Type of Reserves        Nature of Available Data                    Degree of Accuracy

Proved undeveloped      Data from offsetting wells, seismic data    Less accurate

Proved developed        The above as well as logs, core samples,
non-producing           well tests, pressure data                   More accurate

Proved developed        The above as well as production history,
producing               pressure data over time                     Most accurate

Assumptions as to future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in estimating oil, NGLs, and natural gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves is greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Companies using full cost accounting use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.

We compute our provision for DD&A on a units-of-production method. Each quarter, . . .