Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2 Item 2.
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2 Item 3.
Item 3. Legal Proceedings - ------- -----------------
We are a party to various legal proceedings arising in the ordinary course of our business, none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders - ------- ---------------------------------------------------
No matters were submitted to our security holders during the fourth quarter of 2004.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity, Related Stockholder - ------- ----------------------------------------------------------------- Matters and Issuer Purchases of Equity Securities -------------------------------------------------
Our common stock trades on the New York Stock Exchange under the symbol "UNT." The following table identifies the high and low sales prices per share of our common stock for the periods indicated:
2002 2003 ------------------------- ------------------------- QUARTER High Low High Low ------- ----------- ----------- ----------- ----------- First $ 18.60 $ 10.24 $ 21.99 $ 16.30 Second $ 20.93 $ 16.01 $ 23.39 $ 19.14 Third $ 19.25 $ 13.65 $ 22.60 $ 18.68 Fourth $ 20.44 $ 16.71 $ 24.51 $ 18.40
On March 1, 2004 there were 1,763 record holders of our common stock.
We have never paid cash dividends on our common stock and currently intend to continue our policy of retaining earnings from our operations. Our loan agreement prohibits us from declaring and paying dividends (other than stock dividends) in any fiscal year in an amount greater than 25% of our preceding year's consolidated net income.
Item 6.
Item 6. Selected Financial Data - ------- -----------------------
Year Ended December 31, ---------------------------------------------------------- 1999 (1) 2000 2001 2002 2003 ---------- ---------- ---------- ---------- ---------- (In thousands except per share amounts)
Revenues $ 102,352 $ 201,264 $ 259,179 $ 187,636 $ 302,584 ========== ========== ========== ========== ========== Income Before Change in Accounting Principle $ 3,048 $ 34,344 $ 62,766 $ 18,244 $ 48,864 ========== ========== ========== ========== ========== Net Income $ 3,048 $ 34,344 $ 62,766 $ 18,244 $ 50,189 ========== ========== ========== ========== ========== Income Before Change in Accounting Principle per Common Share:
Basic $ 0.10 $ 0.96 $ 1.75 $ 0.47 $ 1.12 ========== ========== ========== ========== ========== Diluted $ 0.10 $ 0.95 $ 1.73 $ 0.47 $ 1.12 ========== ========== ========== ========== ========== Net Income per Common Share: Basic $ 0.10 $ 0.96 $ 1.75 $ 0.47 $ 1.15 ========== ========== ========== ========== ========== Diluted $ 0.10 $ 0.95 $ 1.73 $ 0.47 $ 1.15 ========== ========== ========== ========== ==========
Total Assets $ 295,567 $ 346,288 $ 417,253 $ 578,163 $ 712,925 ========== ========== ========== ========== ========== Long-Term Debt $ 67,239 $ 54,000 $ 31,000 $ 30,500 $ 400 ========== ========== ========== ========== ========== Other Long-Term Liabilities $ 2,325 $ 3,597 $ 4,110 $ 5,439 $ 17,893 ========== ========== ========== ========== ========== Cash Dividends Per Common Share $ -- $ -- $ -- $ -- $ -- ========== ========== ========== ========== ========== - ---------------------- (1) Restated for the merger with Questa Oil and Gas Co.
See Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and - ------- --------------------------------------------------------------- Results of Operations ---------------------
FINANCIAL CONDITION AND LIQUIDITY - ---------------------------------
Summary. Our financial condition and liquidity depends on the cash flow from our two principal subsidiaries and borrowings under our bank loan agreement. Our cash flow is influenced mainly by the prices we receive for our natural gas production, the demand for and the dayrates we receive for our drilling rigs and, to a lesser extent, the prices we receive for our oil production. At December 31, 2003, we had cash totaling $598,000 and we had borrowed $400,000 under our loan agreement.
Over the last six months of 2003 the average monthly natural gas price we received excluding the impact of hedging, ranged from $4.06 in October to $5.06 in December and the average Nymex Henry Hub daily price for the same time period ranged from $4.79 to $7.00. With the average Nymex contract settle price for the next twelve months at $5.40 on February 18, 2004, we expect natural gas prices to remain at levels that will increase demand for our rigs and provide upward movement on the rates we receive for our contract drilling services. There is, however, no assurance that these prices will actually be sustained throughout 2004.
The following is a summary of certain financial information as of December 31, 2003 and for the year ended December 31, 2003:
Working Capital . . . . . . . $ 20,931,000 Long-Term Debt. . . . . . . . $ 400,000 Shareholders' Equity. . . . . $ 515,768,000 Ratio of Long-Term Debt to Total Capitalization. . . . --% Net Income. . . . . . . . . . $ 50,189,000 Net Cash Provided by Operating Activities. . . . $ 121,712,000
The following table summarizes certain operating information for the years ended December 31, 2002 and 2003:
Percent 2002 2003 Change ------------ ------------ -------- Oil Production (Bbls) . . . 473,000 516,000 9% Natural Gas Production (Mcf) 18,968,000 20,648,000 9% Average Oil Price Received. $ 21.54 $ 26.94 25% Average Natural Gas Price Received. . . . . . . . . $ 2.87 $ 4.87 70% Average Number of Our Drilling Rigs in Use During the Period . . . . 39.1 62.9 61%
In December 2003, we acquired SerDrilco Incorporated for $35.0 million in cash. To finance the acquisition we sold 2.0 million shares of common stock for net proceeds of $42.1 million.
Our Bank Loan Agreement. At December 31, 2003, we had a $100 million bank loan agreement consisting of a revolving credit facility through May 1, 2005 and a term loan thereafter, maturing on May 1, 2008. On January 30, 2004, in conjunction with our acquisition of PetroCorp Incorporated, we replaced our loan agreement with a revolving credit facility totaling $150 million having a four year term ending January 30, 2008. Borrowings under the new credit facility are limited to a commitment amount. Although the current value of our assets under the latest loan value computation supported the full $150 million, we elected to set the loan commitment at $120 million in order to reduce financing costs since we are charged a commitment fee of .375 of 1% on the amount available but not borrowed. We paid origination, agency and syndication fees of $515,000 at the inception of the new agreement, $40,000 of which will be paid annually and the remainder of the fees amortized over the four year life of the loan. Following the acquisition of PetroCorp Incorporated our borrowings were $90.0 million on February 18, 2004.
The loan value under our current credit facility is subject to a semi-annual re-determination on May 10 and November 10 of each year, beginning May 10, 2004. The calculation is based primarily on the sum of a percentage of the discounted future value of our oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of our drilling rig fleet, limited to $20 million, is added to the loan value. Provisions are also in the agreement which allow for one requested special re-determination of the borrowing base by either the lender or us between each scheduled re-determination date if conditions warrant such a request.
At our election, any portion of the debt outstanding may be fixed at a Eurodollar Rate for 30, 60, 90 or 180 day terms. During any Eurodollar Rate funding period the outstanding principal balance of the note to which such Eurodollar Rate option applies may be repaid upon three days prior notice to the Administrative Agent. Interest on the Eurodollar Rate is computed at the Eurodollar Base Rate applicable for the interest period
plus 1.00% to 1.50% depending on the level of debt as a percentage of the total loan value and is payable at the end of each term or every 90 days whichever is less. Borrowings not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty. At February 18, 2004, all of our $90.0 million debt was subject to the Eurodollar Rate.
The loan agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year, . the incurrence of additional debt with certain very limited exceptions and . the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our property, except in favor of our banks.
The loan agreement also requires that at the end of each quarter:
. consolidated net worth of at least $350 million, . a current ratio (as defined in the loan agreement) of not less than 1 to 1 and . a leverage ratio of long-term debt to consolidated EBITDA (as defined in the loan agreement) for the most recently ended rolling four fiscal quarters of no greater than 3.25 to 1.0.
Hedging. Periodically we hedge the prices we will receive for a portion of our future natural gas and oil production. We do so in an attempt to reduce the impact and uncertainty that price variations have on our cash flow. We entered into a collar contract covering approximately 25% of our daily oil production for January and February of 2001. The collar had a floor of $26.00 per barrel and a ceiling of $33.00 per barrel and we received $0.86 per barrel for entering into the transaction. During the first quarter of 2001, our oil hedging transaction yielded an increase in our oil revenues of $17,200.
During the second quarter of 2001, we entered into a natural gas collar contract for approximately 36% of our June and July 2001 production, at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter of 2001, we entered into two natural gas collar contracts for approximately 38% of our September through November 2001 natural gas production. Both contracts had a floor price of $2.50. One contract had a ceiling of $3.68 and the other contract had a ceiling of $4.25. During the year of 2001, the collar contracts increased natural gas revenues by $2,030,000.
On April 30, 2002, we entered into a collar contract covering approximately 19% of our natural gas production for the periods of April 1, 2002 through October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During the year of 2002, our natural gas hedging transactions increased natural gas revenues by $40,300. We did not have any hedging transactions outstanding at December 31, 2002.
During the first quarter of 2003, we entered into two collar contracts covering approximately 40% of our natural gas production for the periods of April 1, 2003 through September 30, 2003. One collar had a floor of $4.00 and a ceiling of $5.75 and the other collar had a floor of $4.50 and a ceiling of $6.02. We also entered into two collar contracts covering approximately 25% of our oil production for the periods of May 1, 2003 through December 31, 2003. One collar had a floor of $25.00 and a ceiling of $32.20 and the other collar had a floor of $26.00 and a ceiling of $31.40. During the year of 2003, the collar contracts decreased natural gas revenues by $6,000 and oil revenues by $5,000. We did not have any hedging transactions outstanding at December 31, 2003.
In January 2004, we entered into a natural gas collar covering approximately 14% of our estimated natural gas production. The transaction covers the periods of April through October of 2004 and has a floor of $4.50 and a ceiling of $6.76. We also entered into an oil hedge covering approximately 40% of our estimated oil production. The transaction covers the periods of February through December of 2004 and has an average price of $31.40.
Self-Insurance. We are self-insured for certain losses relating to workers' compensation, general liability, property damage and employee medical benefits. The exposure (i.e. our deductible or retention) per occurrence ranges from $200,000 for general liability to $1 million for rig physical damage. We have purchased stop-loss coverage in order to limit, to the extent feasible, our per occurrence and aggregate exposure to certain claims. There is no assurance that such coverage will adequately protect us against liability from all potential consequences. Following the acquisition of SerDrilco we have continued to use its ERISA governed occupational injury benefit plan to cover its employees in lieu of covering them under an insured Texas workers' compensation plan.
Impact of Prices for Our Oil and Natural Gas. With the acquisition of PetroCorp Incorporated (as further discussed in Note 12 of the Notes to Consolidated Financial Statements), natural gas comprises 86% of our total oil and natural gas reserves. Before the acquisition, natural gas comprised 89% of our reserves. Any significant change in natural gas prices has a material affect on our revenues, cash flow and the value of our oil and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by world wide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we can not predict nor measure their future influence on the prices we will receive.
Based on our production in 2003, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $160,300 per month ($1,923,600 annualized) change in our pre-tax operating cash flow. Our 2003 average natural gas price was $4.87 compared to an average natural gas price of $2.87 for 2002. A $1.00 per barrel change in our oil price would have a $40,000 per month ($480,000 annualized) change in our pre-tax operating cash flow based on our production in 2003. Our
2003 average oil price was $26.94 compared with an average oil price of $21.54 received in 2002.
Because natural gas prices have such a significant affect on the value of our oil and natural gas reserves, declines in these prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our bank loan agreement since that determination is based mainly on the value of our oil and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects.
We sell most of our natural gas production to third parties under month-to-month contracts. Several of these buyers have experienced financial complications resulting from the recent investigations into the energy trading industry. The long-term implications to the energy trading business, as well as to oil and natural gas producers, because of these investigations remains, to be determined. We continue to evaluate the information available to us about our buyers and try to reduce any possible future adverse impact to us. Presently we believe that our buyers will be able to perform their commitments to us. For 2003, purchases by Cinergy Marketing & Trading LP accounted for approximately 17% of our oil and natural gas revenues while purchases by Centerpoint Energy Gas accounted for approximately 16% of our oil and natural gas revenues. We own a 16.7% limited partner interest in Eagle Energy Partners I LP, whose purchases, which are competitively marketed, accounted for 6% of our oil and natural gas revenues in 2003. We have increased our sales to Eagle Energy Partners I LP since we first started selling natural gas to them in August, 2003. For the period August through December 2003 Eagle has purchased 16% of our oil and natural gas revenues and they marketed approximately 37% of the natural gas volumes we sold for ourselves and third parties during the same five month period.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures are discretionary and directed toward future growth. Our decision to increase our oil and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when to incur such costs. We drilled 149 wells (61.57 net wells) in 2003 compared to 96 wells (51.87 net wells) in 2002. Our total capital expenditures for oil and natural gas exploration and acquisitions in 2003 totaled $73.3 million excluding capitalized cost for the recording of the plugging liability associated with our wells. Based on current prices, we plan to drill an estimated 165 to 175 wells in 2004 and total capital expenditures for oil and natural gas exploration and acquisitions is planned to be around $95 million.
Contract Drilling. Our drilling work is subject to many factors that influence the number of rigs we have working as well as the costs and revenues associated with such work. These factors include competition from other drilling contractors, the prevailing prices for natural gas and oil, availability and cost of labor to run our rigs and our ability to supply
the equipment needed. We have not encountered major difficulty in hiring and keeping rig crews, but such shortages have occurred periodically in the past. If demand for drilling rigs increases rapidly in the future, shortages of experienced personnel may limit our ability to increase the number of rigs we could operate.
Most of our contract drilling fleet is targeted to the drilling of natural gas wells, so changes in natural gas prices influence the demand for our drilling rigs and the prices we can charge for our contract drilling services. In the last half of 1999 and throughout 2000, as oil and natural gas prices increased, we experienced a big increase in demand for our rigs. Demand continued to increase until the end of the third quarter of 2001 and reached a high when 52 of our rigs were working in July 2001. Because of declining natural gas prices throughout 2001, demand for our rigs dropped significantly in the fourth quarter of 2001 and stabilized with between 30 and 35 rigs operating in the first half of 2002. The rates received for our rigs also began to fall until they reached a low of $7,275 per day in February of 2003. Natural gas and oil prices once again began to rise during the last half of 2002 and in the second quarter of 2003 through the remainder of the year both demand for our rigs and dayrates continued to improve. In December 2003 the average dayrate on the 75 rig fleet owned by us throughout 2003 was approximately $8,200 per day and the 12 Service rigs added in December 2003 had a dayrate of approximately $7,500 making the average dayrate for the 88 rig fleet $8,130 in December 2003. The average use of our rigs in 2003 was 62.9 rigs (83%) compared with 39.1 rigs (63%) for 2002. Our average dayrate in 2003 was $7,808 compared to $7,716 for 2002. Based on the average utilization of our rigs in 2003, a $100 per day change in dayrates has a $6,290 per day ($2,296,000 annualized) change in our pre-tax operating cash flow. Utilization and dayrates for our drilling rigs will depend mainly on the price of natural gas.
Our contract drilling subsidiary provides drilling services for our exploration and production subsidiary. The contracts for these services are issued under the same conditions and rates as the contracts we have entered into with unrelated third parties. During 2003, we drilled 43 wells for our exploration and production subsidiary. Per regulations provided by the Securities and Exchange Commission, the profit received by our contract drilling segment of $841,000 and $1,883,000 during 2002 and 2003, respectively, was used to reduce the carrying value of our oil and natural gas properties rather than being included in our profits in current operations.
Drilling Acquisitions and Capital Expenditures. On December 8, 2003, we acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the three years following the acquisition. The assets of SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and trailers, various other vehicles and a district office and an equipment yard in and near Borger, Texas. For our contract drilling operations during 2003, we incurred $71.9 million in capital expenditures, which includes $35.0 million in cash and $10.9 million for goodwill resulting from
deferred tax liabilities recorded in connection with the SerDrilco acquisition. For the year 2004, we have budgeted capital expenditures of approximately $30 million for our contract drilling operations.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We are the general partner for 10 oil and natural gas partnerships which were formed privately and publicly. The partnership's revenues and costs are shared under formulas prescribed in each limited partnership agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party's behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party's level of activity and are considered by management to be reasonable. During 2001, 2002 and 2003, the total paid to us for all of these fees was $1,107,000, $929,000 and $873,000, respectively. We expect the fees to be about the same in 2004. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements.
We own a 40% equity interest in Superior Pipeline Company LLC, an Oklahoma Limited Liability Company. Superior is a natural gas gathering and processing company. Our investment, including our share of the equity in the earnings of this company, totaled $3.0 million at December 31, 2003 and is reported in other assets in our accompanying balance sheet. During 2003, Superior Pipeline Company LLC purchased $3.3 million of our natural gas production and paid $64,000 for our natural gas liquids. We paid this company $39,000 for gathering and compression services.
We also own a 16.7% limited partnership interest in Eagle Energy Partnership I, L.P. ("Eagle"), carried at cost, for $2.5 million. Eagle is engaged in the purchase and sale of natural gas, electricity (or similar electricity based products), future commodities, and the performance of scheduling and nomination services for both energy related commodities and similar energy management functions. Eagle was marketing approximately 46% of the natural gas volumes we sell for ourselves and third parties in December 2003 and during February 2004 they are marketing 48%.
Contractual Commitments. We have the following contractual obligations at December 31, 2003:
Payments Due by Period -------------------------------------------------- Less Contractual Than 1 2-3 4-5 After 5 Obligations Total Year Years Years Years ------------- --------- -------- -------- --------- -------- (In thousands)
Bank Debt(1) $ 400 $ -- $ -- $ 400 $ -- Retirement Agreement(2) 1,650 300 600 600 150 Operating Leases(3) 3,555 719 1,424 954 458 --------- -------- -------- --------- -------- Total Contractual Obligations $ 5,605 $ 1,019 $ 2,024 $ 1,954 $ 608 ========= ======== ======== ========= ======== -------------------
(1) See Previous Discussion in Management Discussion and Analysis regarding bank debt. The obligation is presented in accordance with the terms of the loan agreement signed on January 30, 2004.
(2) In the second quarter of 2001, we recorded $1.3 million in additional employee benefit expenses for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, will be paid in monthly payments of $25,000 starting in July 2003 and continuing through June 2009. The liability as presented above is undiscounted.
(3) We lease office space in Tulsa and Woodward, Oklahoma and Houston, Texas under the terms of operating leases expiring through January 31, 2010 along with leasing space on short-term commitments to stack excess rig equipment and production inventory. In the first quarter of 2003, we renegotiated our rental agreement for the Tulsa office reducing the price per square foot while adding additional space and lengthening the term of the agreement to January 31, 2010.
At December 31, 2003, we also have the following commitments and contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration Per Period ------------------------------------------ Total Amount Committed Less Other or Than 1 2-3 4-5 After 5 Commitments Accrued Year Years Years Years ----------------- --------- -------- -------- -------- --------- (In thousands) Deferred Compensation Agreement(1) $ 1,829 Unknown Unknown Unknown Unknown Separation Benefit Agreement(2) $ 2,545 $ 412 Unknown Unknown Unknown Plugging Liability(3) $ 11,994 $ 303 $ 481 $ 882 $ 10,328 Gas Balancing Liability(4) $ 1,191 Unknown Unknown Unknown Unknown Repurchase Obliga- tions(5) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Consolidated Balance Sheet, at the time of deferral. (2) Effective January 1, 1997, we adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with Unit up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. (3) On January 1, 2003 we adopted Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of
long-lived assets (mainly plugging and abandonment costs for our depleted wells) in the period in which the liability is incurred (at the time the wells are drilled or acquired). (4) We have a liability recorded for certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. (5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2004, with a subsidiary of ours serving as General Partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, upon the election of a limited partner, that we repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $1,000 and $106,000 in 2002 and 2003, respectively, for such limited partners' interests. No repurchases were made in 2001.
Critical Accounting Policies. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. At the end of each quarter, the net capitalized costs of our oil and natural gas properties is limited to the lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the present value (10% discount rate) of estimated future net revenues from proved reserves, based on period-end oil and natural gas prices adjusted for hedging, plus the lower of cost or estimated fair value of unproved properties not included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down cannot be reversed even if prices subsequently recover.
The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed or if we have large downward revisions in our estimated proved reserves. Application of these rules during periods of relatively low oil or natural gas prices, even if temporary, increases the chance of a ceiling test write-down. Based on oil and natural gas prices on December 31, 2003 ($5.67 per Mcf for natural gas and $32.52 per barrel for
oil), the unamortized cost of our domestic oil and natural gas properties did not exceed the ceiling of our proved oil and natural gas reserves. Natural gas prices remain erratic and any significant declines below prices used in the reserve evaluation could result in a ceiling test write-down in following quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the borrowing base under our loan agreement with our banks. This amount is affected by both price changes and the measurement of reserve volumes. Oil and natural gas reserves cannot be measured exactly. Our estimate of oil and natural gas reserves require extensive judgments of our reservoir engineering data and are less precise than other estimates made in connection with financial disclosures. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves.
We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the natural gas balancing position on wells in which we have an imbalance are not material.
Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and betterments are capitalized while repairs and maintenance are expensed. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances suggest the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment.
We recognize revenues and expense generated from "daywork" drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under "footage" and "turnkey" contracts, we bear the risk of completion of the well, so revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets.
EFFECTS OF INFLATION - --------------------
The effect of inflation in the oil and natural gas industry is primarily driven by the prices realized for oil and natural gas. Increased commodity prices increase demand for contract drilling rigs and services which support higher rig activity. This in turn affects the overall demand for our rigs and the dayrates we can obtain for our contract drilling services. Before 1999, the effect of inflation on our operations was minimal due to low inflation rates, relatively low natural gas and oil prices and moderate demand for our contract drilling services. Over the last four years natural gas and oil prices have been more volatile, and during periods of higher utilization we have experienced increases in labor cost and the cost of services to support our rigs. During this same period when commodity prices did decline labor rates did not come back down to the levels incurred before the increases. If natural gas prices increased substantially for a long period, shortages in support equipment such as drill pipe, third party services and qualified labor could occur resulting in additional corresponding increases in our material and labor costs. These conditions may limit our ability to realize improvements in operating profits. How inflation will affect us in the future will depend on additional increases, if any, realized in our drilling rig rates and the prices we receive for our oil and natural gas.
NEW ACCOUNTING PRONOUNCEMENTS - -----------------------------------
On January 1, 2003 we adopted Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. We own oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We do not have any assets restricted for the purpose of settling the plugging liabilities.
The effect of this change increased net property, plant and equipment by $13.0 million and liabilities, including deferred tax liabilities, by $11.7 million at January 1, 2003 and decreased net income for the year ended December 31, 2003 by $148,000 ($0.00 per share). The financial statements for the year ended December 31, 2002 have not been restated and the cumulative effect of the change of $1.3 million net of tax ($0.03 per share) is shown as a one-time addition to income in the first quarter of 2003.
On January 17, 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46, as amended, was effective for us in the fourth quarter of 2003 as it applies to entities created after February 1, 2003. The adoption of FIN 46 with respect to these entities, did not have an impact on our financial position or results of operations. For entities created prior to February 1, 2003, which are not special purpose entities, as defined in FIN 46, we will have to adopt FIN 46, as amended, in the quarter ending March 31, 2004. We are still evaluating FIN 46 with regard to these types of entities in which we have an ownership interest, primarily our oil and gas partnerships and our equity investment in Superior pipeline. FIN 46 may require full consolidation of these entities which would increase our total assets with an offsetting minority interest for the percentage not owned by Unit. There will be no net impact to our results of operations from the adoption of FIN 46.
Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. Depending on how the accounting and disclosure literature is applied, oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract oil and natural gas reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the notes to our financial statements would include the disclosures required by FAS 141 and 142 regarding intangibles. To date, we, like many other oil and gas companies, have included oil and gas extraction rights as part of the oil and gas properties, even after FAS 141 and 142 became effective.
Our results of operations and cash flows would not be affected, since these oil and gas mineral extraction rights would continue to be amortized in accordance with full cost accounting rules.
At December 31, 2002 and 2003, we had undeveloped leaseholds of approximately $13.2 million and $14.8 million, respectively that would be classified on our balance sheets as "intangible undeveloped leasehold" and
developed leaseholds of an estimated $18.1 million and $24.6 million, respectively that would be classified as "intangible developed leasehold" if the interpretations were applied. This classification would require us to make the disclosures set forth under FAS 142 related to these interests.
We intend to continue to classify our oil and gas mineral extraction rights as tangible oil and gas properties until further guidance is provided.
RESULTS OF OPERATIONS - --------------------- 2003 versus 2002 - ---------------- Provided below is a comparison of selected operating and financial data for the year of 2002 versus the year of 2003: Percent 2002 2003 Change --------------- --------------- --------- Total Revenue $ 187,636,000 $ 302,584,000 61% Income Before Change in Accounting Principle $ 18,244,000 $ 48,864,000 168% Net Income $ 18,244,000 $ 50,189,000 175%
Oil and Natural Gas: Revenue $ 67,959,000 $ 116,609,000 72% Average natural gas price (Mcf) $ 2.87 $ 4.87 70% Average oil price (Bbl) $ 21.54 $ 26.94 25% Natural gas production (Mcf) 18,968,000 20,648,000 9% Oil production (Bbl) 473,000 516,000 9% Depreciation, depletion and amortization rate (Mcfe) $ 1.04 $ 1.14 10% Depreciation, depletion and amortization ($346,000 write off of interest in Shenandoah in 2002) $ 23,338,000 $ 27,343,000 17%
Drilling: Revenue $ 118,173,000 $ 183,146,000 55% Percentage of revenue from daywork contracts 91% 98% Average number of rigs in use 39.1 62.9 61% Average dayrate on daywork contracts $ 7,716 $ 7,808 1% Depreciation $ 14,684,000 $ 23,644,000 61%
General and Administrative Expense $ 8,712,000 $ 9,222,000 6% Interest Expense $ 973,000 $ 693,000 (29%) Average Interest Rate 3.0% 2.2% (27%) Average Long-Term Debt Outstanding $ 24,771,000 $ 20,722,000 (16%)
Oil and natural gas revenues and net income were all positively affected by the higher prices we received for both our oil and natural gas during 2003 as compared to 2002. Production for both oil and natural gas was also up between the comparative years. Total operating cost increased primarily from higher gross production taxes resulting from higher revenues. Total depreciation, depletion and amortization ("DD&A") on our oil and natural gas properties increased due to higher production volumes and an increase in the DD&A rate in 2003, which resulted from higher development drilling cost per equivalent Mcf.
Operator demand for our rigs increased gradually throughout 2003 as natural gas prices increased in 2003 versus 2002 and resulted in higher rig use and dayrates for our rigs. Higher dayrates were offset by higher rig expense as we experienced a 121% increase in ad valorem taxes on our rigs and a 175% increase in worker's compensation expense. We expect both of these expenses, along with increased demand for quality labor within the industry, to keep upward pressure on rig costs throughout 2004. Approximately 2% of our total drilling revenues in 2003 came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. Nine percent of our total drilling revenues came from footage and turnkey contracts in 2002. Contract drilling depreciation increased due to the acquisition of 20 rigs in August of 2002 and additional rig use.
General and administrative expense was higher in 2003 due to an increase in general liability insurance, director and officer insurance and increased corporate administrative cost. Our total interest expense is lower due to lower interest rates and a substantial reduction in our average long-term debt. Income tax expense increased 202% primarily due to a 180% increase in income before income taxes. Our effective tax rate for 2002 was 34.4% versus 37.2% in 2003. The impact of higher statutory depletion and other permanent differences reduced by the impact of state income taxes was the cause for the lower effective tax rate in 2002.
Net income includes $1.3 million of income due to an accumulated change in accounting principle for the implementation of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. We own oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). The financial statements for the year ended December 31, 2002 have not been restated and the cumulative effect of the change of $1.3 million net of tax ($0.03 per share) is shown as a one-time addition to income in 2003.
2002 versus 2001 - ------------------- Provided below is a comparison of selected operating and financial data for the year of 2002 versus the year of 2001:
Percent 2001 2002 Change --------------- --------------- --------- Total Revenue $ 259,179,000 $ 187,636,000 (28%) Net Income $ 62,766,000 $ 18,244,000 (71%)
Oil and Natural Gas: Revenue $ 90,237,000 $ 67,959,000 (25%) Average natural gas price (Mcf) $ 4.00 $ 2.87 (28%) Average oil price (Bbl) $ 23.62 $ 21.54 (9%) Natural gas production (Mcf) 18,864,000 18,968,000 1% Oil production (Bbl) 492,000 473,000 (4%) Depreciation, depletion and amortization rate (Mcfe) $ 0.91 $ 1.04 14% Depreciation, depletion and amortization (includes $2,083,000 and $346,000 write off of interest in Shenandoah in 2001 and 2002, respectively) $ 22,116,000 $ 23,338,000 6%
Drilling: Revenue $ 167,042,000 $ 118,173,000 (29%) Percentage of revenue from daywork contracts 99% 91% Average number of rigs in use 46.3 39.1 (16%) Average dayrate on daywork contracts $ 10,044 $ 7,716 (23%) Depreciation $ 13,888,000 $ 14,684,000 6%
General and Administrative Expense $ 8,476,000 $ 8,712,000 3% Interest Expense $ 2,818,000 $ 973,000 (65%) Average Interest Rate 5.7% 3.0% (47%) Average Long-Term Debt Outstanding $ 44,995,000 $ 24,771,000 (45%)
Oil and natural gas revenues, net income were all negatively affected by lower prices received for both oil and natural gas during 2002 compared to 2001. Production in equivalent Mcf was almost the same in 2002 as in 2001. Total operating cost decreased due to lower gross production taxes resulting from lower revenues. Total DD&A on our oil and natural gas properties increased due to the increase in the DD&A rate in 2002, which resulted from higher development drilling cost per equivalent Mcf. The increase would have been larger, but included in 2001 DD&A was the write down of our investment in Shenandoah Resources LTD. In 2001 Shenandoah started experiencing financial difficulties and its stock price declined, so we took a write down in our investment of $2.1 million to reduce the carrying value to the market value of Shenandoah's stock. In August 2002, the assets of Shenandoah were liquidated for the benefit of the secured creditors and, as a result, our remaining investment of $346,000 in Shenandoah was written off.
Reduced natural gas prices, especially in the fourth quarter of 2001 and the first quarter of 2002, caused decreases in operator demand for contract drilling rigs within our working area and resulted in lower rig use and dayrates for our rigs. Total drilling operating costs were relatively unchanged between the two years. Approximately 9% of our total drilling revenues in 2002 came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. One percent of our total drilling revenues came from footage and turnkey contracts in 2001. Contract drilling depreciation increased due to the acquisition of 20 rigs in August of 2002. The increase was partially offset by lower rig use.
General and administrative expense was higher in 2002 due to increases in labor cost, insurance expense and outside contract services. In the second quarter of 2001, we recorded $1.3 million in additional employee benefit expenses for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense plus accrued interest will be paid in $25,000 monthly payments starting in July 2003 and continuing through June 2009. Our total interest expense is lower due to lower interest rates along with a substantial reduction in our long-term debt. Income tax expense decreased 73% primarily due to a 72% decrease in income before income taxes.
Item 7a.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk - -------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates.
Commodity Price Risk. Our major market risk exposure is in the price we receive for our oil and natural gas production. The price we receive is primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, prices we received for our oil and natural gas production fluctuated and such fluctuation is expected to continue. The price of natural gas also effects the demand for our rigs and the amount we can charge for the use of the rigs. Based on our 2003 production, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $160,300 per month ($1,923,600 annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $40,000 per month ($480,000 annualized) change in our pre-tax operating cash flow.
In an effort to try and reduce the impact of price fluctuations, over the past several years we periodically have used hedging strategies to hedge the price we will receive for a portion of our future oil and natural gas production. A detailed explanation of those transactions has been included under hedging in the financial condition portion of management's discussion and analysis of financial condition and results of operations included above.
Interest Rate Risk. Our interest rate exposure relates to our long-term debt, all of which bears interest at variable rates based on the JPMorgan Chase Prime Rate or the Eurodollar Rate. At our election, borrowings under our revolving credit facility may be fixed at the Eurodollar Rate for periods up to 180 days. Historically, we have not utilized any financial instruments, such as interest rate swaps, to manage our exposure to increases in interest rates. However, we may use financial instruments in the future should our assessment of future interest rates warrant there use. Based on our average outstanding long-term debt in 2003, a 1% change in the floating rate would change our annual pre-tax cash flow by approximately $207,000.
Item 8.
Item 8. Financial Statements and Supplementary Data - ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
As of December 31, ------------------------ 2002 2003 ---------- ---------- (In thousands) ASSETS ------ Current Assets: Cash and cash equivalents $ 497 $ 598 Accounts receivable (less allowance for doubtful accounts of $1,203 and $1,223) 33,912 58,807 Materials and supplies 8,794 8,023 Income tax receivable 3,602 112 Prepaid expenses and other 4,594 5,202 ---------- ---------- Total current assets 51,399 72,742 ---------- ----------
Property and Equipment: Drilling equipment 369,777 424,321 Oil and natural gas properties, on the full cost method: Proved Properties 449,226 528,110 Undeveloped Leasehold not being amortized 16,024 17,486 Transportation equipment 6,856 9,828 Other 9,906 14,535 ---------- ---------- 851,789 994,280 Less accumulated depreciation, depletion, amortization and impairment 341,031 385,219 ---------- ---------- Net property and equipment 510,758 609,061 ---------- ---------- Goodwill 12,794 23,722 Other Assets 3,212 7,400 ---------- ---------- Total Assets $ 578,163 $ 712,925 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31, ------------------------ 2002 2003 ---------- ---------- (In thousands) LIABILITIES AND SHAREHOLDERS' EQUITY ----------------------------------- Current Liabilities: Current portion of long-term debt and other liabilities (Note 4) $ 1,465 $ 1,015 Accounts payable 21,119 32,871 Accrued liabilities 11,921 15,921 Contract advances 27 2,004 ---------- ---------- Total current liabilities 34,532 51,811 ---------- ---------- Long-Term Debt (Note 4) 30,500 400 ---------- ---------- Other Long-Term Liabilities (Note 4) 5,439 17,893 ---------- ---------- Deferred Income Taxes (Note 5) 86,320 127,053 ---------- ---------- Commitments and Contingencies (Note 9)
Shareholders' Equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued -- -- Common stock, $.20 par value, 75,000,000 shares authorized, 43,339,400 and 45,592,012 shares issued, respectively 8,668 9,117 Capital in excess of par value 264,180 307,938 Retained earnings 148,524 198,713 ---------- ---------- Total shareholders' equity 421,372 515,768 ---------- ---------- Total Liabilities and Shareholders' Equity $ 578,163 $ 712,925 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, -------------------------------------- 2001 2002 2003 ---------- ---------- ---------- (In thousands except per share amounts) Revenues: Contract drilling $ 167,042 $ 118,173 $ 183,146 Oil and natural gas 90,237 67,959 116,609 Other 1,900 1,504 2,829 ---------- ---------- ---------- Total revenues 259,179 187,636 302,584 ---------- ---------- ---------- Expenses: Contract drilling: Operating costs 91,006 91,338 138,762 Depreciation 13,888 14,684 23,644 Oil and natural gas: Operating costs 22,196 20,795 25,169 Depreciation, depletion, amortization and impairment 22,116 23,338 27,343 General and administrative 8,476 8,712 9,222 Interest 2,818 973 693 ---------- ---------- ---------- Total expenses 160,500 159,840 224,833 ---------- ---------- ---------- Income Before Income Taxes and Change in Accounting Principle 98,679 27,796 77,751 ---------- ---------- ---------- Income Tax Expense: Current 5,609 (3,469) -- Deferred 30,304 13,021 28,887 ---------- ---------- ---------- Total income taxes 35,913 9,552 28,887 ---------- ---------- ---------- Income Before Change in Accounting Principle 62,766 18,244 48,864 Cumulative Effect of Change in Accounting Principle (Net of Income Tax of $811) -- -- 1,325 ---------- ---------- ---------- Net Income $ 62,766 $ 18,244 $ 50,189 ========== ========== ==========
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME - CONTINUED
Year Ended December 31, -------------------------------------- 2001 2002 2003 ---------- ---------- ---------- (In thousands except per share amounts) Basic Earnings Per Common Share: Income before change in accounting principle $ 1.75 $ 0.47 $ 1.12 Cumulative effect of change in accounting principle net of income tax -- -- 0.03 ---------- ---------- ---------- Net income $ 1.75 $ 0.47 $ 1.15 ========== ========== ==========
Diluted Earnings Per Common Share: Income before change in accounting principle $ 1.73 $ 0.47 $ 1.12 Cumulative effect of change in accounting principle net of income tax -- -- 0.03 ---------- ---------- ---------- Net income $ 1.73 $ 0.47 $ 1.15 ========== ========== ==========
Pro Forma Amounts Assuming Retroactive Application of Change in Accounting Principle:
Net income $ 62,662 $ 18,115 ========== ========== Basic earnings per share $ 1.74 $ 0.47 ========== ========== Diluted earnings per share $ 1.73 $ 0.46 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 2001, 2002 and 2003
Accumulated Capital Other In Excess Comprehen- Common of Par Retained sive Treasury Stock Value Earnings Income Stock Total -------- ---------- --------- --------- -------- ---------- (In thousands except share amounts) Balances, January 1, 2001 $ 7,154 $ 139,872 $ 67,514 $ -- $ -- $ 214,540 Net Income -- -- 62,766 -- -- 62,766 Activity in employee compensation plans (237,923 shares) 47 2,105 -- -- -- 2,152 Purchase of treasury shares (30,000 shares) -- -- -- -- (296) (296) Other comprehen- sive income (net of tax of $771 and $771): Change in value of cash flow deriva- tive instru- ments used as cash flow hedges -- -- -- 1,258 -- 1,258 Adjustment reclas- ification - deriva- tive settle- ments -- -- -- (1,258) -- (1,258) -------- ---------- --------- --------- -------- ---------- Balances, December 31, 2001 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162 ======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED Year Ended December 31, 2001, 2002 and 2003
Accumulated Capital Other In Excess Comprehen- Common of Par Retained sive Treasury Stock Value Earnings Income Stock Total -------- ---------- --------- --------- -------- ---------- (In thousands except share amounts) Balances, January 1, 2002 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162 Net Income -- -- 18,244 -- -- 18,244 Activity in employee compensation plans (113,133 shares) 23 1,156 -- -- 296 1,475 Issuance of stock for acquisition (7,220,000 shares) 1,444 121,047 -- -- -- 122,491 Other comprehen- sive income (net of tax of $15 and $15): Change in value of cash flow deriva- tive instr- uments used as cash flow hedges -- -- -- 25 -- 25 Adjustment reclas- ification - deriva- tive settle- ments -- -- -- (25) -- (25)
-------- ---------- --------- --------- -------- ---------- Balances, December 31, 2002 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372 ======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED Year Ended December 31, 2001, 2002 and 2003
Accumulated Capital Other In Excess Comprehen- Common of Par Retained sive Treasury Stock Value Earnings Income Stock Total -------- ---------- --------- --------- -------- ---------- (In thousands except share amounts) Balances, January 1, 2003 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372 Net Income -- -- 50,189 -- -- 50,189 Activity in employee compensation plans (252,612 shares) 49 2,018 -- -- -- 2,067 Issuance of 2,000,000 shares of common stock) 400 41,740 -- -- -- 42,140 Other comprehen- sive income (net of tax of $3 and $3): Change in value of cash flow deriva- tive instru- ments used as cash flow hedges -- -- -- (4) -- (4) Adjustment reclas- ifica- tion - deriva- tive settle- ments -- -- -- 4 -- 4
-------- ---------- --------- --------- -------- ---------- Balances, December 31, 2003 $ 9,117 $ 307,938 $198,713 $ -- $ -- $ 515,768 ======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ------------------------------------ 2001 2002 2003 ---------- ---------- ---------- (In thousands) Cash Flows From Operating Activities: Net Income $ 62,766 $ 18,244 $ 50,189 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, amortization and impairment 36,642 38,657 51,783 Equity in net earnings of unconsolidated investments (1,148) (745) (1,516) Loss (gain) on disposition of assets (56) (69) 51 Employee stock compensation plans 2,873 1,165 1,415 Bad debt expense -- 603 645 Plugging liability - cumulative effect - net of accretion -- -- (1,624) Deferred tax expense 30,304 13,021 28,887 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable 6,334 (43) (25,540) Materials and supplies (1,556) (3,436) 771 Prepaid expenses and other (3,533) 2,365 4,240 Accounts payable (155) 1,784 6,148 Accrued liabilities 929 (350) 4,286 Contract advances 61 (213) 1,977 Other liabilities (440) (436) -- ---------- ---------- ---------- Net cash provided by operating activities 133,021 70,547 121,712 ---------- ---------- ----------
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31, ------------------------------------ 2001 2002 2003 ---------- ---------- ---------- (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property and contract drilling acquisitions) $(108,339) $ (75,225) $(131,162) Proceeds from disposition of property and equipment 2,631 1,949 1,625 (Acquisition) disposition of other assets 17 540 (2,562) ---------- ---------- ---------- Net cash used in investing activities (105,691) (72,736) (132,099) ---------- ---------- ---------- Cash Flows From Financing Activities: Borrowings under line of credit 57,200 36,700 65,200 Payments under line of credit (79,200) (36,200) (95,300) Net payments on notes payable and other long-term debt (1,000) (1,161) (1,105) Proceeds from exercise of stock options 609 413 452 Proceeds from sale of common stock -- -- 42,140 Book overdrafts (Note 1) (4,978) 2,543 (899) Acquisition of treasury stock (296) -- -- ---------- ---------- ---------- Net cash provided by (used in) financing activities (27,665) 2,295 10,488 ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents (335) 106 101 Cash and Cash Equivalents, Beginning of Year 726 391 497 ---------- ---------- ---------- Cash and Cash Equivalents, End of Year $ 391 $ 497 $ 598 ========== ========== ========== Supplemental Disclosure of Cash Flow Information: Cash paid (received) during the year for: Interest $ 2,807 $ 1,053 $ 660 Income taxes $ 7,779 $ (4,585) $ (3,495)
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ---------------------------------------------------
Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its directly and indirectly wholly owned subsidiaries ("Unit"). The investment in limited partnerships is accounted for on the proportionate consolidation method, whereby Unit's share of the partnerships' assets, liabilities, revenues and expenses is included in the appropriate classification in the accompanying consolidated financial statements.
Nature of Business. Unit is engaged in the land contract drilling of natural gas and oil wells and the exploration, development, acquisition and production of oil and natural gas properties. Unit's current contract drilling operations are focused primarily in the natural gas producing provinces of the Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Coast and the Rocky Mountain regions. Unit's primary exploration and production operations are also conducted in the Anadarko and Arkoma Basins and in the Texas Gulf Coast area with additional properties in the Permian Basin. The majority of its contract drilling and exploration and production activities are oriented toward drilling for and producing natural gas. At December 31, 2003, Unit had an interest in a total of 3,393 wells and served as operator of 753 of those wells. Unit provides land contract drilling services for a wide range of customers using the drilling rigs, which it owns and operates. In 2003, 84 of Unit's 88 rigs performed contract drilling services.
Drilling Contracts. Unit recognizes revenues and expenses generated from "daywork" drilling contracts as the services are performed, since the Company does not bear the risk of completion of the well. Under "footage" and "turnkey" contracts, Unit bears the risk of completion of the well therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The duration of all three types of contracts range typically from 20 to 90 days, but some of our daywork contracts in the Rocky Mountains can range up to one year. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets.
Cash Equivalents and Book Overdrafts. Unit includes as cash equivalents, certificates of deposits and all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued prior to the end of the period, but not presented to Unit's bank for payment prior to the end of the period. At December 31, 2002 and 2003, book overdrafts of $3.6 million and $2.7 million have been included in accounts payable.
Property and Equipment. Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives, including a minimum provision of 20% of the active rate when the equipment is idle. Unit uses the composite method of depreciation for drill pipe and collars and calculates the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause Unit to reduce the carrying value of property and equipment.
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
Goodwill. Goodwill represents the excess of the cost of the acquisition of Hickman Drilling Company, CREC Rig Equipment Company, CDC Drilling Company and SerDrilco Incorporated over the fair value of the net assets acquired. Prior to January 1, 2002 goodwill was amortized on the straight-line method using a 25 year life. Unit expensed $243,000 annually for the amortization of goodwill. On July 20, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("FAS 142"). For goodwill and intangible assets recorded in the financial statements, FAS 142 ends the amortization of goodwill and certain intangible assets and subsequently requires, at least annually, that an impairment test be performed on such assets to determine whether the fair value has decreased. FAS 142 became effective for the fiscal years starting after December 15, 2001 (January 1, 2002 for Unit). Goodwill is all related to the drilling segment. The 2002 increase in the carrying amount of goodwill of $7,706,000 came from the goodwill acquired in the acquisition of CREC Rig Equipment Company and CDC Drilling Company and the 2003 increase in the carrying amount of goodwill of $10,928,000 came from the goodwill acquired in the acquisition of SerDrilco Incorporated. Both acquisitions are more fully discussed in Note 2. Goodwill of $7,009,000 is expected to be deductible for tax purposes. The following table shows the adjusted net income and earnings per share resulting from the removal of the amortization expense (net of income tax) recognized in the prior periods: 2001 2002 2003 --------- --------- --------- (In thousands except per share amounts) Adjusted Net Income: Reported net income $ 62,766 $ 18,244 $ 50,189 Add back: goodwill amortized - net of income tax 88 -- -- --------- --------- --------- Adjusted net income $ 62,854 $ 18,244 $ 50,189 ========= ========= =========
Basic Earnings per Share: Reported net income $ 1.75 $ 0.47 $ 1.15 Add back: goodwill amortized - net of income tax -- -- -- --------- --------- --------- Adjusted net income $ 1.75 $ 0.47 $ 1.15 ========= ========= =========
Diluted Earnings per Share: Reported net income $ 1.73 $ 0.47 $ 1.15 Add back: goodwill amortized - net of income tax -- -- -- --------- --------- --------- Adjusted net income $ 1.73 $ 0.47 $ 1.15 ========= ========= =========
Oil and Natural Gas Operations. Unit accounts for its oil and natural gas exploration and development activities on the full cost method of accounting prescribed by the Securities and Exchange Commission ("SEC"). Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves are capitalized and amortized on a composite units-of-production method based on proved oil and natural gas reserves. Unit capitalizes internal costs that can be directly identified with its acquisition, exploration and development activities. Independent petroleum engineers annually review Unit's determination of its oil and natural gas reserves. The average composite rates used for depreciation, depletion and amortization ("DD&A") were $0.91, $1.04 and $1.14 per Mcfe in 2001, 2002 and 2003, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Unit's unproved properties totaling $17.5 million are excluded from the DD&A calculation. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. The full cost ceiling is based principally on the estimated future discounted net cash flows from Unit's oil and natural gas properties. As discussed in Note 13, such estimates are imprecise.
No gains or losses are recognized on the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount is involved.
Unit's contract drilling subsidiary provides drilling services for its exploration and production subsidiary. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. During 2003, the contract drilling subsidiary drilled 43 wells for our exploration and production subsidiary. As required by the Securities and Exchange Commission, the profit received by our contract drilling segment of $2,259,000, $841,000 and $1,883,000 during 2001, 2002 and 2003, respectively, was used to reduce the carrying value of our oil and natural gas properties rather than being included in our profits in current operations.
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum Company, is a general partner in 10 oil and natural gas limited partnerships sold privately and publicly. Some of Unit's officers, directors and employees own the interests in most of these partnerships. Unit shares partnership revenues and costs in accordance with formulas prescribed in each limited partnership agreement. The partnerships also reimburse Unit for certain administrative costs incurred on behalf of the partnerships.
Income Taxes. Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.
Natural Gas Balancing. Unit uses the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Unit estimates its December 31, 2003 balancing position to be approximately 1.8 Bcf on under-produced properties and approximately 2.3 Bcf on over-produced properties. Unit has recorded a receivable of $562,000 on certain wells where we estimated that insufficient reserves are available for Unit to recover the under-production from future production volumes. Unit has also recorded a liability of $1,191,000 on certain properties where we believe there is insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Unit's policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which Unit has imbalances are not material.
Investments. Unit owns a 40% equity interest in Superior Pipeline Company LLC, a natural gas gathering and processing company. The investment, including Unit's share of the equity in the earnings of this company, totaled $3.0 million at December 31, 2003 and is reported in other assets.
Unit also owns a 16.7% interest carried at cost in Eagle Energy Partnership I, L.P. ("Eagle") for $2.5 million. Eagle is engaged in the purchase and sale of natural gas, electricity (or similar electricity based products), future commodities, and the performance of scheduling and nomination services for both energy related commodities and similar energy management functions.
Employee and Director Stock Based Compensation. Unit's stock-based compensation plans, which are explained more fully in Note 6, are accounted for under the recognition and measurement principles of APB Opinion 25 "Accounting for Stock Issued to Employees," and related interpretations. Under this standard, no compensation expense is recognized for grants of options, which include an exercise price equal to or greater than the market price of the stock on the date of grant. Accordingly, based on Unit's grants in 2001, 2002 and 2003 no compensation expense has been recognized. Compensation expense included in reported net income is Unit's matching 401(k) contribution which was made in Unit common stock. The following table illustrates the effect on net income and earnings per share if Unit had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation.
2001 2002 2003 --------- --------- --------- Net Income, as Reported (In Thousands) $ 62,766 $ 18,244 $ 50,189 Add Stock Based Employee Compensation Expense Included in Reported Net Income - Net of Tax 671 669 858 Less Total Stock Based Employee Compensation Expense Determined Under Fair Value Based Method For All Awards (1,615) (1,488) (2,114) --------- --------- --------- Pro Forma Net Income $ 61,822 $ 17,425 $ 48,933 ========= ========= ========= Basic Earnings per Share: As reported $ 1.75 $ 0.47 $ 1.15 ========= ========= ========= Pro forma $ 1.72 $ 0.45 $ 1.12 ========= ========= ========= Diluted Earnings per Share: As reported $ 1.73 $ 0.47 $ 1.15 ========= ========= ========= Pro forma $ 1.71 $ 0.45 $ 1.12 ========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes model. Unit's estimate of stock volatility in 2001, 2002 and 2003 was 0.55, 0.53 and 0.52, respectively, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 5.41% in 2001 and 4.24% in 2002 and 2003. Expected life ranged from 1 to 10 years based on prior experience depending on the vesting periods involved and the make up of participating employees. The aggregate fair value of options granted during 2002 and 2003 under the Stock Option Plan were $1,669,000 and $1,617,000, respectively. No options were issued under the Stock Option Plan in 2001. Under the Non-Employee Directors' Stock Option Plan the aggregate fair value of options granted during 2001 was $201,000 and $262,000 in 2002 and 2003.
Self Insurance. Unit utilizes self insurance programs for employee group health and worker's compensation. Self insurance costs are accrued based upon the aggregate of estimated liabilities for reported claims and claims incurred but not yet reported. Accrued liabilities include $3,632,000 and $7,990,000 for employer group health insurance and worker's compensation at December 31, 2002 and 2003, respectively. Unit's exposure (i.e. deductible or retention) per occurrence ranged from $200,000 for general liability to $1 million for rig physical damage. Unit has purchased stop-loss coverage
in order to limit, to the extent feasible, its per occurrence and aggregate exposure to certain claims. Following the acquisition of SerDrilco, Unit continued to use SerDrilco's ERISA governed occupational injury benefit plan to cover the SerDrilco employees in lieu of covering them under an insured Texas workers' compensation plan.
Treasury Stock. On August 30, 2001, Unit's Board of Directors authorized the purchase of up to one million shares of Unit's common stock. The timing of stock purchases are made at the discretion of management. During 2001, 30,000 shares were repurchased for $296,000. These shares were used for a portion of the company match to the 401(k) Employee Thrift Plan. No treasury stock was owned by Unit at December 31, 2002 and 2003.
Financial Instruments and Concentrations of Credit Risk. Financial instruments, which potentially subject Unit to concentrations of credit risk, consist primarily of trade receivables with a variety of national and international oil and natural gas companies. Unit does not generally require collateral related to receivables. Such credit risk is considered by management to be limited due to the large number of customers comprising Unit's customer base. During 2003, Chesapeake Operating, Inc. was our largest drilling customer and provided 15% of our total contract drilling revenues. Purchases by Cinergy Marketing & Trading LP accounted for approximately 17% of Unit's oil and natural gas revenues in 2003 while purchases by Centerpoint Energy Gas accounted for approximately 16% of Unit's oil and natural gas revenues. Unit owns a 16.7% in Eagle Energy Partners I LP, whose purchases accounted for 6% of Unit's oil and natural gas revenues in 2003. In addition, at December 31, 2002 and 2003, Unit had a concentration of cash of $3.0 million and $3.5 million, respectively, with one bank.
Hedging Activities. On January 1, 2001, Unit adopted Statement of Financial Accounting Standard No. 133 (subsequently amended by Financial Accounting Standard No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"). This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, Unit is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss) on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under FAS 133 must be recorded at fair value with gains (losses) recognized in earnings in the period of change.
Unit periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and natural gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps and basic hedges with major energy derivative product specialists. Initial adoption of this standard was not material.
Unit entered into a collar contract for approximately 25% of its daily production for January and February of 2001. The collar had a floor of $26.00 and a ceiling of $33.00 and Unit received $0.86 per barrel for entering into the collar transaction. During the first quarter of 2001, the net effect of this hedging transaction yielded an increase in oil revenues of $17,200.
During the second quarter of 2001, Unit entered into a natural gas collar contract for approximately 36% of its June and July 2001 natural gas production, at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter of 2001, Unit entered into two natural gas collar contracts for approximately 38% of its September through November 2001 natural gas production. Both contracts had a floor price of $2.50. One contract had a ceiling price of $3.68 and the other contract had a ceiling price of $4.25. During 2001 natural gas collar contracts added $2,030,000 to Unit's natural gas revenues.
On April 30, 2002, Unit entered into a collar contract covering approximately 19% of its natural gas production for the periods of April 1, 2002 through October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During the year of 2002, the natural gas hedging transactions increased natural gas revenues by $40,300. At December 31, 2002, Unit was not holding any natural gas or oil derivative contracts.
During the first quarter of 2003, Unit entered into two collar contracts covering approximately 40% of its natural gas production for the periods of April 1, 2003 through September 30, 2003. One collar had a floor of $4.00 and a ceiling of $5.75 and the other collar had a floor of $4.50 and a ceiling of $6.02. Unit also entered into two collar contracts covering approximately 25% of its oil production for the periods of May 1, 2003 through December 31, 2003. One collar had a floor of $25.00 and a ceiling of $32.20 and the other collar had a floor of $26.00 and a ceiling of $31.40. During the year 2003, the collar contracts decreased natural gas revenues by $6,000 and oil revenues by $5,000. We did not have any hedging transactions outstanding at December 31, 2003.
Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Impact of Financial Accounting Pronouncements.
On January 1, 2003 the company adopted Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. The company owns oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the
period in which the liability is incurred (at the time the wells are drilled or acquired). The company does not have any assets restricted for the purpose of settling the plugging liabilities.
The following table shows the activity for the year ending December 31, 2003 relating to the company's retirement obligation for plugging liability:
Short-Term Long-Term Plugging Plugging Liability Liability ------------- ------------- (In Thousands) Plugging Liability 1/1/03 $ 203 $ 10,632 Accretion of Discount 8 505 Liability Incurred in the Period -- 719 Liability Settled in the Period (65) (120) Liability Sold (36) (10) Reclassification of Liability From Long- to Short-Term 193 (193) Revision of Estimate -- 158 ------------- ------------- Plugging Liability 12/31/03 $ 303 $ 11,691 ============= =============
The effect of this change increased net property, plant and equipment by $13.0 million and liabilities, including deferred tax liabilities, by $11.7 million at January 1, 2003 and decreased net income for the year ended December 31, 2003 by $148,000 ($0.00 per share). The financial statements for the year ended December 31, 2002 have not been restated and the cumulative effect of the change of $1.3 million net of tax ($0.03 per share) is shown as a one-time addition to income in the first quarter of 2003.
The following table shows the adjusted net income and earnings per share resulting from the accretion of the discount and change in the depreciation, depletion and amortization (both net of income tax) as if the plugging liability had been recognized in the prior year ended periods:
2000 2001 2002 ------------ ------------ ------------ (In thousands except per share amounts)
Adjusted Net Income: Reported net income $ 34,344 $ 62,766 $ 18,244 Add back: Decrease in depreciation, depletion and amortiza- tion - net of income tax 80 156 167 Deduct: Accretion of discount - net of income tax (231) (260) (296) ------------ ------------ ------------ Adjusted net income $ 34,193 $ 62,662 $ 18,115 ============ ============ ============
Basic Earnings per Share: Reported net income $ 0.96 $ 1.75 $ 0.47
Net adjustment to income from change in accounting principle -- (0.01) -- ------------ ------------ ------------ Adjusted basic earnings per share $ 0.96 $ 1.74 $ 0.47 ============ ============ ============
Diluted Earnings per Share: Reported net income $ 0.95 $ 1.73 $ 0.47
Net adjustment to income from change in accounting principle -- -- (0.01) ------------ ------------ ------------ Adjusted diluted earnings per share $ 0.95 $ 1.73 $ 0.46 ============ ============ ============
If FAS 143 had been applied at January 1, 2000 and December 31, 2000, 2001 and 2002, the plugging liability would have been $8.0 million, $8.7 million, $9.7 million and $10.8 million, respectively, assuming the liability was measured using the information, assumptions and interest rates used as of the adoption date of January 1, 2003.
On January 17, 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate
the VIE. This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46, as amended, was effective for Unit in the fourth quarter of 2003 as it applies to entities created after February 1, 2003. The adoption of FIN 46 with respect to these entities, did not have an impact on Unit's financial position or results of operations. For entities created prior to February 1, 2003, which are not special purpose entities, as defined in FIN 46, Unit will have to adopt FIN 46, as amended, in the quarter ending March 31, 2004. Unit is still evaluating FIN 46 with regard to these types of entities in which it has an ownership interest, primarily oil and gas partnerships and its equity investment in Superior pipeline. FIN 46 may require full consolidation of these entities which would increase total assets with an offsetting minority interest for the percentage not owned by Unit. There will be no net impact to results of operations from the adoption of FIN 46.
Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June 2001 and became effective for Unit on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. Depending on how the accounting and disclosure literature is applied, oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract oil and natural gas reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the notes to the Unit's financial statements would include the disclosures required by FAS 141 and 142 regarding intangibles. To date, Unit, like many other oil and gas companies, has included oil and gas extraction rights as part of the oil and gas properties, even after FAS 141 and 142 became effective.
Unit's results of operations and cash flows would not be affected, since these oil and gas mineral extraction rights would continue to be amortized in accordance with full cost accounting rules.
At December 31, 2002 and 2003, Unit had undeveloped leaseholds of approximately $13.2 million and $14.8 million, respectively that would be classified on its balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $18.1 million and $24.6 million, respectively that would be classified as "intangible developed leasehold" if the interpretations were applied. This classification would require Unit to make the disclosures set forth under FAS 142 related to these interests.
Unit intends to continue to classify its oil and gas mineral extraction rights as tangible oil and gas properties until further guidance is provided.
NOTE 2 - ACQUISITIONS - ---------------------
On December 8, 2003, Unit acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the three years following the acquisition. The assets of SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and trailers, various other vehicles and a district office and equipment yard in and near Borger, Texas. The results of operations for the acquired entity are included in the statement of operations for the period beginning December 8, 2003 and continuing through December 31, 2003.
Total consideration given in the acquisition was determined based on the depth capacity of the rigs, the working condition of the rigs and the ability of the rigs to enhance Unit's ability to provide services and equipment required by our customers on a timely basis within the Anadarko Basin of Western Oklahoma and the Texas Panhandle. Unit acquired SerDrilco Incorporated's tax basis in the property acquired, so a deferred tax liability and goodwill of $10.9 million was recognized in the recording of the acquisition. The allocation of the total consideration paid and goodwill recognized for the acquisition is as follows (in thousands):
Allocation of Total Consideration Paid and Goodwill Recognized:
Drilling rigs including tubulars $ 31,012 Spare drilling equipment 904 Office, yard & yard equipment 1,200 Trucking fleet 1,486 Other vehicles 398 ---------- Total cash consideration 35,000
Goodwill recognized 10,928 ---------- Total consideration paid and recognized $ 45,928 ==========
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment Company and CDC Drilling Company ("Cactus Acquisition"). Both of these acquisitions were stock purchase transactions. Unit issued 6,819,748 shares of common stock and paid $3,813,053 for all the outstanding shares of CREC Rig Equipment Company and issued 400,252 shares of common stock and paid $686,947 for all the outstanding shares of CDC Drilling Company. The assets of the acquired companies included 20 drilling rigs, spare drilling equipment and vehicles. What we paid in both transactions was determined through arms-length negotiations between the parties and only the cash portion of the transaction appears in the investing and financing activities of Unit's Consolidated Statement of Cash Flows. The results of operations for the acquired entities are included in the statement of operations for the period beginning August 15, 2002 and continuing through December 31, 2003.
Total consideration given in both the acquisitions was determined based on the equipment purchased, depth capacity of the rigs, the working condition of the rigs and the ability of the rigs to enhance Unit's ability to provide services and equipment required by our customers on a timely basis within the Anadarko and Gulf Coast areas where the rigs are located. The calculation and allocation of the total consideration paid for the acquisition are as follows (in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock (7,220,000 shares at $16.96556 per share) $ 122,491 Cash 4,500 ---------- Total consideration $ 126,991 ==========
Allocation of Total Consideration Paid:
Drilling rigs $ 112,994 Spare drilling equipment 3,500 Vehicles 636 Deferred tax asset 2,155 Goodwill 7,706 ---------- Total consideration $ 126,991 ==========
Unaudited summary pro forma results of operations for Unit, reflecting the Cactus Acquisition as if it had occurred at the beginning of the year ended December 31, 2001 are as follow:
Year Ended Year Ended December 31, December 31, 2001 2002 -------------- -------------- (In thousands except per Per share amounts)
Revenues $ 311,104 $ 215,805 ============== ==============
Net Income $ 70,457 $ 15,320 ============== ==============
Net Income per Common Share (Diluted) $ 1.62 $ 0.34 ============== ==============
The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective periods nor of the results which may occur in the future.
NOTE 3 - EARNINGS PER SHARE - ---------------------------
The following data shows the amounts used in computing earnings per share.
Weighted Income Shares Per-Share (Numerator) (Denominator) Amount ------------- ------------- ---------- (In thousands except per share amounts)
For the Year Ended December 31, 2001: Basic earnings per common share $ 62,766 35,967 $ 1.75 ========== Effect of dilutive stock options 291 ------------- ------------- Diluted earnings per common share $ 62,766 36,258 $ 1.73 ============= ============= ==========
For the Year Ended December 31, 2002: Basic earnings per common share $ 18,244 38,844 $ 0.47 ========== Effect of dilutive stock options 268 ------------- ------------- Diluted earnings per common share $ 18,244 39,112 $ 0.47 ============= ============= ==========
Weighted Income Shares Per-Share (Numerator) (Denominator) Amount ------------- ------------- ---------- (In thousands except) per share amounts) For the Year Ended December 31, 2003: Basic earnings per common share: Income before change in accounting principle $ 48,864 43,616 $ 1.12 Cumulative effect of change in accounting principle net of income tax 1,325 43,616 0.03 ----------- ---------- Net Income $ 50,189 43,616 $ 1.15 =========== ========== Diluted earnings per common share: Weighted average number of common shares used in basic earnings per common share 43,616 Effect of dilutive stock options 157 ------------- Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share 43,773 ============= Income before change in accounting principle $ 48,864 43,773 $ 1.12 Cumulative effect of change in accounting principle net of income tax 1,325 43,773 0.03 ----------- ---------- Net Income $ 50,189 43,773 $ 1.15 =========== ==========
The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of common shares for the years ended December 31,:
2001 2002 2003 ---------- ---------- ---------- Options 153,000 198,500 137,850 ========== ========== ========== Average Exercise Price $ 16.79 $ 19.01 $ 22.52 ========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES - -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 2002 and 2003:
2002 2003 ---------- ---------- (In thousands) Revolving Credit and Term Loan, with Interest at December 31, 2002 and 2003 of 2.5% and 4.0%, Respectively $ 30,500 $ 400 Notes Payable for Hickman Drilling Company Acquisition with Interest at December 31, 2002 of 4.25% 1,000 -- ---------- ---------- 31,500 400 Less Current Portion 1,000 -- ---------- ---------- Total Long-Term Debt $ 30,500 $ 400 ========== ==========
At December 31, 2003, Unit had a $100 million bank loan agreement consisting of a revolving credit facility through May 1, 2005 and a term loan thereafter, maturing on May 1, 2008. On January 30, 2004, in conjunction with Unit's acquisition of PetroCorp Incorporated, Unit replaced its loan agreement with a revolving credit facility totaling $150 million having a four year term ending January 30, 2008. Borrowings under the new credit facility are limited to a commitment amount. Although, the current value of Unit's assets under the latest loan value computation supported a full $150 million, Unit elected to set the loan commitment at
$120 million in order to reduce financing costs. Unit pays a commitment fee of ..375 of 1% for any unused portion of the commitment amount. Unit paid origination, agency and syndication fees of $515,000 at the inception of the new agreement $40,000 of which will be paid annually and the remainder of the fees will be amortized over the 4 year life of the loan.
The borrowing base under the current credit facility is subject to a semi-annual re-determination on May 10 and November 10 of each year, beginning May 10, 2004. The calculation is based primarily on the sum of a percentage of the discounted future value of Unit's oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of Unit's drilling rig fleet, limited to $20 million, is added to the borrowing base. Provisions are also in the agreement which allow for one requested special re-determination of the borrowing base by either the lender or Unit between each scheduled re-determination date if conditions warrant such a request.
At Unit's election, any portion of the debt outstanding may be fixed at a Eurodollar Rate for 30, 60, 90 or 180 day terms. During any Eurodollar Rate funding period the outstanding principal balance of the note to which such Eurodollar Rate option applies may be repaid upon three days prior notice to the Administrative Agent. Interest on the Eurodollar Rate is computed at the Eurodollar Base Rate applicable for the interest period plus 1.00% tp 1.50% depending on the level of debt as a percentage of the total loan value and payable at the end of each term or every 90 days whichever is less. Borrowings not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty.
The loan agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year, . the incurrence of additional debt with certain very limited exceptions and . the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our property, except in favor of Unit's banks.
The loan agreement also requires that at the end of each quarter:
. consolidated net worth of at least $350 million, . a current ratio (as defined in the loan agreement) of not less than 1 to 1 and . a leverage ratio of long-term debt to consolidated EBITDA (as defined in the loan agreement) for the most recently ended rolling four fiscal quarters of no greater than 3.25 to 1.0.
Other long-term liabilities consisted of the following as of December 31, 2002 and 2003:
2002 2003 ---------- ---------- (In thousands)
Separation Benefit Plan $ 2,081 $ 2,545 Deferred Compensation Plan 1,391 1,829 Retirement Agreement 1,412 1,349 Gas Balancing Liability 1,020 1,191 Plugging Liability -- 11,994 ---------- ---------- 5,904 18,908 Less Current Portion 465 1,015 ---------- ---------- Total Other Long-Term Liabilities $ 5,439 $ 17,893 ========== ==========
Estimated annual principal payments under the terms of long-term debt and other long-term liabilities from 2004 through 2008 are $1,015,000, $606,000, $686,000, $841,000 and $679,000. Based on the borrowing rates currently available to Unit for debt with similar terms and maturities, long-term debt at December 31, 2003 approximates its fair value.
NOTE 5 - INCOME TAXES - ---------------------
A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income to Unit's effective income tax expense is as follows:
2001 2002 2003 ---------- ---------- ---------- (In thousands) Income Tax Expense Computed by Applying the Statutory Rate $ 34,538 $ 9,739 $ 27,213 State Income Tax, Net of Federal Benefit 2,859 834 2,333 Statutory Depletion and Other (1,484) (1,021) (659) ---------- ---------- ---------- Income tax expense $ 35,913 $ 9,552 $ 28,887 ========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at December 31, 2002 and 2003:
2002 2003 ----------- ----------- (In thousands) Deferred Tax Assets: Allowance for losses and nondeductible accruals $ 3,942 $ 9,972 Net operating loss carryforward 17,752 20,745 Statutory depletion carryforward 4,231 4,476 Alternative minimum tax credit carryforward 395 395 ----------- ----------- Gross deferred tax assets 26,320 35,588
Deferred Tax Liability: Depreciation, depletion and amortization (110,598) (159,990) ----------- ----------- Net deferred tax liability (84,278) (124,402)
Current Deferred Tax Asset 2,042 2,651 ----------- ----------- Non-Current - Deferred Tax Liability $ (86,320) $ (127,053) =========== ===========
Realization of the deferred tax asset is dependent on generating sufficient future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
At December 31, 2003, Unit has an excess statutory depletion carryforward of approximately $11,778,000, which may be carried forward indefinitely and is available to reduce future taxable income, subject to statutory limitations. At December 31, 2003, Unit has net operating loss carryforwards of approximately $54,591,000 which expire from 2019 to 2022.
NOTE 6 - EMPLOYEE BENEFIT AND COMPENSATION PLANS - ------------------------------------------------
In December 1984, the Board of Directors approved the adoption of an Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock were authorized for issuance under the Plan. On May 3, 1995, Unit's shareholders approved and amended the Plan to increase by 250,000 shares the aggregate number of shares of common stock that could be issued under the Plan. Under the terms of the Plan, bonuses may be granted to employees in either cash or stock or a combination thereof, and are payable in a lump sum or in annual installments subject to certain restrictions. No shares were issued under the Plan in 2001, 2002 and 2003.
Unit also has a Stock Option Plan (the "Option Plan"), which provides for the granting of options for up to 2,700,000 shares of common stock to officers and employees. The Option Plan permits the issuance of qualified or nonqualified stock options. Options granted typically become exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan is the fair market value of the common stock on the date of the grant.
Activity pertaining to the Stock Option Plan is as follows:
Weighted Number Average of Exercise Shares Price ----------- ---------- Outstanding at January 1, 2001 719,700 $ 6.87 Exercised (177,200) 3.13 Cancelled (10,400) 10.26 ----------- ---------- Outstanding at December 31, 2001 532,100 8.09 Granted 160,000 19.03 Exercised (59,400) 5.67 ----------- ---------- Outstanding at December 31, 2002 632,700 11.08 Granted 116,850 22.89 Exercised (202,900) 5.94 Cancelled (9,900) 15.41 ----------- ---------- Outstanding at December 31, 2003 536,750 $ 15.52 =========== ==========
Outstanding Options at December 31, 2003 --------------------------------------- Weighted Average Weighted Number Remaining Average Exercise of Contractual Exercise Prices Shares Life Price ----------------------- ----------- ----------- ----------- $ 3.00 - $ 4.00 99,600 3.8 years $ 3.52 $ 7.25 - $10.00 45,700 3.2 years $ 8.52 $11.31 - $14.06 3,500 5.8 years $ 13.28 $16.69 - $22.95 387,950 8.6 years $ 19.44
Exercisable Options At December 31, 2003 ------------------------ Weighted Number Average Exercise of Exercise Prices Shares Price ------------------------------------ ----------- ----------- $ 2.75 - $ 4.00 99,600 $ 3.52 $ 7.25 - $10.00 45,700 $ 8.52 $11.31 - $14.06 2,500 $ 12.96 $16.69 - $19.04 108,500 $ 17.49
Options for 329,300, 355,100 and 256,300 shares were exercisable with weighted average exercise prices of $6.25, $7.28 and $5.32 at December 31, 2001, 2002 and 2003, respectively.
In February and May 1992, the Board of Directors and shareholders, respectively, approved the Unit Corporation Non-Employee Directors' Stock Option Plan (the "Old Plan") and in February and May 2000, the Board of Directors and shareholders, respectively, approved the Unit Corporation 2000 Non-Employee Directors' Stock Option Plan (the "Directors' Plan"). Under the Directors' Plan, which replaced the Old Plan, an aggregate of 300,000 shares of Unit's common stock may be issued upon exercise of the stock options. Under the Old Plan, on the first business day following each annual meeting of stockholders of Unit, each person who was then a member of the Board of Directors of Unit and who was not then an employee of Unit or any of its subsidiaries was granted an option to purchase 2,500 shares of common stock. Under the Directors' Plan, commencing with the year 2000 annual meeting, the amount granted has been increased to 3,500 shares of common stock. The option price for each stock option is the fair market value of the common stock on the date the stock options are granted. No stock options may be exercised during the first six months of its term except in case of death and no stock options are exercisable after 10 years from the date of grant.
Activity pertaining to the Directors' Plan is as follows:
Weighted Number Average of Exercise Shares Price ----------- ---------- Outstanding at January 1, 2001 95,000 $ 7.03 Granted 17,500 17.54 Exercised (37,000) 6.80 ----------- ---------- Outstanding at December 31, 2001 75,500 9.58 Granted 21,000 20.10 Exercised (2,500) 1.75 ----------- ---------- Outstanding at December 31, 2002 94,000 12.14 Granted 21,000 20.46 Exercised (34,500) 7.73 ----------- ---------- Outstanding at December 31, 2003 80,500 $ 8.94 =========== ==========
Outstanding and Exercisable Options at December 31, 2003 --------------------------------------- Weighted Average Weighted Number Remaining Average Exercise of Contractual Exercise Prices Shares Life Price ----------------------- ----------- ----------- ----------- $ 2.88 - $ 3.75 2,500 0.4 years $ 2.88 $ 6.87 - $ 9.00 15,000 3.8 years $ 7.58 $12.19 - $17.54 21,000 7.0 years $ 15.76 $20.10 - $20.46 42,000 8.8 years $ 20.28
Under Unit's 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. Unit may match each employee's contribution, up to a specified maximum, in full or on a partial basis. Unit made discretionary contributions under the plan of 35,016, 87,452 and 61,175 shares of common stock and recognized expense of $1,082,000, $1,079,000 and $1,365,000 in 2001, 2002 and 2003, respectively.
Unit provides a salary deferral plan ("Deferral Plan") which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. Funds set aside in a trust to satisfy Unit's obligation under the Deferral Plan at December 31, 2001, 2002 and 2003 totaled $1,277,000, $1,391,000 and $1,829,000, respectively. Unit recognizes payroll expense and records a liability at the time of deferral.
Effective January 1, 1997, Unit adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with Unit is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with Unit up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against Unit in exchange for receiving the separation benefits. On October 28, 1997, Unit adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Unit recognized expense of $589,000, $619,000 and $707,000 in 2001, 2002 and 2003, respectively, for benefits associated with anticipated payments from both separation plans.
Unit has entered into key employee change of control contracts with six of its current executive officers. These severance contracts have an initial three-year term that is automatically extended for one year upon each anniversary, unless a notice not to extend is given by Unit. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive's terms and conditions for employment (including position, work location, compensation and benefits) will not be adversely changed during the three-year period after a change of control. If the executive's employment is terminated (other than for cause, death or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and upon certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive's base salary
plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company's 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES - ------------------------------------------
Unit Petroleum Company serves as the general partner of 10 oil and gas limited partnerships. Four were formed for investment by third parties and six (the employee partnerships) were formed to allow employees of Unit and its subsidiaries and directors of Unit to participate in Unit Petroleum's oil and gas exploration and production operations. The partnerships for the third party investments were formed in 1984, 1985 and 1986. An additional third party partnership, the 1979 Oil and Gas Limited Partnership was dissolved on July 1, 2003. Employee partnerships have been formed for each year beginning with 1984. Interests in the employee partnerships were offered to the employees of Unit and its subsidiaries whose annual base compensation was at least a specified amount ($22,680 for 2002 and 2003 and $36,000 for 2004) and to the directors of Unit.
The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships at the end of last year was done by the general partners under the authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent.
Amounts received in the years ended December 31 from both public and private Partnerships for which Unit is a general partner are as follows:
2001 2002 2003 --------- --------- --------- (In thousands) Contract Drilling $ 416 $ 209 $ 428 Well Supervision and Other Fees $ 498 $ 510 $ 236 General and Administrative Expense Reimbursement $ 193 $ 210 $ 209
Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party's behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party's level of activity and are considered by management to be reasonable.
A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary is the general partner, $3,000, $1,000 and $2,000 during the years ended December 31, 2001, 2002 and 2003, respectively, for purchases of natural gas production.
Unit owns a 40% equity interest in Superior Pipeline Company LLC, an Oklahoma Limited Liability Company. Superior is a natural gas gathering and processing company. The investment, including Unit's share of the equity in the earnings of this company, totaled $3.0 million at December 31, 2003 and is reported in other assets in Unit's consolidated balance sheet. During 2003, Superior Pipeline Company LLC purchased $3.3 million of our natural gas production and paid $64,000 for our natural gas liquids. We paid this company $39,000 for gathering and compression services.
Unit also owns a 16.7% limited partnership interest in Eagle Energy Partnership I, L.P. ("Eagle"), carried at cost, for $2.5 million. Eagle is engaged in the purchase and sale of natural gas, electricity (or similar electricity based products), future commodities, and the performance of scheduling and nomination services for both energy related commodities and similar energy management functions. Total purchases by Eagle Energy Partnership I, L.P., which are competitively marketed, accounted for 6% of Unit's oil and natural gas revenues in 2003. Unit increased its sales to Eagle Energy Partners I LP since it first starting selling natural gas to them in August, 2003. For the period August through December 2003 Eagle has purchased 16% of Unit's oil and natural gas revenues.
NOTE 8 - SHAREHOLDER RIGHTS PLAN - --------------------------------
Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of Unit without offering fair value to all shareholders and to deter other abusive takeover tactics, which are not in the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from Unit one one-hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by Unit or to purchase from an acquiring company certain shares of its common stock or the surviving company's common stock at 50% of its value.
The rights become exercisable 10 days after Unit learns that an acquiring person (as defined in the Plan) has acquired 15% or more of the outstanding common stock of Unit or 10 business days after the commencement of a tender offer, which would result in a person owning 15% or more of such shares. Unit can redeem the rights for $0.01 per right at any date prior to the earlier of (i) the close of business on the 10th day following the time Unit learns that a person has become an acquiring person or (ii) May 19, 2005 (the "Expiration Date"). The rights will expire on the Expiration Date, unless redeemed earlier by Unit.
NOTE 9 - COMMITMENTS AND CONTINGENCIES - --------------------------------------
Unit leases office space in Tulsa and Woodward Oklahoma and Houston Texas under the terms of operating leases expiring through January 31, 2010. Future minimum rental payments under the terms of the leases are approximately $719,000, $710,000, $714,000, $531,000 and $423,000 in 2004, 2005, 2006, 2007 and 2008, respectively. Total rent expense incurred by the Company was $582,000, $678,000 and $752,000 in 2001, 2002 and 2003, respectively.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with the employee oil and gas limited partnerships require, upon the election of a limited partner, that Unit repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20% of the units outstanding. Unit made repurchases of $1,000 and $106,000 in 2002 and 2003, respectively, for such limited partners' interests. No repurchases were made in 2001. In 2001, Unit paid $15,000 for interests in two of the Questa limited partnerships and subsequently dissolved one of the Questa partnerships.
Unit manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a company-wide basis, to identify changes in its environmental risk profile. These reviews
evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to Unit's satisfaction, or agree to assume liability for the remediation of the property.
We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the rig is on the location and the cost has been included in the direct cost of drilling the well.
Unit is a party to various legal proceedings arising in the ordinary course of its business none of which, in management's opinion, will result in judgments which would have a material adverse effect on Unit's financial position, operating results or cash flows.
NOTE 10 - INDUSTRY SEGMENT INFORMATION - --------------------------------------
Unit has two business segments: Contract Drilling and Oil and Natural Gas, representing its two main business units offering different products and services. The Contract Drilling segment provides land contract drilling of oil and natural gas wells and the Oil and Natural Gas segment is engaged in the development, acquisition and production of oil and natural gas properties.
The accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (Note 1). Management evaluates the performance of Unit's operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. Unit has natural gas production in Canada, which is not significant.
2001 2002 2003 ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 169,301 $ 119,014 $ 188,832 Elimination of intersegment revenue 2,259 841 5,686 ---------- ---------- ---------- Contract drilling net of intersegment revenue 167,042 118,173 183,146 Oil and natural gas 90,237 67,959 116,609 Other 1,900 1,504 2,829 ---------- ---------- ---------- Total revenues $ 259,179 $ 187,636 $ 302,584 ========== ========== ========== Operating Income (1): Contract drilling $ 62,148 $ 12,151 $ 20,740 Oil and natural gas 45,925 23,826 64,097 ---------- ---------- ---------- Total operating income 108,073 35,977 84,837
General and administrative expense (8,476) (8,712) (9,222) Interest expense (2,818) (973) (693) Other income (expense)- net 1,900 1,504 2,829 ---------- ---------- ---------- Income before income taxes $ 98,679 $ 27,796 $ 77,751 ========== ========== ========== Identifiable Assets (2): Contract drilling $ 183,471 $ 299,655 $ 364,855 Oil and natural gas 220,476 261,440 327,172 ---------- ---------- ---------- Total identifiable assets 403,947 561,095 692,027 Corporate assets 13,306 17,068 20,898 ---------- ---------- ---------- Total assets $ 417,253 $ 578,163 $ 712,925 ========== ========== ==========
2001 2002 2003 ---------- ---------- ---------- (In thousands) Capital Expenditures: Contract drilling $ 51,280 $ 139,298 (3) $ 71,899 (4) Oil and natural gas 56,933 58,778 80,883 (5) Other 539 516 3,940 ---------- ---------- ---------- Total capital expenditures $ 108,752 $ 198,592 $ 156,722 ========== ========== ========== Depreciation, Depletion, Amortization and Impairment: Contract drilling $ 13,888 $ 14,684 $ 23,644 Oil and natural gas 22,116 23,338 27,343 Other 638 635 796 ---------- ---------- ---------- Total depreciation, depletion, amortization and impairment $ 36,642 $ 38,657 $ 51,783 ========== ========== ==========
- ---------------------- (1) Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization and impairment and does not include non-operating revenues, general corporate expenses, interest expense or income taxes.
(2) Identifiable assets are those used in Unit's operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment.
(3) Includes $7.7 million for goodwill and $2.2 million for deferred tax assets.
(4) Includes $10.9 million for goodwill.
(5) Includes $7.6 million for capitalized cost relating to plugging liability recorded in 2003.
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - --------------------------------------------------------------
Summarized quarterly financial information for 2002 and 2003 is as follows:
Three Months Ended --------------------------------------------------- March 31 June 30 September 30 December 31 ----------- ----------- ------------ ----------- (In thousands except per share amounts) Year Ended December 31, 2002: Revenues $ 38,730 $ 44,753 $ 48,272 $ 55,881 =========== =========== ============ =========== Gross profit(1) $ 6,515 $ 10,295 $ 8,107 $ 11,060 =========== =========== ============ =========== Income before income taxes $ 4,254 $ 8,297 $ 6,022 $ 9,223 =========== =========== ============ =========== Net income(2) $ 2,642 $ 5,108 $ 3,708 $ 6,786 =========== =========== ============ =========== Earnings per common share: Basic (3) $ 0.07 $ 0.14 $ 0.09 $ 0.16 =========== =========== ============ =========== Diluted (4) $ 0.07 $ 0.14 $ 0.09 $ 0.16 =========== =========== ============ =========== Year Ended December 31, 2003: Revenues $ 68,446 $ 72,980 $ 78,201 $ 82,957 =========== =========== ============ =========== Gross profit(1) $ 22,447 $ 20,214 $ 22,251 $ 19,925 =========== =========== ============ =========== Income before income taxes and change in accounting principle $ 20,418 $ 18,857 $ 20,598 $ 17,878 =========== =========== ============ =========== Income before change in accounting principle $ 12,659 $ 11,691 $ 12,763 $ 11,751 =========== =========== ============ =========== Net Income(2) $ 13,984 $ 11,691 $ 12,763 $ 11,751 =========== =========== ============ ===========
Three Months Ended --------------------------------------------------- March 31 June 30 September 30 December 31 ----------- ----------- ------------ ----------- (In thousands except per share amounts) Earnings Before Change in Accounting Principle per Common Share: Basic $ 0.29 $ 0.27 $ 0.29 $ 0.27 =========== =========== ============ =========== Diluted $ 0.29 $ 0.27 $ 0.29 $ 0.27 =========== =========== ============ ===========
Net Income per Common Share: Basic $ 0.32 $ 0.27 $ 0.29 $ 0.27 =========== =========== ============ =========== Diluted $ 0.32 $ 0.27 $ 0.29 $ 0.27 =========== =========== ============ ===========
- ------------------ (1) Gross profit excludes other revenues, general and administrative expense and interest expense.
(2) The net income for the three months ended December 31, 2002 and 2003 includes a tax benefit of $1.1 million and $0.8 million, respectively, relating primarily to an increase in the estimated amount of statutory depletion carryforward.
(3) Due to the effect of rounding basic earnings per share for the year's four quarters does not equal the annual earnings per share.
(4) Due to the effect of price changes of Unit's stock, diluted earnings per share for the year's four quarters, which includes the effect of potential dilutive common shares calculated during each quarter, does not equal the annual diluted earnings per share, which includes the effect of such potential dilutive common shares calculated for the entire year.
NOTE 12 - SUBSEQUENT EVENT - --------------------------
On January 30, 2004 Unit acquired the outstanding common stock of PetroCorp Incorporated for $182.1 million in cash. PetroCorp Incorporated explored and developed oil and natural gas properties primarily in Texas and Oklahoma. Approximately 84% of the oil and natural gas properties acquired in the acquisition are located in the Mid-Continent and Permian basins, while 6% are located in the Rocky Mountains and 10% are located in the Gulf Coast basin. The acquired properties increased Unit's reserve base by approximately 56.7 billion equivalent cubic feet of natural gas and provide additional locations for development drilling in the future. With the acquisition of PetroCorp Incorporated, Unit also entered into a new $150 million credit facility to replace its existing loan agreement as more fully discussed in Note 4.
The preliminary allocation of the total consideration paid for the acquisition is as follows (in thousands):
Working Capital $ 93,668 Undeveloped Oil and Natural Gas Properties 6,557 Proved Oil and Natural Gas Properties 114,518 Property and Equipment - Other 401 Other Assets 1,499 Other Long-Term Liabilities (5,557) Deferred Income Taxes (net) (28,966) ---------- Total consideration $ 182,120 ==========
Unaudited summary pro forma results of operations for Unit, reflecting the above described acquisition as if it had occurred at the beginning of the year ended December 31, 2002 and December 31, 2003, are as follows, respectively; revenues, $217.0 million and $339.6 million; income from continuing operations of $19.5 million and $55.2 million; net income of $19.5 million and $53.5 million; income from continuing operations per common share (diluted) of $0.50 and $1.26 and net income per common shares (diluted) of $0.50 and $1.22. The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective period nor of the results which may occur in the future.
NOTE 13 - OIL AND NATURAL GAS INFORMATION - -----------------------------------------
The capitalized costs at year end and costs incurred during the year were as follows:
USA Canada Total ----------- --------- ----------- (In thousands) 2001: Capitalized costs: Proved properties $ 391,216 $ 888 $ 392,104 Unproved properties 14,207 180 14,387 ----------- --------- ----------- 405,423 1,068 406,491 Accumulated depreciation, depletion, amortization and impairment (196,270) (475) (196,745) ----------- --------- ----------- Net capitalized costs $ 209,153 $ 593 $ 209,746 =========== ========= =========== Cost incurred: Unproved properties acquired $ 7,503 $ 21 $ 7,524 Proved properties acquired 1,419 -- 1,419 Exploration 9,336 -- 9,336 Development 38,359 295 38,654 ----------- --------- ----------- Total costs incurred $ 56,617 $ 316 $ 56,933 =========== ========= =========== 2002: Capitalized costs: Proved properties $ 448,331 $ 895 $ 449,226 Unproved properties 15,692 332 16,024 ----------- --------- ----------- 464,023 1,227 465,250 Accumulated depreciation, depletion, amortization and impairment (218,956) (520) (219,476) ----------- --------- ----------- Net capitalized costs $ 245,067 $ 707 $ 245,774 =========== ========= =========== Cost incurred: Unproved properties acquired $ 5,330 $ 152 $ 5,482 Proved properties acquired 13,379 -- 13,379 Exploration 6,591 -- 6,591 Development 33,319 7 33,326 ----------- --------- ----------- Total costs incurred $ 58,619 $ 159 $ 58,778 =========== ========= ===========
USA Canada Total ----------- --------- ----------- (In thousands) 2003: Capitalized costs: Proved properties $ 527,196 $ 914 $ 528,110 Unproved properties 17,149 337 17,486 ----------- --------- ----------- 544,345 1,251 545,596 Accumulated depreciation, depletion, amortization and impairment (240,047) (540) (240,587) ----------- --------- ----------- Net capitalized costs $ 304,298 $ 711 $ 305,009 =========== ========= =========== Cost incurred: Unproved properties acquired $ 8,611 $ 19 $ 8,630 Proved properties acquired 2,557 -- 2,557 Exploration 7,071 -- 7,071 Development(1) 62,620 5 62,625 ----------- --------- ----------- Total costs incurred $ 80,859 $ 24 $ 80,883 =========== ========= ===========
- ---------------- (1) Includes $7.0 million of capitalized cost for plugging liability recorded in the first quarter of 2003 for wells drilled in prior years.
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2003, by the year in which such costs were incurred.
and Prior 2001 2002 2003 Total --------- --------- --------- --------- --------- (In thousands) Undeveloped Leasehold Acquired $ 3,341 $ 3,272 $ 3,187 $ 7,686 $ 17,486 ========= ========= ========= ========= =========
The results of operations for producing activities are provided below.
USA Canada Total ----------- --------- ----------- (In thousands) 2001: Revenues $ 86,810 $ 190 $ 87,000 Production costs (18,636) (23) (18,659) Depreciation, depletion and amortization (19,756) (40) (19,796) ----------- --------- ----------- 48,418 127 48,545 Income tax expense (17,621) (40) (17,661) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 30,797 $ 87 $ 30,884 =========== ========= ===========
2002: Revenues $ 64,534 $ 87 $ 64,621 Production costs (17,300) (25) (17,325) Depreciation, depletion and amortization (22,685) (45) (22,730) ----------- --------- ----------- 24,549 17 24,566 Income tax expense (8,436) (5) (8,441) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 16,113 $ 12 $ 16,125 =========== ========= ===========
2003: Revenues $ 114,398 $ 171 $ 114,569 Production costs (21,366) (21) (21,387) Depreciation, depletion and amortization (27,059) (20) (27,079) ----------- --------- ----------- 65,973 130 66,103 Income tax expense (24,508) (41) (24,549) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 41,465 $ 89 $ 41,554 =========== ========= ===========
Estimated quantities of proved developed oil and natural gas reserves and changes in net quantities of proved developed and undeveloped oil and natural gas reserves were as follows (unaudited):
USA Canada Total ---------------- ---------------- ---------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas Bbls Mcf Bbls Mcf Bbls Mcf ------- -------- ------- -------- ------- -------- (In thousands) 2001: Proved developed and undeveloped reserves: Beginning of year 4,183 215,196 -- 441 4,183 215,637 Revision of previous estimates (214) (24,253) -- (7) (214) (24,260) Extensions, discoveries and other additions 861 54,521 -- -- 861 54,521 Purchases of minerals in place 8 1,246 -- -- 8 1,246 Sales of minerals in place (3) (26) -- -- (3) (26) Production (492) (18,819) -- (45) (492) (18,864) ------- -------- ------- -------- ------- -------- End of Year 4,343 227,865 -- 389 4,343 228,254 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 3,222 162,718 -- 389 3,222 163,107 End of year 2,753 150,419 -- 338 2,753 150,757
2002: Proved developed and undeveloped reserves: Beginning of year 4,343 227,865 -- 389 4,343 228,254 Revision of previous estimates (166) (10,543) -- (31) (166) (10,574) Extensions, discoveries and other additions 230 29,541 -- -- 230 29,541 Purchases of minerals in place 192 16,558 -- -- 192 16,558 Sales of minerals in place (30) -- -- -- (30) -- Production (473) (18,927) -- (41) (473) (18,968) ------- -------- ------- -------- ------- -------- End of Year 4,096 244,494 -- 317 4,096 244,811 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 2,753 150,419 -- 338 2,753 150,757 End of year 2,951 168,049 -- 317 2,951 168,366
USA Canada Total ---------------- ---------------- ---------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas Bbls(1) Mcf Bbls Mcf Bbls Mcf ------- -------- ------- -------- ------- -------- (In thousands) 2003: Proved developed and undeveloped reserves: Beginning of year 4,096 244,494 -- 317 4,096 244,811 Revision of previous estimates 629 (10,510) -- 371 629 (10,139) Extensions, discoveries and other additions 1,000 39,762 -- -- 1,000 39,762 Purchases of minerals in place 8 437 -- -- 8 437 Sales of minerals in place (76) (31) -- -- (76) (31) Production (516) (20,610) -- (38) (516) (20,648) ------- -------- ------- -------- ------- -------- End of Year 5,141 253,542 -- 650 5,141 254,192 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 2,951 168,049 -- 317 2,951 168,366 End of year 3,984 182,203 -- 650 3,984 128,853
- ---------------------- (1) Oil includes natural gas liquids in barrels.
Oil and natural gas reserves cannot be measured exactly. Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in connection with financial disclosures. Unit utilizes Ryder Scott Company, independent petroleum consultants, to review its reserves as prepared by its reservoir engineers.
Proved oil and gas reserves, as defined in SEC Rule 4-10(a), are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:
. that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
. the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following:
. oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
. crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
. crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
. crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data as previously explained. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth herein is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves nor of estimated future cash flows.
The standardized measure of discounted future net cash flows ("SMOG") was calculated using year-end prices and costs, and year-end statutory tax rates, adjusted for permanent differences, that relate to existing proved oil and natural gas reserves. SMOG as of December 31 is as follows (unaudited):
USA Canada Total ----------- --------- ----------- (In thousands) 2001: Future cash flows $ 676,051 $ 975 $ 677,026 Future production costs (220,590) (311) (220,901) Future development costs (58,909) (30) (58,939) Future income tax expenses (94,037) (134) (94,171) ----------- --------- ----------- Future net cash flows 302,515 500 303,015
10% annual discount for estimated timing of cash flows (125,238) (194) (125,432) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 177,277 $ 306 $ 177,583 =========== ========= ===========
2002: Future cash flows $1,256,434 $ 1,400 $1,257,834 Future production costs (320,940) (309) (321,249) Future development costs (65,266) -- (65,266) Future income tax expenses (250,413) (233) (250,646) ----------- --------- ----------- Future net cash flows 619,815 858 620,673 10% annual discount for estimated timing of cash flows (275,015) (344) (275,359) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 344,800 $ 514 $ 345,314 =========== ========= ===========
2003: Future cash flows $1,548,785 $ 3,500 $1,552,285 Future production costs (418,007) (581) (418,588) Future development costs (72,891) -- (72,891) Future income tax expenses (313,827) (805) (314,632) ----------- --------- ----------- Future net cash flows 744,060 2,114 746,174
10% annual discount for estimated timing of cash flows (325,182) (738) (325,920) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 418,878 $ 1,376 $ 420,254 =========== ========= ===========
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows (unaudited):
USA Canada Total ----------- --------- ----------- (In thousands) 2001: Sales and transfers of oil and natural gas produced, net of production costs $ (68,174) $ (167) $ (68,341) Net changes in prices and production costs (768,295) (1,600) (769,895) Revisions in quantity estimates and changes in production timing (32,705) 13 (32,692) Extensions, discoveries and improved recovery, less related costs 54,127 -- 54,127 Changes in estimated future development cost 2,673 -- 2,673 Previously estimated cost incurred during the period 7,361 -- 7,361 Purchases of minerals in place 1,217 -- 1,217 Sales of minerals in place (220) -- (220) Accretion of discount 99,953 205 100,158 Net change in income taxes 271,421 524 271,945 Other - net (64,668) (108) (64,776) ----------- --------- ----------- Net change (497,310) (1,133) (498,443) Beginning of year 674,587 1,439 676,026 ----------- --------- ----------- End of year $ 177,277 $ 306 $ 177,583 =========== ========= =========== 2002: Sales and transfers of oil and natural gas produced, net of production costs $ (47,230) $ (62) $ (47,292) Net changes in prices and production costs 230,934 363 231,297 Revisions in quantity estimates and changes in production timing (49,000) (110) (49,110) Extensions, discoveries and improved recovery, less related costs 60,957 -- 60,957 Changes in estimated future development cost 1,743 -- 1,743 Previously estimated cost incurred during the period 9,911 30 9,941 Purchases of minerals in place 23,334 -- 23,334 Sales of minerals in place (150) -- (150) Accretion of discount 23,080 39 23,119 Net change in income taxes (84,843) (59) (84,902) Other - net (1,213) 7 (1,206) ----------- --------- ----------- Net change 167,523 208 167,731 Beginning of year 177,277 306 177,583 ----------- --------- ----------- End of year $ 344,800 $ 514 $ 345,314 =========== ========= ===========
USA Canada Total ----------- --------- ----------- (In thousands) 2003: Sales and transfers of oil and natural gas produced, net of production costs $ (93,948) $ (150) $ (94,098) Net changes in prices and production costs 65,611 195 65,806 Revisions in quantity estimates and changes in production timing (14,637) 1,007 (13,630) Extensions, discoveries and improved recovery, less related costs 113,421 -- 113,421 Changes in estimated future development cost (5,356) -- (5,356) Previously estimated cost incurred during the period 15,664 -- 15,664 Purchases of minerals in place 881 -- 881 Sales of minerals in place (837) -- (837) Accretion of discount 48,317 66 48,383 Net change in income taxes (38,950) (386) (39,336) Other - net (16,088) 130 (15,958) ----------- --------- ----------- Net change 74,078 862 74,940 Beginning of year 344,800 514 345,314 ----------- --------- ----------- End of year $ 418,878 $ 1,376 $ 420,254 =========== ========= ===========
Unit's SMOG and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. Management believes such information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect management's expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of management's control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end spot prices of oil $32.52 and natural gas $5.67 relating to proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil and natural gas reserves less the tax basis of Unit's properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to Unit's proved oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.
REPORT OF INDEPENDENT AUDITORS
The Shareholders and Board of Directors Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, changes in shareholders' equity and cash flows present fairly in all material respects, the financial position of Unit Corporation and its subsidiaries at December 31, 2002 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States of America which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted the requirements of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."
PricewaterhouseCoopers LLP
Tulsa, Oklahoma February 18, 2004
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and - ------- --------------------------------------------------------------- Financial Disclosure. ---------------------
None.
Item 9a.
Item 9a. Controls and Procedures. - -------- -------------------------
(a) Evaluation of Disclosure Controls and Procedures
The company maintains "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act"), that are designed to ensure that information required to be disclosed in reports the company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is collected and communicated to management, including the company's Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The company's disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards. Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the company's disclosure controls and procedures were effective to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to them by others within those entities.
(b) Changes in Internal Control Over Financial Reporting
As of the last quarter, there were no changes in the company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant - -------- --------------------------------------------------
The information regarding Directors and Executive Officers appearing under the headings "Item 1: Election of Directors", and "Other Matters" of our 2004 Proxy Statement is incorporated by reference in this section. The information under the heading "Executive Officers" in Items 1 and 2 of this Form 10-K is also incorporated by reference in this section.
Item 11.
Item 11. Executive Compensation - -------- ----------------------
The information appearing under the headings "Directors' Compensation and Benefits", "Executive Compensation", "Termination of Employment & Change in Control Arrangements", "Compensation Committee Interlocks and Insider Participation" and "Report of the Compensation Committee" of our 2004 Proxy Statement is incorporated by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management - -------- -------------------------------------------------------------- and Related Stockholder Matters -------------------------------
The information appearing under the heasding "Ownership of Our Common Stock by Beneficial Owners and Management" of our 2004 Proxy Statement is incorporated by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions - -------- ----------------------------------------------
The information appearing under the heading "Other Matters" of our 2004 Proxy Statement is incorporated by reference.
ITEM 14.
ITEM 14. Principal Accounting Fees and Services. - -------- ---------------------------------------
The information appearing under the headings "Report of Audit Committee", "Principal Accounting Fees and Services" and "Ratification of Appointment of Auditors" of our 2004 Proxy Statement is incorporated by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on - -------- ------------------------------------------------------ Form 8-K --------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements: ---------------------
Included in Part II of this report: Consolidated Balance Sheets as of December 31, 2002 and 2003 Consolidated Statements of Income for the years ended December 31, 2001, 2002 and 2003 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2001, 2002 and 2003 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2002 and 2003 Notes to Consolidated Financial Statements Report of Independent Auditors
2. Financial Statement Schedules: ------------------------------ Included in Part IV of this report for the years ended December 31, 2001, 2002 and 2003: Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of Item 601 of Regulation S-K.
3. Exhibits: --------
2.6.1 Amended and Restated Stock Purchase Agreement dated as of June 24, 2002 by and among Unit Corporation, George B. Kaiser and Kaiser Francis Oil Company (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated August 27,2002).
2.6.2 Amended and Restated Share Purchase Agreement dated as of June 24, 2002, by and among Unit Corporation, Kaiser Francis Charitable Income Trust B and Kaiser Francis Oil Company (incorporated herein by reference to Exhibit 99.2 to Form 8-K dated August 27, 2002).
3.1 Restated Certificate of Incorporation of Unit Corporation (filed as Exhibit 3.1 to Form S-3 (file No. 333-83551), which is incorporated herein by reference).
3.2 By-Laws of Unit Corporation (filed as Exhibit 3.2 to Unit's Form 8-K to Form S-3 (file No. 333-83551), which is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.1 on Form S-3 as S.E.C. File No. 333-83551, which is incorporated herein by reference).
4.2.6 Rights Agreement between Unit Corporation and Chemical Bank, as Rights Agent (filed as Exhibit 1 to Unit's Form 8-A filed with the S.E.C. on May 23, 1995, File No. 1-92601 and incorporated herein by reference).
4.2.7 First Amendment of Rights Agreement dated May 19, 1995, between the Company and Mellon Shareholder Services LLC, as Rights Agent (filed as Exhibit 4 to Unit's Form 8-K dated August 23, 2001, which is incorporated herein by reference).
4.2.8 Second Amendment of the Rights Agreement, dated August 14, 2002, between the Company and Mellon Shareholder Services LLC, as Rights Agent (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 2002, which is incorporated herein by reference).
4.3 Indenture (filed as Exhibit 4.3 to Unit's Form S-3 filed with the S.E.C. File No. 333-104165, which is incorporated herein by reference).
10.1.26 Loan Agreement dated January 30, 2004 (filed herein).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and Exploration Company's Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's Registration Statement Form S-1 as S.E.C. File No. 2-92582, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as Exhibit 10.16 to Unit's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference).
10.2.22* The Company's Amended and Restated Stock Option Plan (filed as an Exhibit to Unit's Registration Statement on Form S-8 as S.E.C. File No's. 33-19652, 33-44103 and 33-64323 which is incorporated herein by reference).
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-49724, which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership Agreement. (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
10.2.30* Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1996, which is incorporated herein by reference).
10.2.32* Unit Corporation Separation Benefit Plan for Senior Management (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended September 30, 1997, which is incorporated herein by reference).
10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1999).
10.2.36* Unit Corporation 2000 Non-Employee Directors' Stock Option Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 333-38166, which is incorporated herein by reference).
10.2.37* Unit Corporation's Amended and Restated Stock Option Plan (filed as an Exhibit to Unit's Registration Statement on Form S-8 as S.E.C. File No. 333-39584 which is incorporated herein by reference).
10.2.38 Unit 2001 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 2000).
10.2.39* Form of Unit Corporation Key Employee Change of Control Contract entered into with certain of Unit's officers (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 2000).
10.2.40 Form of Indemnification Agreement entered into between the Company and its executive officers and directors (filed as Exhibit 10 to Unit's Form 8-K dated August 23, 2001, which is incorporated herein by reference).
10.2.41 Unit 2002 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 2001).
10.2.42 Unit 2003 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 2002).
10.2.43 Unit 2004 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed herein).
21 Subsidiaries of the Registrant (filed herein).
23.1 Consent of Independent Accountants (filed herein).
23.2 Consent of Independent Petroleum Engineers (filed herein).
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a) of the Exchange Act (filed herein).
31.2 Certification of Chief Financial Officer under Rule 13a -14(a) of the Exchange Act (filed herein).
32.1 Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a-14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002 (filed herein).
99.2 Separation Agreement, dated May 11, 2001, between the Registrant and Mr. Kirchner (filed as Exhibit 99.A4 to Unit's Form 8-K dated May 18, 2001, which is incorporated herein by reference).
* Indicates a management contract or compensatory plan identified pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
On October 22, 2003, we filed a report on Form 8-K under items 7 and 12. This report announced our results of operations and financial condition for the quarter ended September 30, 2003. The press release regarding this announcement was furnished as an exhibit.
On October 27, 2003, we filed a report on Form 8-K under items 5 and 7. This report announced that our Board of Directors has elected Mr. Mark E. Monroe to the Company's Board of Directors. The press release regarding this announcement was furnished as an exhibit.
On November 21, 2003, we filed a report on Form 8-K under items 5 and 7. This report announced that we signed an agreement to acquire Serdrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, a U.S. land drilling company located in Borger, Texas, for $35.0 million in cash and an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the next three years. The press release regarding this announcement was furnished as an exhibit.
On December 8, 2003, we filed a report on Form 8-K under items 7 and 9. This report announced the completion of the acquisition of SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC. We also announced we intend to offer 2 million shares of our common stock pursuant to an effective shelf registration statement filed with the Securities and Exchange Commission. The press releases regarding both of the announcements were furnished as exhibits.
On December 9, 2003, we filed a report on Form 8-K/A under item 7. This report updated the proforma financial statements related to the acquisition of CREC Rig Acquisition Company LLC and CDC Drilling Company.
On December 10, 2003, we filed a report on Form 8-K under items 7 and 9. This report announced that the previously announced public offering of 2 million shares of our common stock was priced at $22.00 per share and we anticipate the transaction will close on December 15, 2003. The press release regarding this announcement was furnished as an exhibit.
On December 11, 2003, we filed a report on Form 8-K under items 5 and 7. This report filed exhibits in connection with a prospectus supplement relating to the issuance and sale in an underwritten public offering of 2,000,000 shares of the Company's common stock.
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance Balance at Charged to Deductions at Beginning Costs & & Net End of Description of Period Expenses Write-Offs Period ----------- ---------- ---------- ---------- ---------- (In thousands) Year ended December 31, 2001 $ 919 $ -- $ 315 $ 604 ========== ========== ========== ========== Year ended December 31, 2002 $ 604 $ 603 $ 4 $ 1,203 ========== ========== ========== ========== Year ended December 31, 2003 $ 1,203 $ 645 $ 625 $ 1,223 ========== ========== ========== ==========
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 10, 2004 By: /s/ John G. Nikkel ----------------- --------------------------- JOHN G. NIKKEL Chief Executive Officer (Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 10th day of March, 2004. Name Title - ------------------------------- -----------------------------------
/s/ John G. Nikkel - ------------------------------- Chairman of the Board and Chief JOHN G. NIKKEL Executive Officer (Principal Executive Officer)
/s/ Larry D. Pinkston - ------------------------------- Director, President, Chief LARRY D. PINKSTON Operating Officer
/s/ David T. Merrill - ------------------------------- Chief Financial Officer and DAVID T. MERRILL Treasurer (Principal Financial Officer)
/s/ Stanley W. Belitz - ------------------------------- Controller (Principal Accounting STANLEY W. BELITZ Officer)
/s/ J. Michael Adcock - ------------------------------- Director J. MICHAEL ADCOCK
/s/ Don Cook - ------------------------------- Director DON COOK
/s/ King P. Kirchner - ------------------------------- Director KING P. KIRCHNER
/s/ Mark E. Monroe - ------------------------------- Director MARK E. MONROE
/s/ William B. Morgan - ------------------------------- Director WILLIAM B. MORGAN
/s/ John H. Williams - ------------------------------- Director JOHN H. WILLIAMS
/s/ John S. Zink - ------------------------------- Director JOHN S. ZINK
EXHIBIT INDEX ----------------------- Exhibit No. Description Page ---------- ------------------------------------------- ----
10.1.26 Loan Agreement dated January 30, 2004.
10.2.43 Unit 2004 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23.1 Consent of Independent Accountants.
23.2 Consent of Independent Petroleum Engineers.
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a) of the Exchange Act.
31.2 Certification of Chief Financial Officer under Rule 13a -14(a) of the Exchange Act.
32.1 Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a-14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.