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 2000.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder - ------- ------------------------------------------------------------------ Matters -------
Our common stock is traded on the New York Stock Exchange under the symbol "UNT." The following table sets forth the high and low sale prices per share of our common stock as reported in the New York Stock Exchange composite transactions, for the periods indicated:
1999 2000 ------------------------- ------------------------- QUARTER High Low High Low ------- ----------- ----------- ----------- ----------- First $ 7 $ 3 1/2 $ 11 1/2 $ 6 5/8 Second $ 8 1/4 $ 4 7/8 $ 14 9/16 $ 9 Third $ 9 $ 6 3/4 $ 16 1/4 $ 11 13/16 Fourth $ 7 3/4 $ 4 7/8 $ 19 7/16 $ 12 3/8
As of February 7, 2001 our common stock was held by 2,158 holders of record.
We have not declared nor paid any cash dividends on shares of our common stock since organization and currently intend to continue our policy of retaining earnings from our operations. We are prohibited by certain loan agreement provisions from declaring and paying dividends (other than stock dividends) during any fiscal year in excess of 25 percent of our consolidated net income of the preceding fiscal year, and only if working capital provided from operations during the prior year is equal to or greater than 175 percent of current maturities of long-term debt at the end of the prior year.
Item 6.
Item 6. Selected Financial Data - ------- ----------------------- Year Ended December 31, ---------------------------------------------------------- 1996(1) 1997(1) 1998(1) 1999(1) 2000 ---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 75,751 $ 96,478 $ 97,274 $ 102,352 $ 201,264 ========== ========== ========== ========== ========== Income From Continuing Operations $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344 ========== ========== ========== ========== ========== Net Income $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344 ========== ========== ========== ========== ========== Earnings Per Common Share: Basic $ .38 $ .47 $ .05 $ .10 $ .96 ========== ========== ========== ========== ========== Diluted $ .38 $ .46 $ .05 $ .10 $ .95 ========== ========== ========== ========== ==========
Total Assets $ 147,734 $ 213,416 $ 233,096 $ 295,567 $ 346,288 ========== ========== ========== ========== ==========
Long-Term Debt $ 42,255 $ 55,480 $ 75,048 $ 67,239 $ 54,000 ========== ========== ========== ========== ========== Other Long-Term Liabilities $ 2,360 $ 2,363 $ 2,368 $ 2,325 $ 3,597 ========== ========== ========== ========== ==========
Cash Dividends Per Common Share $ - $ - $ - $ - $ - ========== ========== ========== ========== ========== -------------------- (1) Restated for the merger with Questa Oil and Gas Co.
See Management's Discussion of Financial Condition and Results of Operations for a review of 1998, 1999 and 2000 activity.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and - ------- --------------------------------------------------------------- Results of Operations ---------------------
Financial Condition and Liquidity - ---------------------------------
On March 20, 2000, we completed the acquisition, by merger, of Questa Oil and Gas Co.("Questa") under which Questa became a wholly owned subsidiary of Unit Corporation. In the merger, each of Questa's outstanding shares of common stock (excluding treasury shares) was converted into .95 shares of our common stock. We issued approximately 1.8 million shares as a result of this merger. The merger has been accounted for as a pooling of interests and, accordingly, all amounts within this document have been restated, unless otherwise noted, as if the companies had been combined during the periods presented.
Our bank loan agreement provides for a total loan facility of $100 million. Each year on April 1 and October 1 our banks redetermine our available borrowing value. This value is primarily determined by an amount equal to a percentage of the discounted future value of our oil and natural gas reserves, as determined by the banks. An additional amount, limited to $20 million, is added to the borrowing value for a percentage of the value of a portion of our drilling rig fleet. Our loan agreement provides for a revolving credit facility which terminates on May 1, 2002 followed by a three year term loan. Borrowings under our loan agreement totaled $52 million at December 31, 2000 and $50 million at February 7, 2001. The latest borrowing value computation determined the full amount of the loan facility could be available to us, however, in order to reduce cost, we elected to set the borrowing value at $70 million for the current borrowing value period. We are charged a facility fee of .375 of 1 percent on any unused portion of the available borrowing value. The loan agreement also contains covenants which require us to maintain
. consolidated tangible net worth of at least $75 million,
. a current ratio of not less than 1 to 1,
. a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1,
. a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1, and
. working capital provided by operations, as defined in the loan agreement, cannot be less than $18 million in any year.
The interest rate on our bank debt was 7.82 percent at December 31, 2000 and 6.72 percent at February 7, 2001. At our election, any portion of our outstanding bank debt may be fixed at the London Interbank Offered Rate ("Libor Rate"), as adjusted, depending on the level of our debt as a percentage of the available borrowing value. The Libor Rate may be fixed for periods of up to 30, 60, 90 or 180 days with the remainder of our bank
debt being subject to the Chase Manhattan Bank, N. A. prime rate. During any Libor Rate funding period, we may not pay any part of the outstanding principal balance which is subject to the Libor Rate. Borrowings subject to the Libor Rate were $47.0 million at December 31, 2000 and $50.0 million at February 7, 2001.
Our shareholders' equity at December 31, 2000 was $214.5 million giving us a ratio of long-term debt-to-total capitalization of 20 percent. Our primary source of funds consists of the cash flow from our operations and borrowings under our bank loan agreement. Net cash provided by our operations in 2000 was $67.4 million compared to $24.7 million in 1999. We had working capital of $13.3 million at December 31, 2000. Our total 2000 capital expenditures were $65.3 million, of which $39.9 million was spent in our oil and natural gas operations. This segment's capital expenditures consisted primarily of $30.5 million for exploration and development drilling and $3.8 million for producing property acquisitions. Capital expenditures for our contract drilling operations totaled $22.0 and consisted primarily of $3.0 million to rebuild three of our drilling rigs, $3.2 million to acquire one rig and $1.5 million to start construction on two additional rigs. We also acquired $3.3 million in new drill pipe with the remainder of our drilling capital expenditures for major components for our rig fleet. We anticipate that we will spend approximately $20 million in 2001 for drilling rig equipment.
As natural gas and oil prices increased during the last six months of 1999 and throughout 2000, we increased the drilling activity in our exploration and production operation with the result that we drilled 101 wells during 2000 as compared to a total of 51 wells during the 1999. If oil and natural gas prices remain favorable, we plan to drill an estimated 130 wells and spend approximately $65 million drilling or buying oil and natural gas properties in 2001.
Most of our capital expenditures are discretionary and directed toward our future growth. Current operations do not depend on our ability to obtain funds outside of our loan agreement and our anticipated cash flow. Future decisions by us to acquire or drill on oil and natural gas properties will depend on prevailing or anticipated market conditions, potential return on investment, future drilling potential and the availability of opportunities to obtain financing under the circumstances involved, thus providing us with a large degree of flexibility in determining when and if to incur such costs.
On September 30, 1999, we completed the acquisition of 13 land drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc., for 1,000,000 shares of our common stock and $40,000,000 in cash. The cash part of this acquisition was funded through a public offering of 7,000,000 shares of our common stock which closed on September 29, 1999. We received proceeds of $50.1 million from the offering net of commission fees and other costs.
On November 20, 1997, we acquired Hickman Drilling Company pursuant to an agreement and plan of merger entered into by and between us, Hickman Drilling Company and all of the holders of the outstanding capital stock of Hickman Drilling Company. As part of this acquisition, the former
shareholders of Hickman held, as of December 31, 2000, promissory notes in the aggregate outstanding principal amount of $3.0 million. These notes are payable in equal annual installments on January 2, 2001 through January 2, 2003. The notes bear interest at the Chase Prime Rate which at December 31, 2000 was 9.5 percent and February 7, 2001 was 8.5 percent. At February 7, 2001, the promissory notes outstanding totaled $2.0 million.
Due to a settlement agreement which terminated at December 31, 1997, we have a liability of $877,000 at December 31, 2000, representing proceeds received from a natural gas purchaser as prepayment for natural gas. The $877,000 is payable in equal annual payments on June 1, 2001 and June 1, 2002.
The average price we received for our oil in 2000 increased 54 percent from the price we received in 1999 and our December 2000 oil price was 10 percent higher than the oil price we received in December 1999. Natural gas prices remain volatile, but increased substantially during the year. Our average natural gas price in 2000 was 91 percent higher than our average 1999 price and our December 2000 natural gas price was 239 percent higher than our December 1999 price. For the year, the average natural gas price we received was $3.91 per Mcf and the average oil price we received was $26.95 per barrel. Natural gas prices are influenced by weather conditions and supply imbalances, particularly in the domestic market, and by world wide oil price levels. Domestic oil price levels continue to be primarily influenced by world market developments. Since natural gas comprises approximately 90 percent of our total oil and natural gas reserves, natural gas prices have a significant effect on the value of our oil and natural gas reserves and large natural gas price declines could cause us to reduce the carrying value of our oil and natural gas properties. Any price decreases, if sustained, would also adversely affect our future cash flow by reducing our oil and natural gas revenues and, if continued over an extended period, could lessen not only the demand for our contract drilling rigs but also the rate we would receive. Any declines in natural gas and oil prices could also adversely affect the semi-annual determination of the loan value under our bank loan agreement since this determination is based on the value of our oil and natural gas reserves and our drilling rigs. Such a reduction would reduce the amount available to us under our loan agreement which, in turn, may affect our ability to carry out our capital projects.
Generally, during the past 17 years, our contract drilling operations have encountered significant competition, as reduced oil and natural gas prices during most of the period created a reduction in the demand for domestic land contract drilling rigs. However, in the last half of 1999 and throughout 2000 as oil and natural gas prices increased we experienced a substantial increase in demand for our rigs bringing our utilization rates above 90 percent for the last five months of 2000. Even with the increase in demand, we anticipate that competition within our industry will, for the foreseeable future, continue to influence the use of our drilling rigs. In addition to competition, our ability to use our drilling rigs at any given time depends on a number of other factors, including the continued strengthening of the price of both oil and natural gas, the availability of labor and our ability to supply the type of equipment required.
At December 31, 2000, we had tax net operating loss carryforwards ("NOL's") of approximately $39.5 million, the benefit of which has been recognized in our financial statements as we believe it to be more likely than not that we will use these NOL's. Should we be unable to generate sufficient income in future years to allow the use of all the NOL's, a charge to expense will be required to give recognition to any loss of the NOL's.
At December 31, 2000, one of our subsidiaries owned 4,949,500 shares of common stock and 1,800,000 warrants in Shenandoah Resources Ltd., which is a Canadian oil and natural gas exploration and production company. The investment of $2,426,000 is part of other assets in our consolidated balance sheet.
Effects of Inflation - --------------------
In the previous 17 years the effects of inflation on our operations have been minimal due to low inflation rates and moderate demand for contract drilling services. In the last half of 1999 and throughout 2000, as drilling rig day rates and drilling rig utilization increased, the impact of inflation has increased as the availability of equipment and third party services have decreased. Due to industry wide demand for qualified labor, contract drilling labor cost increased substantially in the summer of 2000. How inflation will effect us in the future will depend on additional increases, if any, we realize in our drilling rig rates and the prices we receive for our oil and natural gas. If industry activity continues to increase, 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.
New Accounting Pronouncements - -----------------------------------
On June 15, 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). The statement has subsequently been amended by FASB statements No. 137 and No. 138 and establishes new accounting and reporting standards for derivative instruments. We will be required to adopt this statement in the first quarter of 2001. This statement will require us to recognize all derivatives as either assets or liabilities on the balance sheet and measure the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value for each reporting period. The effective portion of the gain or loss on the derivative instrument will be recognized in other comprehensive income as a component of our equity until the hedged item is recognized in earnings. The ineffective portion of the derivative's change in fair value is required to be recognized in earnings during the period the change in value occurs. We have evaluated all of our transactions that could potentially be classified as derivative instruments under FAS 133. The adoption of FAS 133 will not have a significant effect on our results of operations or financial position.
Results of Operations - ---------------------
2000 versus 1999 - ----------------
Net income for 2000 was $34,344,000, compared with $3,048,000 for 1999. This increase resulted primarily from increases in our natural gas and oil prices and production volumes. Higher oil and natural gas prices also elevated the demand for our drilling rigs, resulting in increased utilization of our rigs, dayrates and net income.
Our oil and natural gas revenues increased 99 percent in 2000 due to a 91 percent and 54 percent rise in the average prices we received for natural gas and oil, respectively. For the year, natural gas production increased by 11 percent and oil production increased by 15 percent when compared to 1999. Production grew as we drilled 101 gross wells (40.2 net wells) in 2000, compared to 51 gross wells (21.4 net wells) in 1999. Natural gas production for the fourth quarter of 2000 exceeded 1999's fourth quarter production by 11 percent.
In 2000, revenues from our contract drilling operations increased by 95 percent as the average number of our drilling rigs being used increased from 23.1 in 1999 to 39.8 in 2000. Revenues per rig per day increased 13 percent between the comparative years. The acquisition of the Parker drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter of 1999 and 9.0 rigs to our 2000 utilization at dayrates substantially higher than those achieved in our other marketing area. Our rigs excluding those acquired from Parker added 9.3 rigs to utilization and added an additional 10 percent to their revenue per rig per day. Daywork revenues represented 75 percent of our total drilling revenues in 2000 and 61 percent in 1999.
Operating margins (revenues less operating costs) for our oil and natural gas operations were 79 percent in 2000 and 67 percent in 1999. This increase resulted primarily from the increase in the average oil and natural gas prices we received. Total operating costs between the comparative years increased 31 percent due primarily to the 113 percent increase in production taxes incurred as a result of higher revenues and to a lesser extent from the addition of new wells through development drilling.
Our contract drilling operating margins increased from 14 percent in 1999 to 22 percent in 2000. The additional operating margin was generally due to additional revenue received per day and an increase in the number of rigs utilized. Our contract drilling operating cost per rig per day increased $109 in 2000 as total contract drilling operating costs were up 76 percent in 2000 versus 1999 primarily due to increased utilization.
Contract drilling depreciation increased 75 percent due to the impact of higher depreciation per operating day associated with the newly acquired
Parker rigs and an overall increase in our rig utilization. Depreciation, depletion and amortization ("DD&A") of our oil and natural gas properties increased 8 percent due to additional production volumes. The average DD&A rate per Mcfe decreased 4 percent to $0.82 in 2000.
General and administrative expenses increased 14 percent as certain employee costs, outside contract services and office expenses increased due to the growth in both of our operating segments. Interest expense decreased 3 percent as our average outstanding debt decreased 14 percent during 2000. The average interest rate increased from 7.0 percent in 1999 to 7.9 percent in 2000.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were struck by a tornado destroying two buildings and damaging various vehicles and drilling equipment. In May 1999, we received $500,000 of insurance proceeds for the destroyed buildings, and, as a result, in the second quarter of 1999, we recognized a gain of $315,000 recorded as part of other revenues. During the first quarter of 2000, we received the final insurance proceeds totaling $987,000 for the contents of the destroyed buildings, damaged equipment and clean up costs. From these proceeds, we recognized a gain of $599,000 recorded as part of other revenues in the first quarter of 2000.
1999 versus 1998 - ----------------
Net income for 1999 was $3,048,000, compared with $1,428,000 in 1998. Lower natural gas and oil prices in the first half of 1999 reduced both the demand for our drilling rigs and the rates we received for the drilling rigs that were operating. As a result of the merger with Questa, the oil and gas properties of Questa were restated from the successful efforts method of accounting to the full cost method of accounting used by Unit Corporation. As part of this restatement, in 1998, the value of Questa's oil and natural gas properties were impaired due to low prices at the end of the third quarter of 1998; therefore, the Questa properties were written down $2.6 million.
Our oil and natural gas revenues increased 7 percent in 1999 due to a 7 percent and 37 percent increase in the average prices we received for natural gas and oil, respectively. For the year, natural gas production decreased by 2 percent and oil production decreased by 13 percent when compared to 1998. Our oil production declined because we in recent years emphasized the drilling of development wells aimed at replacing and increasing our natural gas reserves. Our natural gas production decreased because we curtailed our development drilling program during the first half of 1999 while oil and natural gas prices were depressed. As prices began to improve during the last six months of 1999, our natural gas production increased as we increased our drilling program. Natural gas production for the fourth quarter of 1999 exceeded 1998's fourth quarter production by 4 percent.
In 1999, revenues from our contract drilling operations increased by 4 percent as the average number of drilling rigs being used increased from 22.9 in 1998 to 23.1 in 1999. Revenues per rig per day increased 3 percent
between the comparative years. During the first nine months of 1999 as compared to the same period of 1998, our average drilling rig utilization was down 22 percent and our average revenues per rig per day was down 4 percent. The acquisition of the Parker drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter of 1999 at dayrates substantially higher than those achieved in our other marketing area. As a result, that acquisition had a strong impact on our contract drilling fourth quarter and year-end operating results, adding $5.6 million in revenues. Daywork revenues represented 61 percent of our total drilling revenues in 1999 and 64 percent in 1998.
Operating margins (revenues less operating costs) for our oil and natural gas operations were 67 percent in 1999 and 64 percent in 1998. This increase resulted primarily from the increase in the average oil and natural gas prices we received and a 2 percent decrease in operating costs between the comparative years.
Our contract drilling operating margins decreased from 18 percent in 1998 to 14 percent in 1999. This reduction was generally due to decreases during the first nine months of 1999 in both daily drilling rig revenue rates and utilization and increases in operating costs. Total contract drilling operating costs were up 9 percent in 1999 versus 1998 due to increased labor costs and related benefit costs, including workers' compensation.
Contract drilling depreciation increased 19 percent due to the impact of higher depreciation per operating day associated with the newly acquired Parker rigs. Depreciation, depletion and amortization ("DD&A") of our oil and natural gas properties decreased 13 percent. Total DD&A was higher in 1998 due to the write down of Questa's oil and natural gas properties in the third quarter of 1998, as discussed above. Decreases in production as previously discussed also reduced DD&A in 1999. The average DD&A rate per Mcfe increased 5 percent to $0.85 in 1999.
General and administrative expenses increased 4 percent as certain employee benefit costs and outside services increased. Interest expense increased 6 percent as our average outstanding debt increased 11 percent during 1999. The average interest rate decreased from 7.1 percent in 1998 to 7.0 percent in 1999.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were struck by a tornado destroying two buildings and damaging various vehicles and drilling equipment. In May 1999, we received $500,000 of insurance proceeds for the destroyed buildings, and as a result, in the second quarter of 1999, we recognized a gain of $315,000 recorded as part of other revenues.
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 pricing of 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 have received for our oil and natural gas production have been volatile and such volatility is expected to continue.
To reduce the impact of price fluctuations, we periodically use hedging strategies to hedge the price we will receive for a portion of our future oil and natural gas production. In the first quarter of 2000, we entered into swap transactions in an effort to lock in a portion of our production at the higher oil prices which currently existed. These transactions applied to approximately 50 percent of our daily oil production covering the period from April 1, 2000 to July 31, 2000 and 25 percent of our daily oil production for August and September of 2000, at prices ranging from $24.42 to $27.01. We have also entered into a collar contract for approximately 25 percent of our daily production for the period covering November 1, 2000 to February 28, 2001. The collar has a floor of $26.00 and a ceiling of $33.00 and we are receiving $0.86 per barrel for entering into the collar transaction. During 2000, the sum of these hedging transactions yielded a reduction in our oil revenues of $465,000.
Interest Rate Risk - Our interest rate exposure relates to our long- term debt, all of which bears interest at variable rates based on the prime rate or the London Interbank Offered Rate ("Libor rate"). At our election, borrowings under our revolving credit and term loan may be fixed at the Libor rate for periods up to 180 days. Historically, we have not utilized any financial instruments, such as interest rate swaps, to attempt to manage the exposure to increases in interest rates. However, we may consider the use of such financial instruments in the future based on our assessment of future interest rates. The impact on annual cash flow before taxes of a one percent change in the floating rate based on our average outstanding long-term debt in 2000 would have been approximately $628,000.
Item 8.
Item 8. Financial Statements and Supplementary Data - ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
As of December 31, ---------------------- 1999 2000 ---------- ---------- Restated, See Note 2) (In thousands) ASSETS - ------ Current Assets: Cash and cash equivalents $ 2,647 $ 726 Accounts receivable (less allowance for doubtful accounts of $583 and $919) 22,070 40,220 Materials and supplies 3,259 3,802 Prepaid expenses and other 2,510 1,269 ---------- ---------- Total current assets 30,486 46,017 ---------- ----------
Property and Equipment: Drilling equipment 177,238 196,736 Oil and natural gas properties, on the full cost method 312,269 349,707 Transportation equipment 3,502 5,803 Other 7,694 8,801 ---------- ---------- 500,703 561,047 Less accumulated depreciation, depletion, amortization and impairment 241,649 270,690 ---------- ---------- Net property and equipment 259,054 290,357 ---------- ---------- Other Assets 6,027 9,914 ---------- ---------- Total Assets $ 295,567 $ 346,288 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31, ---------------------- 1999 2000 ---------- ---------- (Restated, See Note 2) (In thousands) LIABILITIES AND SHAREHOLDERS' EQUITY - ----------------------------------- Current Liabilities: Current portion of long-term debt and other liabilities $ 2,027 $ 1,627 Accounts payable 14,682 21,012 Accrued liabilities 8,517 9,854 Contract advances 358 179 ---------- ---------- Total current liabilities 25,584 32,672 ---------- ---------- Long-Term Debt 67,239 54,000 ---------- ---------- Other Long-Term Liabilities (Note 4) 2,325 3,597 ---------- ---------- Deferred Income Taxes 20,914 41,479 ---------- ---------- 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, 40,000,000 and 75,000,000 shares authorized, 35,641,307 and 35,768,344 shares issued, respectively 7,128 7,154 Capital in excess of par value 139,207 139,872 Retained earnings 33,170 67,514 ---------- ---------- Total shareholders' equity 179,505 214,540 ---------- ---------- Total Liabilities and Shareholders' Equity $ 295,567 $ 346,288 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ------------------------------------- 1998 1999 2000 ---------- ---------- ---------- (Restated, (Restated, See Note 2) See Note 2) (In thousands except per share amounts) Revenues: Contract drilling $ 53,528 $ 55,479 $ 108,075 Oil and natural gas 43,346 46,225 92,016 Other 400 648 1,173 ---------- ---------- ---------- Total revenues 97,274 102,352 201,264 ---------- ---------- ---------- Expenses: Contract drilling: Operating costs 43,729 47,721 84,051 Depreciation 5,766 6,851 11,999 Oil and natural gas: Operating costs 15,464 15,084 19,754 Depreciation, depletion, amortization and impairment 19,564 17,114 18,492 General and administrative 5,543 5,750 6,560 Interest 4,950 5,268 5,136 ---------- ---------- ---------- Total expenses 95,016 97,788 145,992 ---------- ---------- ---------- Income Before Income Taxes 2,258 4,564 55,272 ---------- ---------- ---------- Income Tax Expense: Current 214 29 621 Deferred 616 1,487 20,307 ---------- ---------- ---------- Total income taxes 830 1,516 20,928 ---------- ---------- ---------- Net Income $ 1,428 $ 3,048 $ 34,344 ========== ========== ========== Net Income Per Common Share: Basic $ .05 $ .10 $ .96 ========== ========== ========== Diluted $ .05 $ .10 $ .95 ========== ========== ==========
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, 1998, 1999 and 2000 (1998 and 1999 Restated, See Note 2)
Capital In Excess Common Of Par Retained Treasury Stock Value Earnings Stock Total -------- ---------- --------- -------- ---------- (In thousands) Balances, January 1, 1998 $ 5,468 $ 81,837 $ 28,694 $ (156) $ 115,843 Net income - - 1,428 - 1,428 Activity in employee compensation plans (48,329 shares) 10 144 - 156 310 Retirement of Shares - (58) - - (58) Purchase of treasury Stock (25,000 shares) - - - (131) (131) Questa purchase of treasury shares - (8) - - (8) -------- ---------- --------- -------- ----------
Balances, December 31, 1998 5,478 81,915 30,122 (131) 117,384 Net income - - 3,048 - 3,048 Activity in employee compensation plans (252,511 shares) 50 680 - 131 861 Sale of Common Stock (7,000,000 shares) 1,400 48,682 - - 50,082 Issuance of stock for acquisition (1,000,000 shares) 200 7,938 - - 8,138 Questa purchase of treasury shares - (8) - - (8) -------- ---------- --------- -------- ----------
Balances, December 31, 1999 7,128 139,207 33,170 - 179,505 Net income - - 34,344 - 34,344 Activity in employee compensation plans (135,419 shares) 26 665 - - 691 -------- ---------- --------- -------- ----------
Balances, December 31, 2000 $ 7,154 $ 139,872 $ 67,514 $ - $ 214,540 ======== ========== ========= ======== ==========
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, ------------------------------------ 1998 1999 2000 ---------- ---------- ---------- (Restated, (Restated, See Note 2) See Note 2) (In thousands) Cash Flows From Operating Activities: Net Income $ 1,428 $ 3,048 $ 34,344 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, amortization and impairment 25,681 24,285 30,946 Loss (gain) on disposition of assets 17 (400) (969) Employee stock compensation plans 561 436 443 Bad debt expense - 255 350 Deferred tax expense 616 1,487 20,307 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable 6,425 (8,450) (18,500) Materials and supplies 244 49 (543) Prepaid expenses and other (441) 140 (96) Accounts payable 882 2,667 (1,370) Accrued liabilities 60 1,590 3,067 Contract advances 205 48 (179) Other liabilities (447) (442) (440) ---------- ---------- ---------- Net cash provided by operating activities 35,231 24,713 67,360 ---------- ---------- ----------
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, ------------------------------------ 1998 1999 2000 ---------- ---------- ---------- (Restated, (Restated, See Note 2) See Note 2) (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property acquisitions $ (56,290) $ (69,503) $ (60,447) Proceeds from disposition of property and equipment 964 1,438 4,259 (Acquisition) disposition of other assets (93) 91 (2,656) ---------- ---------- ---------- Net cash used in investing activities (55,419) (67,974) (58,844) ---------- ---------- ---------- Cash Flows From Financing Activities: Borrowings under line of credit 53,475 61,600 31,200 Payments under line of credit (32,900) (68,400) (44,439) Net payments on notes payable and other long-term debt (495) (1,090) (556) Proceeds from sale of common stock (21) 50,136 250 Book overdrafts (Note 1) - 2,974 3,108 Acquisition of treasury stock (131) - - ---------- ---------- ---------- Net cash provided by (used in) financing activities 19,928 45,220 (10,437) ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents (260) 1,959 (1,921) Cash and Cash Equivalents, Beginning of Year 948 688 2,647 ---------- ---------- ---------- Cash and Cash Equivalents, End of Year $ 688 $ 2,647 $ 726 ========== ========== ========== Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest $ 4,199 $ 5,850 $ 5,135 Income taxes $ 617 $ 30 $ 519
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 contact drilling and exploration and production activities are oriented toward drilling for and producing natural gas. At December 31, 2000, Unit had an interest in a total of 2,951 wells and served as operator of 667 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 2000, all of Unit's 47 rigs owned throughout the year 2000 were in operation. Unit acquired another rig at the end of the year and two more rigs were under construction, making the total rig count 50, at December 31, 2000.
Drilling Contracts
Unit recognizes revenues generated from "daywork" drilling contracts as the services are performed, which is similar to the percentage of completion method. Under "footage" and "turnkey" contracts, Unit bears the risk of completion of the well therefore, revenues and expenses are recognized using the completed contract method. The duration of all three types of contracts range typically from 20 to 90 days. 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, 1999 and 2000, book overdrafts of $3.0 million and $6.1 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 betterments 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 percent 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 over the fair value of the net assets acquired and is being amortized on the straight-line method over 25 years. Goodwill is evaluated periodically for impairment, when it appears an impairment may have occurred. If an impairment is determined, the amount of such impairment is calculated based on the estimated fair market value of the related assets. Net goodwill reported in other assets at December 31, 1999 and 2000 was $5,575,000 and $5,331,000, respectively with accumulated amortization at December 31, 1999 and 2000 of $507,000 and $750,000, respectively.
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 $0.81, $0.85 and $0.82 per Mcfe in 1998, 1999 and 2000, 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 $11.0 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 12, such estimates are imprecise. As part of the merger with Questa, the oil and gas properties of Questa were restated from the successful effort method of accounting to the full cost method of accounting used by Unit Corporation. As part of this restatement, in 1998, the value of Questa's oil and natural gas properties were impaired due to low prices at the end of the third quarter of 1998; therefore, the properties were written down $2.6 million.
No gains or losses are recognized upon the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in current operations for services performed on oil and natural gas properties in which Unit has an interest or on properties in which a partnership, of which Unit is a general partner, has an interest. Accordingly, in 1998 and 2000, Unit recorded $437,000 and $179,000 of contract drilling profits, respectively, as a reduction of the carrying value of its oil and natural
gas properties rather than including these profits in current operations. No contract drilling profits were realized on such interests in 1999.
Limited Partnerships
Unit's wholly owned subsidiary, Unit Petroleum Company, is a general partner in sixteen 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's wholly owned subsidiary, Questa Oil and Gas Co., is a general partner in two additional oil and natural gas limited partnerships sold privately. 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. Based upon the 2000 average natural gas price received of $3.91 per Mcf, Unit estimates its balancing position to be approximately $6.9 million on under-produced properties and approximately $6.0 million on over-produced properties. 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.
Employee and Director Stock Based Compensation
Unit applies APB Opinion 25 in accounting for its stock option plans for its employees and directors. 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 1998, 1999 and 2000 no compensation expense has been recognized. As provided by Financial Accounting Standard No. 123 "Accounting for Stock-Based Compensation," Unit has disclosed the pro forma effects of recording compensation for such option grants based on fair value in Note 6 to the financial statements.
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 $2,974,000 and $4,462,000 for employer group health insurance and worker's compensation at December 31, 1999 and 2000, respectively.
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 2000, one purchaser of Unit's oil and natural gas production accounted for approximately 12 percent of consolidated revenues. At December 31, 2000 accounts receivable from one oil and natural gas purchaser was approximately $12.5 million. In addition, at December 31, 1999 and 2000, Unit had a concentration of cash of $0.4 million and $1.7 million, respectively, with one bank.
Hedging Activities
To reduce the impact of fluctuations in the market prices of oil and natural gas, Unit periodically utilizes hedging strategies such as futures transactions or swaps to hedge the price of a portion of its future oil and natural gas production. Results of these hedging transactions are reflected in oil and natural gas sales in the month of the hedged production. At December 31, 1998 and 1999, Unit had no such hedging or derivative transactions. In the first quarter of 2000, we entered into swap transactions in an effort to lock in a portion of our daily production at the higher oil prices which currently existed. These transactions applied to approximately 50 percent of our daily oil production covering the period from April 1, 2000 to July 31, 2000 and 25 percent of our oil production for August and September of 2000, at prices ranging from $24.42 to $27.01. We have also entered into a collar contract for approximately 25 percent of our daily production for the period covering November 1, 2000 to February 28, 2001. The collar has a floor of $26.00 and a ceiling of $33.00 and we are receiving $0.86 per barrel for entering into the collar transaction. During 2000, the sum of these hedging transactions yielded a reduction in our oil revenues of $465,000.
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 June 15, 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"). The statement has subsequently been amended by FASB statements No. 137 and No. 138 and establishes new accounting and reporting standards for derivative instruments. Unit will be required to adopt this statement in the first quarter of 2001. FASB 133 requires the recognition of all derivatives as either assets or liabilities on the balance sheet and measure the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value for each reporting period. The effective portion of the gain or loss on the derivative instrument will be recognized in other comprehensive income as a component of Unit's equity until the hedged item is recognized in earnings. The ineffective portion of the derivative's change in fair value is required to be recognized in earnings during the period the change in value occurs. Unit has evaluated all of the transactions that could potentially be classified as derivative instruments under FAS 133. The adoption of FAS 133 will not have a significant effect on the results of operations or financial position.
NOTE 2 - ACQUISITIONS AND MERGER - --------------------------------
On March 20, 2000, Unit completed the acquisition, by merger, of Questa Oil and Gas Co.("Questa") under which Questa became a wholly owned subsidiary of Unit Corporation. In the merger each of Questa's outstanding shares of common stock (excluding treasury shares) was converted into .95 shares of our common stock. Unit issued approximately 1.8 million shares as a result of this merger. The merger has been accounted for as a pooling of interests and, accordingly, all amounts in the financial statements have been restated as if the companies had been combined throughout the periods presented.
The results of operations for each company and the combined amounts presented in Unit Corporation's consolidated financial statements are as follows:
Three Months Year Ended Year Ended Ended December 31, December 31, March 31, 1998 1999 2000 -------------- -------------- -------------- (In thousands) Revenues: Unit Corporation $ 93,337 $ 97,453 $ 35,807 Questa 3,937 4,899 1,420 -------------- -------------- -------------- Combined $ 97,274 $ 102,352 $ 37,227 ============== ============== ==============
Net Income: Unit Corporation $ 2,246 $ 1,486 $ 3,095 Questa (818) 1,562 483 -------------- -------------- -------------- Combined $ 1,428 $ 3,048 $ 3,578 ============== ============== ==============
Questa's net income has been reduced by $1,219,000 in 1998, increased by $527,000 in 1999 and increased by $12,000 in the first quarter of 2000 to restate Questa's financial statements to the full cost method of accounting used by Unit.
On September 30, 1999, Unit acquired 13 land drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc. Under the terms of the acquisition, the sellers received 1,000,000 shares of Unit's common stock valued at $8,138,000 and $40,000,000 in cash. The cash portion of the consideration was funded through an offering of 7,000,000 shares of Unit's common stock, which closed on September 29, 1999. The proceeds received by Unit from the offering were $50,082,000 net of commission fees and other costs. The acquisition has been accounted for as a purchase and the results of operations of the acquired rigs have been included in the consolidated financial statements since the date of acquisition.
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 ------------- ------------- ----------
For the Year Ended December 31, 1998: Basic earnings per common share $ 1,428,000 27,370,000 $ 0.05 ========== Effect of dilutive stock options - 340,000 ------------- ------------- Diluted earnings per common share $ 1,428,000 27,710,000 $ 0.05 ============= ============= ==========
For the Year Ended December 31, 1999: Basic earnings per common share $ 3,048,000 29,639,000 $ 0.10 ========== Effect of dilutive stock options - 274,000 ------------- ------------- Diluted earnings per common share $ 3,048,000 29,913,000 $ 0.10 ============= ============= ========== For the Year Ended December 31, 2000: Basic earnings per common share $ 34,344,000 35,723,000 $ 0.96 ========== Effect of dilutive stock options 409,000 ------------- ------------- Diluted earnings per common share $ 34,344,000 36,132,000 $ 0.95 ============= ============= ==========
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,:
1998 1999 2000 ---------- ---------- ---------- Options 191,000 196,500 144,000 ========== ========== ========== Average exercise price $ 8.60 $ 8.49 $ 16.59 ========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES - -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 1999 and 2000: 1999 2000 ---------- ---------- (In thousands) Revolving credit and term loan, with interest at December 31, 1999 and 2000 of 7.5 percent and 7.8 percent, respectively $ 62,400 $ 52,000 Notes payable for Hickman Drilling Company acquisition with interest at December 31, 1999 and 2000 of 8.5 percent and 9.5 percent, respectively 4,000 3,000 Notes payable to banks by Questa with interest at December 31, 1999 of 8.5 percent 2,147 - ---------- ---------- 68,547 55,000 Less current portion 1,308 1,000 ---------- ---------- Total long-term debt $ 67,239 $ 54,000 ========== ==========
At December 31, 2000, Unit's bank loan agreement provided for a total loan commitment of $100 million consisting of a revolving credit facility through May 1, 2002 and a term loan thereafter, maturing on May 1, 2005. Borrowings under the loan agreement are limited to a borrowing value. At December 31, 2000, the latest borrowing value computation had determined the full amount of the loan facility could be available to Unit, but the company elected to set the borrowing value at $70 million in order to reduce cost. The loan value under the revolving credit facility is subject to a semi-annual re-determination calculated as the sum of a percentage of
the discounted future value of Unit's oil and natural gas reserves, as determined by the banks. An additional amount, limited to $20 million, is added to the borrowing value from a percentage of the value of a portion of our drilling rig fleet. Any declines in commodity prices would adversely impact the determination of the borrowing value.
Borrowings under the revolving credit facility bear interest at the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank Offered Rates ("Libor Rate") plus 1.00 to 1.50 percent depending on the level of debt as a percentage of the total borrowing base. Subsequent to May 1, 2002, borrowings under the loan agreement bear interest at the Prime Rate or the Libor rate plus 1.25 to 1.75 percent depending on the level of debt as a percentage of the total loan value.
At Unit's election, any portion of the debt outstanding may be fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate funding period the outstanding principal balance of the note to which such Libor Rate option applies may not be paid. Borrowings under the Prime Rate option may be paid anytime in part or in whole without premium or penalty.
Unit paid an origination fee of $85,000 at inception of the loan agreement and a facility fee of 3/8 of one percent is charged for any unused portion of the borrowing value. Some of Unit's drilling rigs are collateral for such indebtedness and the balance of Unit's assets are subject to a negative pledge.
The loan agreement includes prohibitions against (i) the payment of dividends (other than stock dividends) during any fiscal year in excess of 25 percent of the consolidated net income of Unit during the preceding fiscal year, and only if working capital provided from operations during said year is equal to or greater than 175 percent of current maturities of long- term debt at the end of such year, (ii) the incurrence by Unit or any of its subsidiaries of additional debt with certain very limited exceptions and (iii) the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any property of Unit or any of its subsidiaries, except in favor of its banks. The loan agreement also requires that Unit maintain consolidated net worth of at least $75 million, a current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1 and a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1. In addition, working capital provided by operations, as defined in the loan agreement, cannot be less than $18 million in any year.
In November 1997, Unit completed the acquisition of Hickman Drilling Company. In association with this acquisition, we issued an aggregate of $5.0 million in promissory notes payable in five equal annual installments commencing January 2, 1999, with interest at the Prime Rate.
At December 31, 1999, Questa had $2.1 million of notes payable to a local bank, collateralized by certain of Questa's oil and natural gas interests, bearing interest at the prime rate of 8.5 percent and payable in quarterly installments of $75,000 with all remaining principal and accrued interest due at maturity on June 30, 2001. Other 60 month notes payable of $22,000, collateralized by automotive equipment, were owed by Questa at December 31, 1999, at interest rates of 7.5 to 7.75 percent. All of Questa's long-term debt was paid before Questa merged with Unit.
Other long-term liabilities consisted of the following as of December 31, 1999 and 2000:
1999 2000 ---------- ---------- (In thousands) Natural gas purchaser prepayment $ 1,317 $ 877 Separation benefit plan 1,419 1,811 Deferred compensation plan - 1,536 Rig acquisition 248 - Questa severance tax settlement payable 60 - ---------- ---------- 3,044 4,224 Less current portion 719 627 ---------- ---------- Total other long-term liabilities $ 2,325 $ 3,597 ========== ==========
At December 31, 2000, Unit has a prepayment balance of $877,000 representing proceeds received from a purchaser for prepayment of natural gas under a natural gas settlement agreement, which terminated on December 31, 1997. This amount is net of natural gas recouped and net of certain amounts disbursed to other owners for their proportionate share of the prepayments. At termination, the December 31, 1997 prepayment balance of $2.2 million became payable in equal annual payments over a five year period. A payment of $441,000 is due on June 1, 2001 and the final payment of $436,000 is due on June 1, 2002.
Unit has other long-term liabilities of $3,347,000, consisting of $1,811,000 accrued in connection with its separation benefit plans and $1,536,000 accrued in connection with its Deferred Compensation Plan.
Estimated annual principal payments under the terms of long-term debt and other long-term liabilities from 2001 through 2005 are $1,627,000, $11,549,000, $18,333,000, $17,333,000 and $7,222,000. Based on the borrowing rates currently available to Unit for debt with similar terms and maturities, long-term debt at December 31, 2000 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:
1998 1999 2000 ---------- ---------- ---------- (In thousands) Income tax expense computed by applying the statutory rate $ 768 $ 1,552 $ 19,345 State income tax, net of federal benefit 77 139 1,575 Goodwill and other (15) (175) 8 ---------- ---------- ---------- Income tax expense $ 830 $ 1,516 $ 20,928 ========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at December 31, 1999 and 2000:
1999 2000 ----------- ----------- (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 2,370 $ 3,308 Net operating loss carryforward 23,475 15,027 Statutory depletion carryforward 2,260 2,260 Investment tax credit carryforward 339 - Alternative minimum tax credit carryforward 895 1,123 ----------- ----------- Gross deferred tax assets 29,339 21,718
Valuation allowance (335) - Deferred tax liability- Depreciation, depletion and amortization (49,918) (63,197) ----------- ----------- Net deferred tax liability $ (20,914) $ (41,479) =========== ===========
The deferred tax asset valuation allowance reflects that the investment tax credit carryforwards may not be utilized before the expiration dates due, in part, to the effects of anticipated future exploratory and development drilling costs. The reduction in the valuation allowance was the result of the expiration of investment tax credit carryforwards in 2000.
Realization of the deferred tax asset is dependent on generating sufficient taxable income prior to expiration of loss carryforwards. 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 during the carryforward period are reduced.
At December 31, 2000, Unit has net operating loss carryforwards for regular tax purposes of approximately $39,546,000 and net operating loss carryforwards for alternative minimum tax purposes of approximately $10,824,000, which expire in various amounts from 2001 to 2019. In addition, a statutory depletion carryforward of approximately $5,948,000, which may be carried forward indefinitely, is available to reduce future taxable income, subject to statutory limitations.
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. On January 4, 1999, 87,376 shares of common stock were issued for payment of Unit's 1998 year-end bonuses. No shares were issued under the Plan in 1998 and 2000.
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 become exercisable at the rate of 20 percent per year one year after being granted and expire after ten years from the original grant date. The exercise price for options granted under this plan is the fair market value 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, 1998 574,160 $ 4.28 Granted 227,000 3.96 Exercised (21,300) 2.71 Cancelled (10,500) 7.05 ----------- ---------- Outstanding at December 31, 1998 769,360 4.19 Exercised (109,760) 2.76 Cancelled (2,000) 10.00 ----------- ---------- Outstanding at December 31, 1999 657,600 $ 4.41 Granted 146,000 16.59 Exercised (79,700) 4.19 Cancelled (4,200) 4.94 ----------- ---------- Outstanding at December 31, 2000 719,700 $ 6.87 =========== ==========
OUTSTANDING OPTIONS ------------------------------------ WEIGHTED AVERAGE WEIGHTED NUMBER REMAINING AVERAGE EXERCISE OF CONTRACTUAL EXERCISE PRICES SHARES LIFE PRICE ----------------------- ----------- ----------- ----------- $ 2.37 - $ 4.00 439,100 4.8 years $ 3.14 $ 7.25 - $16.69 280,600 8.1 years $ 12.75
EXERCISABLE OPTIONS ------------------------ WEIGHTED NUMBER AVERAGE EXERCISE OF EXERCISE PRICES SHARES PRICE ------------------------------------ ----------- ----------- $ 2.37 - $ 4.00 313,400 $ 2.90 $ 7.25 - $10.00 94,500 $ 8.69
Options for 427,000, 414,200 and 407,900 shares were exercisable with weighted average exercise prices of $3.42, $3.96 and $4.24 at December 31, 1998, 1999 and 2000, 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 Director's 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 ten 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, 1998 60,000 $ 5.06 Granted 12,500 9.00 ----------- ---------- Outstanding at December 31, 1998 72,500 5.74 Granted 12,500 6.90 Exercised (5,000) 5.13 Cancelled (2,500) 8.94 ----------- ---------- Outstanding at December 31, 1999 77,500 5.86 Granted 17,500 12.19 ----------- ---------- Outstanding at December 31, 2000 95,000 $ 7.03 =========== ==========
OUTSTANDING AND EXERCISABLE OPTIONS ------------------------------------ WEIGHTED AVERAGE WEIGHTED NUMBER REMAINING AVERAGE EXERCISE OF CONTRACTUAL EXERCISE PRICES SHARES LIFE PRICE ----------------------- ----------- ----------- ----------- $ 1.75 - $ 3.75 32,500 2.8 years $ 3.00 $ 6.87 - $12.19 62,500 7.6 years $ 9.12
Unit applies APB Opinion 25 in accounting for Unit's Stock Option Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on the nature of Unit's grants of options, no compensation cost has been recognized in 1998, 1999 and 2000. Had compensation been determined on the basis of fair value pursuant to FASB Statement No. 123, net income and earnings per share would have been reduced as follows:
1998 1999 2000 --------- --------- --------- Net Income (In thousands): As reported $ 1,428 $ 3,048 $ 33,344 ========= ========= ========= Pro forma $ 1,115 $ 2,652 $ 33,986 ========= ========= ========= Basic Earnings per Share: As reported $ .05 $ .10 $ .96 ========= ========= ========= Pro forma $ .04 $ .09 $ .95 ========= ========= ========= Diluted Earnings per Share: As reported $ .05 $ .10 $ .95 ========= ========= ========= Pro forma $ .04 $ .09 $ .94 ========= ========= =========
The fair value of each option granted is estimated using the Black- Scholes model. Unit's estimate of stock volatility was 0.53, 0.55 and 0.55 in 1998, 1999 and 2000, respectively, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 4.95, 6.70 and 5.26 percent in 1998, 1999 and 2000, respectively. 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 1998 and 2000 under the Stock Option Plan were $527,000 and $1,470,000, respectively. No options were issued under the Stock Option Plan in 1999. Under the Non-Employee Director's Stock Option Plan the aggregate fair value of options granted during 1998, 1999 and 2000 were $71,000, $58,000 and $99,000, respectively.
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. The Company made discretionary contributions under the plan of 46,892, 105,819 and 58,353 shares of common stock and recognized expense of $536,000, $464,000 and $595,000 in 1998, 1999 and 2000, 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, 1999 and 2000 totaled $1,165,000 and $1,536,000, 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 $577,000, $502,000 and $558,000 in 1998, 1999 and 2000, respectively, for benefits associated with anticipated payments from both separation plans.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES - ------------------------------------------
Unit formed private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2000, with a subsidiary of Unit serving as General Partner. Questa Oil and Gas Co. formed five private limited partnerships for 1981 to 1993. 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 Unit in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with Unit and Questa, respectively, in most drilling operations and most producing property acquisitions commenced by Unit or Questa for its own account during the period from the formation of the Partnership through December 31 of each year. Unit repurchased the limited partner's interest in three of five Questa partnerships in the fourth quarter of 2000 and the three partnerships were dissolved.
Amounts received in the years ended December 31 from both public and private Partnerships for which Unit and Questa are a general partner are as follows:
1998 1999 2000 --------- --------- --------- (In thousands) Contract drilling $ 180 $ 94 $ 296 Well supervision and other fees $ 415 $ 425 $ 478 General and administrative expense reimbursement $ 176 $ 175 $ 192
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, $21,000, $9,000 and $6,000 during the years ended December 31, 1998, 1999 and 2000, respectively, for purchases of natural gas production.
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 percent of its value.
The rights become exercisable 10 days after Unit learns that an acquiring person (as defined in the Plan) has acquired 15 percent 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 percent 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
tenth 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 under the terms of operating leases expiring through January 31, 2005. Future minimum rental payments under the terms of the leases are approximately $478,000, $393,000, $386,000, $386,000 and $32,000 in 2001, 2002, 2003, 2004 and 2005, respectively. Total rent expense incurred by the Company was $412,000, $422,000 and $535,000 in 1998, 1999 and 2000, respectively.
Unit as a 40 percent owner in a corporation which provides gas gathering services, guarantees certain indebtedness of that corporation up to a maximum of $2 million (approximately $1,436,000 at December 31, 2000). The guarantee extends for a period ending on June 21, 2001.
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 percent of the units outstanding. Unit made repurchases of $15,000, $10,000 and $14,000 in 1998, 1999 and 2000, respectively, for such limited partners' interests. Subsequent to the merger, Unit also paid $17,000 for additional interest in two of the Questa limited partnerships and $1,980,000 for all the remaining interest in three other Questa partnerships.
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 - --------------------------------------
In 1998, Unit adopted Statement of Financial Accounting Standard No. 131, "Disclosures about Segments of an Enterprise and Related Information." Unit has two business segments: Contract Drilling and Oil and Natural Gas, representing its two strategic 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.
1998 1999 2000 ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 53,528 $ 55,479 $ 108,075 Oil and natural gas 43,346 46,225 92,016 Other 400 648 1,173 ---------- ---------- ---------- Total revenues $ 97,274 $ 102,352 $ 201,264 ========== ========== ========== Operating Income (1): Contract drilling $ 4,033 $ 907 $ 12,025 Oil and natural gas 8,318 14,027 53,770 ---------- ---------- ---------- Total operating income 12,351 14,934 65,795
General and administrative expense (5,543) (5,750) (6,560) Interest expense (4,950) (5,268) (5,136) Other income (expense)- net 400 648 1,173 ---------- ---------- ---------- Income before income taxes $ 2,258 $ 4,564 $ 55,272 ========== ========== ========== Identifiable Assets (2): Contract drilling $ 69,147 $ 125,853 $ 141,324 Oil and natural gas 160,424 164,252 198,251 ---------- ---------- ---------- Total identifiable assets 229,571 290,105 339,575 Corporate assets 3,525 5,462 6,713 (3) ---------- ---------- ---------- Total assets $ 233,096 $ 295,567 $ 346,288 ========== ========== ==========
1998 1999 2000 ---------- ---------- ---------- (In thousands) Capital Expenditures: Contract drilling $ 11,485 $ 55,656 $ 22,045 Oil and natural gas 41,046 21,532 39,884 Other 216 744 3,324 ---------- ---------- ---------- Total capital expenditures $ 52,747 $ 77,932 $ 65,253 ========== ========== ========== Depreciation, Depletion, Amortization and Impairment: Contract drilling $ 5,766 $ 6,851 $ 11,999 Oil and natural gas 19,564 17,114 18,492 Other 351 320 455 ---------- ---------- ---------- Total depreciation, depletion, amortization and impairment $ 25,681 $ 24,285 $ 30,946 ========== ========== ==========
- ---------------------- (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 an investment in a Canadian oil and natural gas exploration and production company of $2,426,000.
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - -------------------------------------------------------------- Summarized quarterly financial information for 1999 and 2000 is as follows: Three Months Ended --------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ----------- ----------- ------------ ----------- Year ended (In thousands except per share amounts) December 31, 1999: Revenues $ 20,626 $ 20,495 $ 23,920 $ 37,311 =========== =========== =========== =========== Gross profit(1) $ 851 $ 1,272 $ 4,551 $ 8,260 =========== =========== =========== =========== Income (loss) before income taxes $ (1,760) $ (1,047) $ 1,870 $ 5,501 =========== =========== =========== =========== Net income (loss) $ (1,119) $ (656) $ 1,094 $ 3,729 =========== =========== =========== =========== Earnings (loss) per common share: Basic (2) $ (0.04) $ (0.02) $ 0.04 $ 0.10 =========== =========== =========== =========== Diluted (3) $ (0.04) $ (0.02) $ 0.04 $ 0.10 =========== =========== =========== =========== December 31, 2000: Revenues $ 37,227 $ 43,587 $ 54,788 $ 65,662 =========== =========== =========== =========== Gross profit(1) $ 7,719 $ 11,810 $ 18,154 $ 28,112 =========== =========== =========== =========== Income before Income taxes $ 5,648 $ 9,076 $ 15,622 $ 24,926 =========== =========== =========== =========== Net income $ 3,578 $ 5,627 $ 9,685 $ 15,454 =========== =========== =========== =========== Earnings per Common share: Basic $ 0.10 $ 0.16 $ 0.27 $ 0.43 =========== =========== =========== =========== Diluted (4) $ 0.10 $ 0.16 $ 0.27 $ 0.43 =========== =========== =========== =========== - ------------------ (1) Gross Profit excludes other revenues, general and administrative expense and interest expense.
(2) As a result of shares issued during the year, earnings per share for the year's four quarters, which is based on average shares outstanding during each quarter, does not equal the annual earnings per share, which is based on the average shares outstanding during the year.
(3) Due to the effect of additional shares sold in the equity offering and issued for the Parker rig acquisition and 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.
(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 - 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) 1998: Capitalized costs: Proved properties $ 279,988 $ 480 $ 280,468 Unproved properties 10,602 281 10,883 ----------- --------- ----------- 290,590 761 291,351 Accumulated depreciation, depletion, amortization and impairment (141,287) (412) (141,699) ----------- --------- ----------- Net capitalized costs $ 149,303 $ 349 $ 149,652 =========== ========= =========== Cost incurred: Unproved properties $ 4,856 $ 203 $ 5,059 Producing properties 9,223 - 9,223 Exploration 2,380 - 2,380 Development 24,384 - 24,384 ----------- --------- ----------- Total costs incurred $ 40,843 $ 203 $ 41,046 =========== ========= =========== 1999: Capitalized costs: Proved properties $ 301,725 $ 508 $ 302,233 Unproved properties 9,654 382 10,036 ----------- --------- ----------- 311,379 890 312,269 Accumulated depreciation, depletion, amortization and impairment (158,147) (420) (158,567) ----------- --------- ----------- Net capitalized costs $ 153,232 $ 470 153,702 =========== ========= =========== Cost incurred: Unproved properties $ 1,724 $ 101 $ 1,825 Producing properties 3,733 28 3,761 Exploration 2,037 - 2,037 Development 13,909 - 13,909 ----------- --------- ----------- Total costs incurred $ 21,403 $ 129 $ 21,532 =========== ========= ===========
USA CANADA TOTAL ----------- --------- ----------- (In thousands) 2000: Capitalized costs: Proved properties $ 338,159 $ 553 $ 338,712 Unproved properties 10,795 200 10,995 ----------- --------- ----------- 348,954 753 349,707 Accumulated depreciation, depletion, amortization and impairment (176,515) (435) (176,950) ----------- --------- ----------- Net capitalized costs $ 172,439 $ 318 $ 172,757 =========== ========= =========== Cost incurred: Unproved properties $ 5,522 $ 16 $ 5,538 Producing properties 3,752 45 3,797 Exploration 2,409 - 2,409 Development 28,140 - 28,140 ----------- --------- ----------- Total costs incurred $ 39,823 $ 61 $ 39,884 =========== ========= ===========
The results of operations for producing activities are provided below.
USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1998: Revenues $ 40,133 $ 55 $ 40,188 Production costs (12,684) (20) (12,704) Depreciation, depletion amortization and impairment (19,384) (8) (19,392) ----------- --------- ----------- 8,065 27 8,092 Income tax expense (3,094) (9) (3,103) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 4,971 $ 18 $ 4,989 =========== ========= =========== 1999: Revenues $ 42,999 $ 63 $ 43,062 Production costs (11,739) (20) (11,759) Depreciation, depletion and amortization (16,848) (8) (16,856) ----------- --------- ----------- 14,412 35 14,447 Income tax expense (4,387) (14) (4,401) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 10,025 $ 21 $ 10,046 =========== ========= =========== 2000: Revenues $ 88,461 $ 110 $ 88,571 Production costs (16,457) (19) (16,476) Depreciation, depletion and amortization (18,258) (15) (18,273) ----------- --------- ----------- 53,746 76 53,822 Income tax expense (20,350) (30) (20,380) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 33,396 $ 46 $ 33,442 =========== ========= ===========
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) 1998: Proved developed and undeveloped reserves: Beginning of year 4,596 159,012 - 723 4,596 159,735 Revision of previous estimates (1,205) (5,484) - (162) (1,205) (5,646) Extensions, discoveries and other additions 466 33,413 - - 466 33,413 Purchases of minerals in place 261 7,169 - - 261 7,169 Sales of minerals in - - place (3) (532) - - (3) (532) Production (486) (17,694) - (38) (486) (17,732) ------- -------- ------- -------- ------- -------- End of Year 3,629 175,884 - 523 3,629 176,407 ======= ======== ======= ======== ======= ========
Proved developed reserves: Beginning of year 3,871 129,422 - 295 3,871 129,717 End of year 2,749 134,504 - 421 2,749 134,925
1999: Proved developed and undeveloped reserves: Beginning of year 3,629 175,884 - 523 3,629 176,407 Revision of previous estimates 1,046 1,308 - 81 1,046 1,389 Extensions, discoveries and other additions 157 19,398 - - 157 19,398 Purchases of minerals in place 139 7,922 - - 139 7,922 Sales of minerals in - - place (20) (340) (20) (340) Production (424) (17,402) - (35) (424) (17,437) ------- -------- ------- -------- ------- -------- End of Year 4,527 186,770 - 569 4,527 187,339 ======= ======== ======= ======== ======= ========
Proved developed reserves: Beginning of year 2,749 134,504 - 421 2,749 134,925 End of year 3,583 144,992 - 467 3,583 145,459
USA CANADA TOTAL ---------------- ---------------- ---------------- NATURAL NATURAL NATURAL OIL GAS OIL GAS OIL GAS BBLS MCF BBLS MCF BBLS MCF ------- -------- ------- -------- ------- -------- (In thousands) 2000: Proved developed and undeveloped reserves: Beginning of year 4,527 186,770 - 569 4,527 187,339 Revision of previous estimates (45) 6,385 - (82) (45) 6,303 Extensions, discoveries and other additions 286 37,896 - - 286 37,896 Purchases of minerals in place 229 4,893 - - 229 4,893 Sales of minerals in (326) (1,509) - - (326) (1,509) place Production (488) (19,239) - (46) (488) (19,285) ------- -------- ------- -------- ------- -------- End of Year 4,183 215,196 - 441 4,183 215,637 ======= ======== ======= ======== ======= ========
Proved developed reserves: Beginning of year 3,583 144,992 - 467 3,583 145,459 End of year 3,222 162,718 - 389 3,222 163,107
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 our reserves as prepared by our reservoir engineers.
Proved reserves are those quantities which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves, which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
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) 1998: Future cash flows $ 418,744 $ 1,089 $ 419,833 Future production and development costs (167,114) (271) (167,385) Future income tax expenses (51,702) (160) (51,862) ----------- --------- ----------- Future net cash flows 199,928 658 200,586
10% annual discount for estimated timing of cash flows (68,705) (259) (68,964) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 131,223 $ 399 $ 131,622 =========== ========= ===========
1999: Future cash flows $ 557,915 $ 1,281 $ 559,196 Future production and development costs (213,929) (344) (214,273) Future income tax expenses (81,039) (175) (81,214) ----------- --------- ----------- Future net cash flows 262,947 762 263,709
10% annual discount for estimated timing of cash flows (95,722) (285) (96,007) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 167,225 $ 477 $ 167,702 =========== ========= ===========
2000: Future cash flows $2,260,796 $ 4,155 $2,264,951 Future production and development costs (484,900) (433) (485,333) Future income tax expenses (574,099) (1,099) (575,198) ----------- --------- ----------- Future net cash flows 1,201,797 2,623 1,204,420
10% annual discount for estimated timing of cash flows (527,210) (1,184) (528,394) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 674,587 $ 1,439 $ 676,026 =========== ========= ===========
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows (unaudited):
USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1998: Sales and transfers of oil and natural gas produced, net of production costs $ (27,449) $ (35) $ (27,484) Net changes in prices and production costs (46,042) (186) (46,228) Revisions in quantity estimates and changes in production timing (18,105) (335) (18,440) Extensions, discoveries and improved recovery, less related costs 28,096 - 28,096 Purchases of minerals in place 6,711 - 6,711 Sales of minerals in place (603) - (603) Accretion of discount 19,741 91 19,832 Net change in income taxes 18,352 486 18,838 Other - net 1,087 (13) 1,074 ----------- --------- ----------- Net change (18,212) 8 (18,204) Beginning of year 149,435 391 149,826 ----------- --------- ----------- End of year $ 131,223 $ 399 $ 131,622 =========== ========= ===========
1999: Sales and transfers of oil and natural gas produced, net of production costs $ (31,260) $ (44) $ (31,304) Net changes in prices and production costs 42,319 23 42,342 Revisions in quantity estimates and changes in production timing 987 44 1,031 Extensions, discoveries and improved recovery, less related costs 24,035 - 24,035 Purchases of minerals in place 8,612 - 8,612 Sales of minerals in place (320) - (320) Accretion of discount 8,096 44 8,140 Net change in income taxes (18,355) 7 (18,348) Other - net 1,888 4 1,892 ----------- --------- ----------- Net change 36,002 78 36,080 Beginning of year 131,223 399 131,622 ----------- --------- ----------- End of year $ 167,225 $ 477 $ 167,702 =========== ========= ===========
USA CANADA TOTAL ----------- --------- ----------- (In thousands) 2000: Sales and transfers of oil and natural gas produced, net of production costs $ (72,005) $ (91) $ (72,096) Net changes in prices and production costs 647,313 1,854 649,167 Revisions in quantity estimates and changes in production timing 44,991 (324) 44,667 Extensions, discoveries and improved recovery, less related costs 184,624 - 184,624 Purchases of minerals in place 23,144 - 23,144 Sales of minerals in place (3,469) - (3,469) Accretion of discount 19,881 51 19,932 Net change in income taxes (293,357) (581) (293,938) Other - net (43,760) 53 (43,707) ----------- --------- ----------- Net change 507,362 962 508,324 Beginning of year 167,225 477 167,702 ----------- --------- ----------- End of year $ 674,587 $ 1,439 $ 676,026 =========== ========= ===========
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 errors 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 ($25.55) and natural gas ($9.41) 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. This year-end spot natural gas price was significantly higher than the average natural gas price of $6.89 received by Unit in December 2000 and the natural gas price that Unit expects to receive in the future.
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 ACCOUNTANTS
The Shareholders and Board of Directors Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, 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, 1999 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the accompanying financial statement schedule 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.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma February 7, 2001
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and - ------- --------------------------------------------------------------- Financial Disclosure. ---------------------
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant - -------- --------------------------------------------------
The table below and accompanying footnotes set forth certain information concerning each executive officer of Unit. Unless otherwise indicated, each has served in the positions set forth for more than five years. Executive officers are elected for a term of one year. There are no family relationships between any of the persons named.
NAME AGE POSITION - ---------------- --- ----------------------------------------
King P. Kirchner 73 Chairman of the Board, Chief Executive Officer and Director
John G. Nikkel 66 President, Chief Operating Officer and Director
Earle Lamborn 66 Senior Vice President, Drilling and Director
Philip M. Keeley 59 Senior Vice President, Exploration and Production
Larry D. Pinkston 46 Vice President, Treasurer and Chief Financial Officer
Mark E. Schell 43 General Counsel and Secretary ________
Mr. Kirchner, a co-founder of Unit, has been the Chairman of the Board and a director since 1963 and was President until November 1983. Mr. Kirchner is a Registered Professional Engineer within the State of Oklahoma, having received degrees in Mechanical Engineering from Oklahoma State University and in Petroleum Engineering, with honors, from the University of Oklahoma. Following graduation, he was employed by, Lufkin Manufacturing as a development engineer for hydraulic pumping units. Prior to co-founding Unit, he served in the US Army during the Korean War and after that as vice-president - engineering and operations for Woolaroc Oil Company.
Mr. Nikkel joined Unit in 1983 as its President and a director. From 1976 until January 1982 when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and director of Cotton Petroleum Corporation, serving as the President of that Company from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel presently serves as President and a director of Nike Exploration Company. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 49 years, joining Unit's predecessor in 1952 prior to it becoming a publicly- held corporation. He was elected Vice President, Drilling in 1973 and to his current position as Senior Vice President and director in 1979.
Mr. Keeley joined Unit in November 1983 as a Senior Vice President, Exploration and Production. Prior to that time, Mr. Keeley co-founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and serves as Executive Vice President and a director of that company. From 1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation, serving first as Manager of Land and from 1979 as Vice President and a director. Before joining Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as Manager of Land and prior thereto he was employed by Texaco, Inc. for nine years. He received a Bachelor of Arts degree in Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined Unit in December 1981. He had served as Corporate Budget Director and Assistant Controller prior to being appointed as Controller in February 1985. He has been Treasurer since December 1986 and was elected to the position of Vice President and Chief Financial Officer in May 1989. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma and is a Certified Public Accountant.
Mr. Schell joined Unit in January of 1987, as its Secretary and General Counsel. From 1979 until joining Unit, Mr. Schell was Counsel, Vice President and a member of the Board of Directors of C & S Exploration, Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa Law School. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel Association and the American Society of Corporate Secretaries.
The balance of the information required in this Item 10 is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 2001 annual meeting of stockholders.
Item 11.
Item 11. Executive Compensation - -------- ----------------------
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2001 annual meeting of stockholders.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management - -------- --------------------------------------------------------------
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2001 annual meeting of stockholders.
Item 13.
Item 13. Certain Relationships and Related Transactions - -------- ----------------------------------------------
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2001 annual meeting of stockholders.
PART IV
Item 14.
Item 14. 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, 1999 and 2000 Consolidated Statements of Operations for the years ended December 31, 1998, 1999 and 2000 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 1998, 1999 and 2000 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1999 and 2000 Notes to Consolidated Financial Statements Report of Independent Accountants
2. Financial Statement Schedules: ------------------------------ Included in Part IV of this report for the years ended December 31, 1998, 1999 and 2000: 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: --------
2.1 Agreement and Plan of Merger dated November 21, 1997, by and among the Registrant, Unit Drilling Company, the Shareholders and Hickman Drilling Company (filed as an Exhibit to Unit's Form 8-K dated November 21, 1997, which is incorporated herein by reference).
2.2 Asset Purchase Agreement dated August 12, 1999, by and among Unit Corporation, Parker Drilling Company and Parker Drilling Company North America, Inc. (filed as Exhibit 99.1 to Unit's Form 8-K dated September 23, 1999, which is incorporated herein by reference).
2.3 Agreement and Plan of Merger, dated as of December 8, 1999, among Unit Corporation, Questa Oil & Gas Co. and Unit Acquisition Company (filed as Appendix A to the Proxy Statement/Prospectus which forms a part of Unit's Registration Statement on Form S-4 as S.E.C. File No. 333-94325, which is incorporated herein by reference).
2.4 Form of Stockholder Agreement, between Unit Corporation and the directors and executive officers of Questa Oil & Gas Co. (filed as Exhibit 2.2 of Unit's Registration Statement on Form S-4 as S.E.C. File No. 333-94325, which is incorporated herein by reference).
3.1.4 Amended and Restated Certificate of Incorporation of Unit Corporation dated May 11, 2000 (filed as Exhibit 3.1 to Unit's Form 8-K dated June 29, 2000, which is incorporated herein by reference).
3.2.2 By-Laws of Unit Corporation (filed as an Exhibit to Unit's Registration Statement on Form S-3 as S.E.C. file No. 333- 83551, which is incorporated herein by reference).
4.1 Form of Promissory Note to be issued to the Shareholders of Hickman Drilling Company pursuant to the Agreement and Plan of Merger dated November 21, 1997 (filed as an Exhibit to Unit's Form 8-K dated November 21, 1997, 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).
10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1998, which is incorporated herein by reference).
10.1.24 First Amendment to the Loan Agreement effective as of May 1, 1999 between and among Unit Corporation, Bank of Oklahoma, N.A., BankBoston, N.A., Bank of America, N.A. and Local Oklahoma Bank, N.A. (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended September 30, 1999, which is incorporated herein by reference).
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).
10.2.18 Unit 1991 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, 1991, which is incorporated herein by reference).
10.2.19 Unit 1992 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, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 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, 1992, 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).
10.2.26 Unit 1994 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, 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).
10.2.28 Unit 1995 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, 1994, which is incorporated herein by reference).
10.2.29 Unit 1996 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, 1995, 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).
10.2.31 Unit 1997 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, 1996).
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).
10.2.33 Unit 1998 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, 1997).
10.2.34 Unit 1999 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, 1998).
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 herewith).
10.2.39* Form of Unit Corporation Key Employee Change of Control Contract (filed herewith).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
* 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:
No reports on Form 8-K were filed during the quarter ended December 31, 2000.
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, 1998 $ 514 $ - $ 80 $ 434 ========== ========== ========== ========== Year ended December 31, 1999 $ 434 $ 305 $ 15 $ 583 ========== ========== ========== ========== Year ended December 31, 2000 $ 583 $ 350 $ 14 $ 919 ========== ========== ========== ==========
Deferred Tax Asset Valuation Allowance:
Balance Balance at at Beginning end of Description of period Additions Deductions period ----------- ---------- ---------- ---------- ---------- (In thousands) Year ended December 31, 1998 $ 1,552 $ - $ 1,022 $ 530 ========== ========== ========== ========== Year ended December 31, 1999 $ 530 $ - $ 195 $ 335 ========== ========== ========== ========== Year ended December 31, 2000 $ 335 $ - $ 335 $ - ========== ========== ========== ==========
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 20, 2001 By: /s/ John G. Nikkel -------------- --------------------------- JOHN G. NIKKEL President and Chief Operating 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 20h day of March, 2001.
Name Title - ------------------------------- -----------------------------------
/s/ King P. Kirchner - ------------------------------- Chairman of the Board and Chief KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel - ------------------------------- President and Chief Operating JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn - ------------------------------- Senior Vice President, Drilling, EARLE LAMBORN Director
/s/ Larry D. Pinkston - ------------------------------- Vice President, Chief Financial LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz - ------------------------------- Controller STANLEY W. BELITZ
/s/ J. Michael Adcock - ------------------------------- Director J. MICHAEL ADCOCK
/s/ Don Cook - ------------------------------- Director DON COOK
/s/ William B. Morgan - ------------------------------- Director WILLIAM B. MORGAN
/s/ John S. Zink - ------------------------------- Director JOHN S. ZINK
/s/ John H. Williams - ------------------------------- Director JOHN H. WILLIAMS
EXHIBIT INDEX ----------------------- Exhibit No. Description Page - ------- ----------------------------------------------- -----
10.2.38 Unit 2001 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership.
10.2.39 Form of Unit Corporation Key Employee Change of Control Contract.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.