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| UNT > SEC Filings for UNT > Form 10-Q on 3-May-2007 | All Recent SEC Filings |
3-May-2007
Quarterly Report
FINANCIAL CONDITION
Management's Discussion and Analysis (MD&A) provides an understanding of operating results and financial condition by focusing on changes in key measures from year to year. MD&A is organized in the following sections:
• Financial Condition
• New Accounting Pronouncements
• Results of Operations
MD&A should be read in conjunction with the Consolidated Condensed Financial Statements and related notes included in this report.
Summary. Our financial condition and liquidity depends on the cash flow from our three principal business segments (and our subsidiaries that carry out those operations) and borrowings under our bank credit agreement.
Our cash flow is influenced mainly by:
• the prices we receive for our natural gas production and,
to a lesser extent, the prices we receive for our oil
production;
• the quantity of natural gas and oil we produce;
• the demand for and the dayrates we receive for our drilling
rigs; and
• the margins we obtain from our natural gas gathering and
processing contracts.
Our three principal business segments are:
• land contract drilling carried out by our subsidiary Unit
Drilling Company and its subsidiary Unit Texas Drilling,
L.L.C.;
• oil and natural gas exploration, carried out by our
subsidiary Unit Petroleum Company and its subsidiaries; and
• mid stream operations (consisting of natural gas buying,
selling, gathering and processing) carried out by our
subsidiary Superior Pipeline Company, L.L.C.
The following is a summary of certain financial information as of March 31, 2007 and 2006 and for the three months ended March 31, 2007 and 2006:
March 31, March 31, Percent
2007 2006 Change
(In thousands except percent amounts)
Working Capital $ 47,292 $ 44,242 7 %
Long-Term Debt $ 152,000 $ 90,300 68 %
Shareholders' Equity $ 1,225,651 $ 913,411 34 %
Ratio of Long-Term Debt to 11 % 9 % 22 %
Total Capitalization
Net Income $ 64,482 $ 74,913 (14 )%
Net Cash Provided by $ 128,706 $ 140,849 (9 )%
Operating Activities
Net Cash Used in Investing $ (111,251 ) $ (81,159 ) 37 %
Activities
Net Cash Used In Financing $ (17,441 ) $ (59,816 ) (71 )%
Activities
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The following table summarizes certain operating information for the three months ended March 31, 2007 and 2006:
March 31, March 31, Percent
2007 2006 Change
Oil Production (MBbls) 356 327 9 %
Natural Gas Production (MMcf) 10,673 10,713 --- %
Average Oil Price Received $ 47.59 $ 54.53 (13 )%
Average Oil Price Received $ 47.59 $ 54.53 (13 )%
Excluding Hedges
Average Natural Gas Price $ 6.37 $ 7.04 (10 )%
Received
Average Natural Gas Price
Received Excluding
Hedges $ 6.36 $ 7.04 (10 )%
Average Number of Our
Drilling Rigs in Use During
the Period 96.8 108.6 (11 )%
Total Number of Drilling Rigs
Available at the End
of the Period 118 111 6 %
Average Dayrate $ 19,427 $ 17,122 13 %
Gas Gathered-MMBtu/day 226,081 215,341 5 %
Gas Processed-MMBtu/day 43,327 30,668 41 %
Number of Active Natural Gas 37 36 3 %
Gathering Systems
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At March 31, 2007, we had unrestricted cash totaling $0.6 million and we had borrowed $152.0 million of the $275.0 million we have available under our credit agreement.
Our Credit Facility. At March 31, 2007, we had a $275 million revolving credit facility maturing on May 31, 2008. Borrowings under the credit facility are limited to a commitment amount, but we may elect to have a smaller amount available. At March 31, 2007, we had elected to have the full $275.0 million available as the commitment amount. We are charged a commitment fee of .375 of 1% on the amount available but not borrowed. We incurred origination, agency and syndication fees of $515,000 at the inception of the agreement, $40,000 of which will be paid annually and the remainder of the fees amortized over the life of the agreement. During 2005 and 2006, we incurred additional origination; agency and syndication fees of $187,500 and $60,000, respectively while amending the credit facility and these fees are being amortized over the remaining life of the agreement. The average interest rate for the first quarter of 2007 was 6.5%. At March 31, 2007 and April 27, 2007, our borrowings were $152.0 million and $166.9 million, respectively.
The borrowing base under the current credit facility is subject to re-determination on May 10 and November 10 of each year. The latest redetermination supported a borrowing base of $375.0 million. Each re-determination is based primarily on a percentage of the discounted future value of our oil and natural gas reserves, as determined by the banks. The determination of our borrowing base also includes an amount representing a small part of the value of our drilling rig fleet (limited to $20 million) as well as such loan value as the lenders reasonably attribute to Superior Pipeline Company's cash flow as defined in the credit agreement. The credit facility allows for one requested special re-determination of the borrowing base by either the banks or us between each scheduled re-determination date.
At our election, any part of the outstanding debt may be fixed at a London Interbank Offered Rate (LIBOR) Rate for a 30, 60, 90 or 180 day term. During any LIBOR Rate funding period the outstanding principal balance of the note to which such LIBOR Rate option applies may be repaid on three days prior notice to the administrative agent and subject to the payment of any applicable funding indemnification amounts. Interest on the LIBOR Rate is computed at the LIBOR Base Rate applicable for the interest period plus 1.00% to 1.50% depending on the level of debt as a percentage of the total loan value and payable at the end of each term or every 90 days whichever is less. Borrowings not under the LIBOR Rate bear interest at the JPMorgan Chase Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty. At March 31, 2007, $145.6 million of the $152.0 million we had borrowed was subject to the LIBOR rate.
The credit facility includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year,
. the incurrence of additional debt with certain limited exceptions, and
. the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our property, except in favor of our banks.
The credit facility also requires that we have at the end of each quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the loan agreement) of not less than 1 to 1, and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined in the loan agreement) for the most recently ended rolling four fiscal quarters of no greater than 3.25 to 1.0.
On March 31, 2007, we were in compliance with the covenants in the credit facility.
In February 2005, we entered into an interest rate swap to help manage our exposure to possible future interest rate increases. The contract swaps $50.0 million of variable rate debt to fixed and covers the period from March 1, 2005 through January 30, 2008. The fixed rate is 3.99%. The swap is a cash flow hedge. As a result of this interest rate swap, our interest expense was decreased by $0.2 million in the first quarter of 2007. The fair value of the swap was recognized on the March 31, 2007 balance sheet as current derivative assets totaling $0.5 million and a gain of $0.4 million, net of tax, in accumulated other comprehensive income.
Contractual Commitments. At March 31, 2007, we have the following contractual obligations:
Payments Due by Period
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
(In thousands)
Bank Debt (1) $ 161,989 $ 8,558 $ 153,431 $ --- $ ---
Retirement Agreements (2) 1,224 726 498 --- ---
Operating Leases (3) 4,488 1,446 2,583 459 ---
Drill Pipe and
Drilling Components (4) 33,195 33,195 --- --- ---
SerDrilco Inc. Earn-Out
Agreement (5) 17,866 17,866 --- --- ---
Total Contractual
Obligations $ 218,762 $ 61,791 $ 156,512 $ 459 $ ---
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(1) See the previous discussion in MD&A regarding our bank credit facility. This obligation is presented in accordance with the terms of the credit facility and includes interest calculated at the March 31, 2007 interest rate of 6.4% including the effect of the interest rate swap related to $50.0 million of the outstanding debt.
(2) In the second quarter of 2001, we recorded $1.3 million in employee benefit expense for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, is paid in monthly payments of $25,000 through June 2009. In the first quarter of 2004, we assumed a liability for the present value of a separation agreement between PetroCorp Incorporated
and one of its previous officers. The liability associated with this agreement will be paid in quarterly payments of $12,500 through December 31, 2007. In the first quarter of 2005, we recorded $0.7 million in employee benefit expense for the present value of a separation agreement made in connection with the retirement of John Nikkel from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, will be paid in monthly payments of $31,250 starting in November 2006 and continuing through October 2008. These liabilities as presented above are undiscounted.
(3) We lease office space in Tulsa and Woodward, Oklahoma; Houston and Midland, Texas; and Denver, Colorado under the terms of operating leases expiring through January 31, 2012. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess rig equipment and production inventory.
(4) Due to the potential for limited availability of new drill pipe within the industry, we have committed to purchase approximately $30.7 million of drill pipe and drill collars. We have also committed to purchase $3.1 million of rig components with 20% or $0.6 million paid through March 31, 2007.
(5) On December 8, 2003, the company acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest, L.L.C., for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to receive one-half of the cash flow in excess of $10.0 million for each of the three years following the acquisition. For the year ending December 31, 2006, the third and final year of the earn-out period, the drilling rigs included in the earn-out provision had cash flow providing an earn-out of $17.9 million which was paid in April 2007.
At March 31, 2007, we also had the following commitments and contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
(In thousands)
Deferred Compensation
Plan (1) $ 2,763 Unknown Unknown Unknown Unknown
Separation Benefit
Plans (2) $ 3,752 $ Unknown Unknown Unknown Unknown
Plugging Liability (3) $ 34,255 $ 1,091 $ 2,262 $ 3,079 $ 27,823
Gas Balancing
Liability (4) $ 1,080 Unknown Unknown Unknown Unknown
Repurchase
Obligations (5) Unknown Unknown Unknown Unknown Unknown
Workers' Compensation
Liability (6) $ 22,643 $ 8,220 $ 4,182 $ 1,505 $ 8,736
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(1) We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our consolidated condensed balance sheet, at the time of deferral.
(2) Effective January 1, 1997, we adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit
Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of the company 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. On May 5, 2004 we also adopted the Special Separation Benefit Plan ("Special Plan"). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant's reaching the age of 65 or serving 20 years with the company. At March 31, 2007, there were 33 eligible employees participating in the plan.
(3) When a well is drilled or acquired, under Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143), we have recorded the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
(4) We have recorded a liability for certain properties where we believe there are insufficient oil and natural gas reserves available to allow the under-produced owners to recover their under-production from future production volumes.
(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2007, with a subsidiary of ours serving as general partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $7,000, $4,000 and $14,000 in 2006, 2005 and 2004, respectively and have not had any repurchases in 2007.
(6) We have recorded a liability for future estimated payments related to workers' compensation claims primarily associated with our contract drilling segment.
Hedging. Periodically we hedge the prices we will receive for a portion of our future natural gas and oil production. We do so in an attempt to reduce the impact and uncertainty that price variations have on our cash flow.
In January and February of 2007, we entered into the following two natural gas collar contracts.
First Contract:
Production volume covered 10,000 MMBtus/day
Period covered March through December of 2007
Prices Floor of $6.00 and a ceiling of $10.00
Underlying commodity price Centerpoint Energy Gas Transmission Co.,
East - Inside FERC
Second Contract:
Production volume covered 10,000 MMBtus/day
Period covered March through December of 2007
Prices Floor of $6.25 and a ceiling of $9.25
Underlying commodity price Centerpoint Energy Gas Transmission Co.,
East - Inside FERC
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In December 2006, we entered into the following natural gas hedging transaction.
First Contract:
Production volume covered 10,000 MMBtus/day
Period covered January through December of
2007
Prices Floor of $6.00 and a ceiling
of $9.60
Underlying commodity price Centerpoint Energy Gas
Transmission Co.,
East - Inside FERC
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All of the hedges for 2007 are cash flow hedges and there is no material amount of ineffectiveness. The fair value of the hedge these three hedge transactions was recognized on the March 31, 2007 balance sheet as current derivative liability totaling $1.2 million and a loss of $0.8 million, net of tax, in accumulated other comprehensive income.
In February 2005, we entered into an interest rate swap to help manage our exposure to possible future interest rate increases. The contract swaps $50.0 million of variable rate debt to fixed and covers the period from March 1, 2005 through January 30, 2008. The fixed rate is based on three-month LIBOR and is at 3.99%. The swap is a cash flow hedge. As a result of this interest rate swap, our interest expense was decreased by $0.2 million in the first quarter of 2007 and $0.1 million in the first quarter of 2006. The fair value of the swap was recognized on the March 31, 2007 balance sheet as current derivative assets totaling $0.5 million and a gain of $0.4 million, net of tax, in accumulated other comprehensive income.
Self-Insurance. We are self-insured for certain losses relating to workers' compensation, general liability, property damage, control of well and employee medical benefits. In addition, our insurance policies contain deductibles or retentions per occurrence that range from $0.5 million for Oklahoma workers' compensation to $1.0 million for general liability and drilling rig physical damage. We have purchased stop-loss coverage in order to limit, to the extent feasible, our per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage we have will adequately protect us against liability from all potential consequences. If our insurance coverage becomes more expensive, we may choose to decrease our limits and increase our deductibles rather than pay higher premiums. We have elected to use an ERISA governed occupational injury benefit plan to cover the field and support staff for drilling operations in the State of Texas in lieu of covering them under an insured Texas workers' compensation plan.
Impact of Prices for Our Oil and Natural Gas. Natural gas comprises approximately 85% of our total oil and natural gas reserves. Any significant change in natural gas prices has a material effect on our revenues, cash flow and the value of our oil and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by world wide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we can not predict nor measure their future influence on the prices we will receive.
Based on our first quarter 2007 production, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $337,000 per month ($4.0 million annualized) change in our pre-tax operating cash flow. Our first quarter 2007 average natural gas price was $6.37 compared to an average natural gas price of $7.04 for the first quarter of 2006. A $1.00 per barrel change in our oil price would have a $112,000 per month ($1.3 million annualized) change in our pre-tax operating cash flow based on our production in the first quarter of 2007. Our first quarter 2007 average oil price was $47.59 compared with an average oil price of $54.53 received in the first quarter of 2006.
Because oil and natural gas prices have such a significant affect on the value of our oil and natural gas reserves, declines in these prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely effect the semi-annual determination of the amount available for us to borrow under our bank credit facility since that determination is based mainly on the value of our oil and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects.
Most of our natural gas production is sold to third parties under month-to-month contracts.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures are discretionary and directed toward future growth. Our decision to increase our oil and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We drilled 54 wells (22.95 net wells) in the
first quarter of 2007 compared to 41 wells (10.84 net wells) in the first quarter of 2006. Our total capital expenditures for oil and natural gas exploration and acquisitions in the first quarter of 2007 totaled $70.4 million. Based on current prices, we plan to drill an estimated 270 wells in 2007 and estimate our total capital expenditures for oil and natural gas exploration to be approximately $326.0 million. Whether we are able to drill the full number of wells we are planning on drilling is dependent on a number of factors, many of which are beyond our control and include the availability of drilling rigs, the weather and the efforts of outside industry partners.
On May 16, 2006, we closed the acquisition of certain oil and natural gas properties from a group of private entities for approximately $32.4 million in cash. Proved oil and natural gas reserves involved in this acquisition consisted of approximately 14.2 Bcfe. The effective date of this acquisition was April 1, 2006 and results from this acquisition were included in the statement of income beginning May 1, 2006.
On October 13, 2006, we completed the acquisition of Brighton Energy, L.L.C., a privately owned oil and natural gas company for approximately $67.0 million in cash. Included in this acquisition were all of Brighton's oil and natural gas assets (excluding Atoka and Coal counties in Oklahoma) and included approximately 23.1 Bcfe of proved reserves. The majority of the acquired reserves are located in the Anadarko Basin of Oklahoma and the onshore Gulf Coast basins of Texas and Louisiana, with additional reserves in Arkansas, Kansas, Montana, North Dakota and Wyoming. This acquisition had an effective date of August 1, 2006 and results of operations from this acquisition are included in the statement of income beginning October 1, 2006 with the results for the period from August 1, 2006 through September 30, 2006 included as an adjustment to the purchase price.
Contract Drilling. Our drilling work is subject to many factors that influence the number of drilling rigs we have working as well as the costs and revenues associated with that work. These factors include the demand for drilling rigs, competition from other drilling contractors, the prevailing prices for natural gas and oil, availability and cost of labor to run our rigs and our ability to supply the equipment needed.
Although rig utilization declined in the fourth quarter of 2006 and into the first quarter of 2007, we do not anticipate declines in labor cost per hour due to the competition within the industry to keep qualified employees and attract individuals with the skills required to meet the future technological requirements of the drilling industry. To help keep qualified labor, we previously implemented longevity pay incentives and as recently as the second quarter of 2006 provided pay increases in some of our operating districts. To date, these efforts have allowed us to meet our labor requirements. However, if current demand for drilling rigs strengthens above the first quarter levels of 83%, shortages of experienced personnel may limit our ability to operate our drilling rigs.
We currently do not have any shortages of drill pipe and drilling equipment. Because of the potential for shortages in the availability of new drill pipe, at March 31, 2007 we have commitments to purchase approximately $30.7 million of drill pipe and drill collars in 2007. We have also committed to purchase $3.1 million of rig components with 20% or $0.6 million paid through March 31, 2007.
Most of our contract drilling fleet is targeted to the drilling of natural gas wells so changes in natural gas prices have a disproportionate influence on the demand for our drilling rigs as well as the prices we can charge for our contract drilling services. In March 2007, our average dayrate for the 118 drilling rigs that we owned was $19,028 with an 83% utilization rate. In the first quarter of 2007 our average dayrate was $19,427 per day compared to $17,122 in the first quarter of 2006. The average number of drilling rigs used was 96.8 (83%) in the first quarter of 2007 compared to 108.6 (98%) in the first quarter of 2006. Based on the average utilization of our drilling rigs during the first quarter of 2007, a $100 per day change in dayrates has a $9,680 per day ($3.5 million annualized) change in our pre-tax operating cash flow. Industry demand for our drilling rigs remained strong throughout the first nine months of 2006 before declining in the fourth quarter of 2006 and into the first quarter of 2007. The reduction in demand for drilling rigs was primarily the result of the evaluation of the economics of drilling prospects by the operators using our contract drilling services after natural gas prices declined significantly in the last half of the third quarter of 2006 combined with high . . .
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