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PTEN > SEC Filings for PTEN > Form 10-Q on 1-May-2013All Recent SEC Filings

Show all filings for PATTERSON UTI ENERGY INC | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for PATTERSON UTI ENERGY INC


1-May-2013

Quarterly Report


ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Management Overview - We are a leading provider of services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and pressure pumping services. In addition to the aforementioned services, we also invest, on a non-operating working interest basis, in oil and natural gas properties.

We have a drilling fleet that consists of more than 300 marketable land-based drilling rigs. There continues to be uncertainty with respect to the global economic environment and crude oil and natural gas prices remain volatile. During the first quarter of 2013, our average number of rigs operating in the United States was 188, compared to an average of 224 drilling rigs operating during the same period in 2012. During the first quarter of 2013, our average number of rigs operating in Canada was 11 compared to 13 drilling rigs operating during the first quarter of 2012.

We have addressed our customers' needs for drilling wells in the newer horizontal shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of March 31, 2013, we have completed 117 new APEX ® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 9 additional new APEX® rigs in the remainder of 2013. In connection with the newer horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of March 31, 2013, we had more than 750,000 hydraulic horsepower in our pressure pumping fleet. Low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America.


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We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more. Our backlog as of March 31, 2013 was approximately $1.14 billion. We expect approximately $626 million of our backlog to be realized in the remainder of 2013. We calculate our backlog by multiplying the day rate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer.

For the three months ended March 31, 2013 and 2012, our operating revenues consisted of the following (dollars in thousands):

                                           Three Months Ended March 31,
                                          2013                     2012
             Contract drilling     $ 419,094        63 %    $ 489,482        66 %
             Pressure pumping        231,160        35        241,722        32
             Oil and natural gas      16,785         2         14,717         2

                                   $ 667,039       100 %    $ 745,921       100 %

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the first quarter of 2013, our average number of rigs operating was 188 in the United States and 11 in Canada compared to 224 in the United States and 13 in Canada in the first quarter of 2012. Our average revenue per operating day was $23,410 in the first quarter of 2013 compared to $22,650 in the first quarter of 2012. Due primarily to reduced revenues in our contract drilling and pressure pumping segments, as well as higher depreciation, depletion and amortization expense, consolidated net income for the first quarter of 2013 was $56.2 million compared to consolidated net income of $97.3 million for the first quarter of 2012.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing for our services. Oil and natural gas prices and our monthly average number of rigs operating have declined from historic highs. In March 2013, our average number of rigs operating was 199.

We are highly impacted by competition, the availability of excess equipment, labor issues, weather and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see "Risk Factors" included in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

We believe that our liquidity as of March 31, 2013, which includes approximately $351 million in working capital, approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies - As of March 31, 2013, we maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2013, no amounts had been drawn under the letters of credit.

As of March 31, 2013, we had commitments to purchase approximately $128 million of major equipment for our drilling and pressure pumping businesses.


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Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016 and 2017. As of March 31, 2013, the remaining obligation under these agreements is approximately $35.0 million, of which materials with a total purchase price of approximately $7.2 million are expected to be delivered during the last three quarters of 2013. In the event that the required minimum quantities are not purchased during any contract year, the Company would be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance, on a non-revolving basis, up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and other assets and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of March 31, 2013, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $531,000 had been received resulting in a balance outstanding of approximately $11.2 million.

Trading and Investing - We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

Description of Business - We conduct our contract drilling operations primarily in the continental United States, Alaska and western and northern Canada. We have more than 300 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for completion of new wells and remedial work on existing wells. We also invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

The North American oil and natural gas services industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to efficiently compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

• movement of drilling rigs from region to region,

• reactivation of land-based drilling rigs, or

• construction of new technology drilling rigs.

Construction of new technology drilling rigs increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of conventional drilling rigs. Similarly, the substantial increase in unconventional resource plays has led to higher demand for pressure pumping services, and there has been a significant increase in the construction of new pressure pumping equipment across the industry. As a result of relatively low natural gas prices and the construction of new equipment, there is currently an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.


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Liquidity and Capital Resources

As of March 31, 2013, we had working capital of $351 million, including cash and cash equivalents of $144 million, compared to working capital of $340 million and cash and cash equivalents of $111 million at December 31, 2012.

During the three months ended March 31, 2013, our sources of cash flow included:

• $210 million from operating activities,

• $21.4 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and

• $707,000 in proceeds from the disposal of property and equipment.

During the three months ended March 31, 2013, we used $15.2 million to repurchase shares of our common stock, $7.3 million to pay dividends on our common stock, $1.3 million to repay long-term debt and $174 million:

• to build new drilling rigs and pressure pumping equipment,

• to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment,

• to acquire and procure equipment and facilities to support our drilling and pressure pumping operations, and

• to fund investments in oil and natural gas properties on a working interest basis.

We paid cash dividends during the three months ended March 31, 2013 as follows:

Per Share Total
(in thousands)

Paid on March 29, 2013 $ 0.05 $ 7,312

On April 24, 2013, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on June 28, 2013 to holders of record as of June 14, 2013. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

On July 25, 2012, our Board of Directors approved a stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions. During the three months ended March 31, 2013, no shares were purchased under the stock buyback program. As of March 31, 2013, we had remaining authorization to purchase approximately $51.1 million of our outstanding common stock under the stock buyback program.

On September 27, 2012, we entered into a Credit Agreement (the "Credit Agreement"). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.


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Subject to customary conditions, we may request that the lenders' aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of March 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each of our domestic subsidiaries other than immaterial subsidiaries has unconditionally guaranteed all of our existing and future indebtedness and liabilities of the other guarantors arising under the Credit Agreement and other loan documents. Such guarantees also cover our obligations and those of any of our subsidiaries arising under any interest rate swap contract with any person while such person is a lender under the Credit Agreement.

The Credit Agreement also requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of
(a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of March 31, 2013. The Credit Agreement also contains customary representations, warranties, indemnities and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic), and
(iii) requires us to cash collateralize any outstanding letters of credit.

As of March 31, 2013, we had $97.5 million principal amount outstanding under the term loan facility at an interest rate of 2.625% and no amounts outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at March 31, 2013 and, as a result, we had available borrowing of approximately $460 million at that date.

On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the "Series A Notes") in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.27% Series B Senior Notes due June 14, 2022 (the "Series B Notes") in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations which rank equally in right of payment with all of our other unsubordinated indebtedness. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of our existing domestic subsidiaries other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a "make-whole" premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.


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The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to
(b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of March 31, 2013. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under a note purchase agreement occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

We believe that our liquidity as of March 31, 2013, which included approximately $351 million in working capital, and approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

The following tables summarize operations by business segment for the three
months ended March 31, 2013 and 2012:



Contract Drilling                                        2013              2012           % Change
                                                        (Dollars in thousands)
Revenues                                             $    419,094        $ 489,482            (14.4 )%
Direct operating costs                               $    247,072        $ 282,649            (12.6 )%
Selling, general and administrative                  $      1,851        $   1,336             38.5 %
Depreciation and impairment                          $     97,622        $  93,726              4.2 %
Operating income                                     $     72,549        $ 111,771            (35.1 )%
Operating days                                             17,903           21,610            (17.2 )%
Average revenue per operating day                    $      23.41        $   22.65              3.4 %
Average direct operating costs per operating day     $      13.80        $   13.08              5.5 %
Average rigs operating                                        199              237            (16.0 )%
Capital expenditures                                 $    134,383        $ 200,607            (33.0 )%

Revenues and direct operating costs decreased in 2013 compared to 2012 as a result of fewer operating days. A greater number of APEX® rigs working combined with fewer total rigs working caused an increase in the average revenue per operating day. We received a $2.9 million early termination payment for one rig that also caused an increase in the average revenue per operating day in 2013. Average direct operating costs per operating day increased in 2013 due primarily to higher labor and related costs. Capital expenditures were incurred in 2013 and 2012 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased primarily as a result of capital expenditures.


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Pressure Pumping                                       2013              2012           % Change
                                                      (Dollars in thousands)
Revenues                                           $    231,160        $ 241,722             (4.4 )%
Direct operating costs                             $    168,156        $ 166,857              0.8 %
Selling, general and administrative                $      4,253        $   4,275             (0.5 )%
Depreciation and amortization                      $     30,236        $  23,803             27.0 %
Operating income                                   $     28,515        $  46,787            (39.1 )%
Fracturing jobs                                             266              330            (19.4 )%
Other jobs                                                1,142            1,659            (31.2 )%
Total jobs                                                1,408            1,989            (29.2 )%
Average revenue per fracturing job                 $     784.60        $  625.98             25.3 %
Average revenue per other job                      $      19.66        $   21.19             (7.2 )%
Average revenue per total job                      $     164.18        $  121.53             35.1 %
Average direct operating costs per total job       $     119.43        $   83.89             42.4 %
Capital expenditures                               $     30,234        $  54,574            (44.6 )%

Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional equipment through . . .

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