CORRESP 1 filename1.htm

CORRESP

August 31, 2015

VIA EDGAR

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Attention: Ethan Horowitz

Re: Patterson-UTI Energy, Inc.

Form 10-K for Fiscal Year Ended December 31, 2014

Filed February 12, 2015

Form 10-Q for Fiscal Quarter Ended June 30, 2015

Filed July 27, 2015

File No. 000-22664

Dear Mesdames and Sirs:

By letter dated August 17, 2015, Patterson-UTI Energy, Inc. (the “Company”) received the Staff’s comments relating to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015. The following numbered paragraphs repeat the comments for your convenience, followed by our responses to those comments.

Form 10-K for Fiscal Year Ended December 31, 2014

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 21

Critical Accounting Policies, page 23

Property and Equipment, page 23

1. Disclosure in your Form 10-K states that in light of the significant decline in oil and natural gas commodity prices you assessed the recoverability of long-lived assets within your contract drilling and pressure pumping segments. Please expand your disclosure to provide additional detail regarding your impairment testing. Specifically, your revised disclosure should:

• describe the methods and key assumptions used and how the key assumptions were determined;

• discuss the degree of uncertainty associated with these key assumptions and the factors that create variability in assumptions; and

• address potential events and/or changes in circumstances that could reasonably be expected to affect the key assumptions.

As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014, in light of the significant decline in oil and natural gas commodity prices, we assessed the recoverability of long-lived assets within our contract drilling and pressure pumping segments. While we disclosed that we estimated future cash flows over the expected life of the assets and

disclosed our conclusion that no impairment was needed, in future filings we will provide further detail regarding our estimates and assumptions impacting future assessments when meaningful to an understanding of our conclusion. Following is an example of the revised disclosure as it would have appeared in the Form 10-K for the fiscal year ended December 31, 2014 (the underlined text is the proposed revision to the disclosure):

In light of the significant decline in oil and natural gas commodity prices beginning in the fourth quarter of 2014 and continuing into 2015, we deemed it necessary to perform a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling and pressure pumping segments. With respect to these assets, we estimated future cash flows over the expected remaining life of the assets, and determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets. The expected cash flows for our contract drilling segment include our backlog of commitments for contract drilling revenues under term contracts, which was approximately $1.5 billion at December 31, 2014. We expect approximately $953 million of our backlog to be realized in 2015. Rigs not under term contracts will be subject to pricing in the spot market. Utilization and rates for rigs in the spot market and for our pressure pumping segment were estimated based upon our historical experience in prior downturns. Also, the expected cash flows for our contract drilling and pressure pumping segments are based on the assumption that oil prices and activity levels in both segments would begin to recover in late 2015 and continue to recover in 2016. This oil price assumption is consistent with forecast information published by the United States Energy Information Administration in January 2015. While we believe our assumptions with respect to future pricing for oil and natural gas were reasonable, actual future prices may vary significantly from the ones we assumed. Based on this assessment, no impairment was indicated. Impairment considerations related to our oil and natural gas segment are discussed below.

2. Please tell us about rig utilization rates as of December 31, 2014 and June 30, 2015 using classifications similar to the information presented on page 5 of your Form 10-K. In addition, please describe management’s plans for rigs not currently under contract including your prospects for entering into drilling contracts.

For competitive reasons, we do not disclose information about utilization of the three different APEX^® rig classifications reflected on page 5 of our Form 10-K. To the extent that we disclose utilization information, we classify the rigs into three classifications as follows: APEX^® rigs, other electric rigs and mechanical rigs. Summarized on this basis, rigs operating as of December 31, 2014 and June 30, 2015 by rig class were as follows:

		December 31, 2014												June 30, 2015
		Fleet				Operating				Utilization				Fleet				Operating				Utilization
APEX® rigs			145				141				97	%			158				92				58	%
Other electric rigs			50				37				74	%			50				11				22	%
Mechanical rigs			44				35				80	%			43				8				19	%
Total			239				213				89	%			251				111				44	%

As evidenced by the decline in rig utilization reflected above, demand for land drilling rigs in North America has declined significantly in 2015 as a result of the collapse in oil prices which began in the fourth quarter of 2014. A rig is “stacked” when it is released by a customer and we have not entered into a new contract for that rig to work. Generally, stacked rigs are stored in secure locations and major components are serviced in an effort to maintain the stacked rigs in a condition whereby they can be reactivated without incurring excessive cost if demand improves. We currently believe that until oil or natural gas prices improve, we will not experience any meaningful increase in demand for North American land drilling rigs.

APEX^® rigs are newer/higher technology, electric-powered land drilling rigs which, on average, have achieved higher utilization than our other rigs over the past five years. Our other electric rigs are, on average, less technologically advanced than the APEX^® rigs. These rigs also have somewhat lower utilization than our APEX^® rigs. Our mechanical rig fleet consists of older rigs that are not technologically advanced by today’s standards. Our mechanical rigs have lower utilization than our APEX^® and other electric rigs. Our mechanical rig fleet has, however, continued to contribute to our profitability.

At least annually, we evaluate our fleet of drilling rigs for marketability based on the condition of each rig, expenditures that would be necessary to bring stacked rigs to working condition and the expected demand for drilling services by rig type. We also carefully monitor the carrying value of our land rig fleet. Since the beginning of 2009, we have retired 212 mechanical rigs (including 55 in 2014) and twelve other electric rigs (including six in 2014). We will continue to evaluate our rig fleet and retire rigs that are not deemed marketable.

Goodwill, page 24

3. We note that you determined based on an assessment of qualitative factors that it was more likely than not that the fair values of your reporting units were greater than their carrying amounts. However, disclosure in your Form 10-K states that your industry is experiencing a severe downturn and that 2015 will be a challenging year. Please tell us how you were able to reach this conclusion based on recent industry and market conditions along with the volatility in oil and natural gas prices noted in your filing. Refer to FASB ASC 350-20-35.

ASC 350-20-35-3 states that a company has the option to first assess qualitative factors to determine whether the existence of events or circumstances would lead to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, a company determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the two-step impairment test is considered to be unnecessary. Given this guidance, we elected to use the qualitative approach to determine if the quantitative approach was necessary. Our qualitative assessment of goodwill was a comprehensive analysis of factors set forth in ASC 350-20-35-3C. Each factor was first evaluated to determine if its impact on each reporting unit’s fair value was positive, negative or neutral. We then assessed the magnitude of the potential impact of each factor as being high, medium or low. We also considered whether the evidence supporting these assessments was objective or subjective. The key factors we considered included the following:

• Oil and natural gas prices have historically been volatile, and the current price decline is not expected to be permanent. The Short-Term Energy Outlook published by the United States Energy Information Administration (January 2015) forecast that the price of West Texas Intermediate (“WTI”) would increase by the end of 2015 and continue to increase through 2016. The industry experienced similar periods of extreme commodity price volatility in 2008 and 2009 which resulted in a depressed period of activity that recovered in 2010 and 2011. We did not recognize any impairments of goodwill during this previous downturn and the subsequent recovery.

• The most recent quantitative assessment of the Contract Drilling and Pressure Pumping reporting units based on discounted cash flows was prepared as of December 31, 2013. While industry conditions have deteriorated since the end of 2013, the last quantitative assessments indicated that the fair values of both reporting units exceeded their carrying values by significant margins.

• Because of the ordering of our impairment testing for tangible long-lived assets and the fact that the carrying values of our asset groups comprise the substantial majority of net assets within our respective Contract Drilling and Pressure Pumping reporting units, we took into consideration our testing for recoverability under ASC 360-10-35 as of December 31, 2014 (which is also discussed in our response to comment 1 above). The results of our testing not

only supported our conclusion that our asset groups were not impaired but also the ability of our reporting units to continue to generate significant cash flows in the current depressed industry environment, even when factored for the undiscounted nature of that test.

• At December 31, 2014, the Company’s market capitalization was $2.4 billion compared to total stockholders’ equity of $2.9 billion. Our book equity implied a share price of approximately $19.84 compared to the closing market price on December 31, 2014 of $16.59. However, we believed the following considerations were important in considering the implications of our share price at December 31, 2014 and whether the share price decrease during the last fiscal quarter of 2014 was indicative of a long-term or sustained change:

• The Company’s share price is influenced by current trends in the exploration and production industry as well as crude oil and natural gas commodity prices; yet, the EIA was forecasting in January 2015 that the price of WTI would increase by the end of 2015 and continue to increase through 2016, which would lead to increased activity in the industry and an increase in the Company’s share price.

• The Company’s year-end share price reflected a non-controlling interest value; however, the Company believed a control premium was reasonable in assessing the enterprise value of the Company, which would indicate an enterprise value in excess of the year-end implied market capitalization. At December 31, 2014, the Company’s book value was approximately 20% greater than its market capitalization and at February 6, 2015 the book value was approximately 10% greater than its market capitalization. The Company believed a control premium of up to 50% was reasonable (based on observable oil field service transactions) in assessing the enterprise value of the Company, which would result in an implied enterprise value in excess of book value.

• The Company’s share price had rebounded to $18.01 as of February 6, 2015.

• In December 2014, a third party report estimated that the Net Asset Value (“NAV”) of the Company’s U.S. drilling assets (excluding all mechanical rigs) was $2.6 billion and the replacement value of the Company’s pressure pumping assets was between $990 million and $1.8 billion. Another third party report in December 2014 estimated that the NAV of the Company was $5.2 billion.

After considering these factors, we formed an overall conclusion that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts.

Form 10-Q for Fiscal Quarter Ended June 30, 2015

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 21

4. Remarks attributed to you as part of the conference call to discuss your operating results for the quarter ended June 30, 2015 indicate that you have stacked approximately one-third of your horsepower. While you state that your pressure pumping business is experiencing the effects of reduced spending by customers and downward pressure on pricing in your Form 10-Q, it does not appear that information regarding the status of your pressure pumping equipment is conveyed as part of this disclosure. Please tell us how you considered providing this type of information as part of your discussion of key performance indicators. With your response, please tell us about your near-term expectations for the deployment of stacked pressure pumping equipment.

We believe that the key performance indicators for pressure pumping activity are the number of fracturing jobs and the average revenue per fracturing job that are presented in the tables on pages 28 and 30 of the Form 10-Q.

We have 443 frac pumps which represent approximately one million horsepower of fracturing capacity. These pumps are deployed to jobs in groups of pumps based upon the customer’s horsepower requirements for each job. With fewer jobs in this market environment, we have elected to concentrate wear and tear in a smaller number of pieces of equipment by parking (or “stacking”) a portion of the equipment. Alternatively, we could rotate the equipment

from job to job and spread the wear and tear evenly over each piece of equipment. Under such a scenario, every piece of equipment could potentially work every week. Since the amount of stacked equipment can vary as a result of such operating decisions without regard to the underlying activity, we do not believe that it should be included as a key performance indicator. This parked equipment can be readily deployed to customer locations at current activity levels or as activity levels improve.

We currently believe that until oil or natural gas prices improve, we will not experience any meaningful increase in demand for U.S. pressure pumping equipment.

The Company acknowledges that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

• Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please do not hesitate to call me at (214) 765-5525 if you have any questions or would like any additional information regarding these matters.

Very truly yours,

/s/ John E. Vollmer III

John E. Vollmer III

Senior Vice President-Corporate Development,

Chief Financial Officer and Treasurer