CORRESP 1 filename1.htm corresp
[BAKER BOTTS L.L.P. LETTERHEAD]
July 21, 2009
Via EDGAR and Overnight Mail
Mr. John P. Lucas
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street NE
Washington D.C. 20549
Re:   Pride SpinCo, Inc.
Amendment No. 4 to Registration Statement on Form 10
Filed July 6, 2009
File No. 1-34231
Dear Mr. Lucas:
On behalf of Pride SpinCo, Inc. (the “Registrant”), we transmit herewith for electronic filing via the EDGAR system a memorandum of the Registrant responding to the comments received from the staff of the Division of Corporation Finance of the Securities and Exchange Commission, by facsimile dated July 14, 2009.
Please telephone the undersigned (713.229.1856) with any questions or comments you may have regarding the enclosed.
         
  Very truly yours,


BAKER BOTTS L.L.P.
 		  
  By:   /s/ Eric C. Swanson    
    Eric C. Swanson   
       
 
Enclosures
cc:   Randall D. Stilley
Pride SpinCo, Inc.

H. Roger Schwall
Anne Nguyen Parker
Suying Li
Christopher White
Sandra Eisen
United States Securities and Exchange Commission

 

 

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MEMORANDUM
     
TO:
  Division of Corporation Finance
Securities and Exchange Commission
 
    
FROM:
  Pride SpinCo, Inc.
 
    
DATE:
  July 21, 2009
 
    
RE:
  Amendment No. 4 to Registration Statement on Form 10
Filed July 6, 2009; File No. 1-34231
Response to SEC Comments dated July 14, 2009
     We are responding to comments received from the staff of the Division of Corporation Finance of the Securities and Exchange Commission (the “Staff”) by facsimile dated July 14, 2009 relating to the above-referenced filing (the “Registration Statement”) of Pride SpinCo, Inc. (the “Company”). For your convenience, our responses are prefaced by the corresponding Staff comment in italicized text.
Amendment No. 4 to Registration Statement on Form 10
Exhibit 99-1
Unaudited Pro Forma Combined Financial Information, page 45
1.   We note your response to prior comment 2 from our letter dated June 26, 2009. Please add disclosure either in the introductory paragraphs to this section or in the footnotes on page 49 to clarify that contingent obligations relating to the Mexican tax assessments are excluded from the pro forma balance sheet. Include the amounts of the assessments and anticipated potential assessments or refer to related disclosure elsewhere in your filing.
 
    Response: In response to the Staff’s comment, we will revise the information statement in our next amendment to the Registration Statement to add, on page 45 immediately following the disclosure in bullet points describing the transactions reflected in the adjustments to the pro forma, as adjusted combined statements of operations and balance sheet, the following disclosure:
“The pro forma combined balance sheet does not reflect contingent obligations relating to tax assessments from the Mexican government. Please read ‘Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—

 

 

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Income Taxes’ for more information about these tax assessments, including the amounts assessed to date and anticipated potential assessments.”
Financial Statements
Note 2 — Significant Accounting Policies
Property and Equipment, page F-18
2.   We have considered your response to prior comment 3(a) in our letter dated June 26, 2009. Please provide the following additional information with respect to your conclusion that your entire mat-supported jackup fleet is a single asset group under paragraph 10 of SFAS 144.
  a.   Clarify the lowest level of identifiable cash flows. In this regard, tell us whether you are able to identify specific revenues and costs associated with each individual rig or whether you allocate revenues and costs among individual rigs for any purpose, such as for performance evaluation and budgeting. Explain whether you track other operating information on a per-rig basis, such as utilization, day rates and days operated.
 
      Response: While some of our operating and overhead costs are allocated across our entire fleet (such as engineering support, purchasing, human resources, safety, training, risk, legal and accounting costs), the majority of our revenues and direct operating costs are identifiable on a rig-by-rig basis. We also track operating information (including utilization, day rates and operating days) on a rig-by-rig basis. Although the lowest level of identifiable cash flows is generally at this rig level, our conclusion that our entire mat-supported jackup fleet should be treated as a single asset group under paragraph 10 of SFAS 144 is based primarily on the fact that these rig cash flows are not “largely independent” (discussed further in response to the Staff’s other comments below).
 
  b.   With regard to your conclusion that the cash flows of individual rigs are not “largely independent” from the cash flows of other rigs, you have told us that (1) the rigs could be substituted; (2) labor costs can be redirected among the rigs; and (3) costs can be shared for equipment and spare parts. Please tell us how these factors create a dependency of the rigs on one another. That is, describe the extent to which equipment and costs are shared and when and how interchangeability of rigs occurs.
 
      Response: The interchanging of rigs, and the sharing of personnel and costs for equipment and spare parts, is common in our operations. This interchangeability and sharing across our fleet creates a dependency of the rigs on one another. In the vast majority of drilling activity in the Gulf of Mexico, the specifications of a

 

 

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      jackup rig, including water depth rating, do not materially affect its suitability for drilling a particular prospect, making rigs substantially interchangeable. According to RigPoint permitting data, from January 2007 to July 15, 2009, 86% of all wells permitted to be drilled by jackup rigs in the U.S. Gulf of Mexico were located in water depths of 200 feet or less. Only 9% of wells drilled in the Gulf of Mexico during that period were in water depths of 200 to 250 feet, and only 3% were in water depths of 250 to 300 feet. For prospects in water depths of 200 feet or less, the customer usually will be indifferent as to whether the rig performing the drilling service has a water depth rating of 200 feet or 250 feet; the 250-foot rig does not have a meaningful performance advantage in these circumstances.
 
      Additionally, please note that 250-foot rigs are almost always working in water depths of less than 200 feet. In the RigPoint data referred to above, 371 wells were permitted for 250-foot jackups; only 21 of those wells, or less than 6%, were located in water depths over 200 feet. Over 94% of the time, 250-foot rigs in the U.S. Gulf of Mexico were drilling in water depths where 200-foot rigs would have been satisfactory substitutes for our customers.
 
      This rig interchangeability is borne out by bidding processes with customers. Our customers have drilling prospects throughout the Gulf of Mexico and from time to time will solicit bids for drilling contracts. Before we submit a written bid, we will contact the potential customer to discuss the bid and which of our rigs are available for the particular drilling prospect, based on location, performance history and other factors. While we generally try to identify a suitable rig close to the prospect, we can, and in the past have, moved rigs from the U.S. for work in Mexico, and vice-versa. The dayrate awarded for a contract is based mostly on jackup rig demand and supply in the Gulf of Mexico, rather than the specifications of the particular rig. While the bid will generally specify the rig to be used to perform the services, we may substitute a different rig if the previously-specified rig is no longer available on the start date for the engagement. In some cases the substitute rig has a different water depth rating or otherwise has slightly different specifications than the previously-specified rig. For example, in January 2009 we entered into a drilling contract for the Pride Arizona, a 250-foot rig. That rig ultimately was unavailable, however, and we substituted the Pride Mississippi, a 200-foot rig, instead.
 
      In our industry, maintaining a fleet of rigs, in contrast to operating a single rig, is an important part of our business, as customers look for a drilling contractor to have an extensive labor pool, a high level of proven technical expertise and operating credentials, and the ability to minimize downtime in providing services. The maintenance of a rig fleet is critically important to operating in the shallow water drilling market and creates significant interdependencies of the revenues of the rigs. For example, in order to maintain our critical mass, historically we have tended to stack rigs during periods of weak demand rather than selling them. By doing so we have preserved flexibility to reactivate the rigs when demand strengthens, and we optimize day rates and utilization of the other rigs in our fleet.
 
      Given our portfolio of rigs, we do not believe that the water depth ratings of our rigs have ever made a difference in our ability to accept drilling projects. We are not aware of an instance when we have had to turn down work on a project in water depths greater than 200 feet because all of our 250-foot rigs were already working on projects in more than 200 feet of water; that is to say, there have been no circumstances in which we would have been able to take on more work if more of our rigs were rated for 250 feet or more, rather that 200 feet.

 

 

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      Also reflecting the interchangeability of these particular rigs, dayrates for jackups operating in the Gulf of Mexico are, as one would expect for a homogeneous commodity, almost solely a function of supply and demand. An increase in demand or decrease in supply has historically resulted in higher utilization and dayrates (and thus higher revenues) for all jackups operating in the region, including the 200-foot rigs in our fleet; customers do not view 200-foot rigs as so distinct that utilization and pricing remain unaffected by demand for rigs with different specifications.
 
      From an operational standpoint, there is also a high degree of interchangeability of equipment and spare parts for the rigs in our fleet—the vast majority of both can be, and are, used effectively on any rig in our fleet, including drill pipe, blowout preventers, top drives and flare booms. Similarly, rig crews are frequently moved from rig to rig, as our operational needs require. Sometimes during crew rotations (every two or four weeks), we will move or reassign crew members throughout the fleet from one rig to another, to maintain the required staffing and technical experience levels. Additionally, when we stacked a number of rigs earlier this year, we transferred almost 50 employees from the stacked rigs to active rigs. Our crew members’ skills are transferable—our rigs do not have materially different operating characteristics, and an effective crew member on a 200-foot rig, for example, would also be an effective crew member on a 250-foot rig.
 
      We also maintain a pool of employees that are not specifically assigned to a particular rig in order to further manage our workforce requirements. Many operational functions are provided on a fleetwide basis—we do not maintain rig-specific teams to provide marketing, engineering, training, procurement or safety services for our operations. These functions do not change in any material way depending on the rig specifications or operating characteristics, and thus are centralized in our organization from our fleetwide employee pool.
 
      If we were to decide to abandon or dispose of an individual rig, implement a plan to sell an individual rig, or determine that an individual rig has no remaining useful life, we would conclude that its cash flows are largely independent of the other rigs in our fleet. In that case, the rig would be extracted from the asset group and evaluated individually for impairment.
 
  c.   Compare and contrast your particular facts and circumstances to the example discussed in paragraph B45 of SFAS 144. In this regard, include a description of the obligations mandated in your contracts and which of your idled or stacked rigs would be suitable for and potentially utilized for those contracts.
 
      Response: The example in paragraph B45 of SFAS 144 describes a bus company that runs a fleet of buses providing services on five different routes, one of which

 

 

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      is operating at a deficit. The assets devoted to serving each route are discrete and not interchangeable. The contract with the customer, however, does not allow the bus company to cease providing service on any one route, and for this reason the entire fleet providing service on all five routes would be the appropriate asset group.
 
      The bus company example illustrates a scenario in which a company might conclude that its asset grouping should be aggregated in spite of the fact that its asset classes are discrete, a factor arguing for an asset grouping at a route-by-route level. In contrast to the example, however, our assets are not discrete—our rigs are interchangeable for most drilling projects. This is illustrated in the data cited above with respect to the water depths of wells drilled in the U.S. Gulf of Mexico. Many of our idled or stacked rigs would be considered by customers to be satisfactory substitutes for the rigs currently working under contract, as evidenced by market dynamics in the Gulf of Mexico which treat jackups as a homogeneous commodity. We acknowledge that our contracts with customers differ from the example in paragraph B45—our contracts are entered into on a rig-by-rig basis, rather than across all rigs in our fleet. However, paragraph B45 is illustrating a basis for aggregated asset grouping when asset classes are discrete. Our asset classes, on the other hand, are not discrete and our rig cash flows are not largely independent as a result of this fact; therefore we, unlike the bus company, do not rely on the interdependence of our customer contracts to support our asset grouping. For this reason we do not believe that the example in paragraph B45 is relevant to our rig fleet.
 
  d.   Tell us why you believe it is appropriate to group all rigs regardless of their capabilities. Include in your explanation how the water depth ratings, drilling depth ratings and other characteristics of your rigs affect interchangeability. Also explain whether each rig is interchangeable for another based upon where they are currently located and the cost to move them.
 
      Response: We did not disregard our rigs’ capabilities in determining the appropriate asset grouping; rather, we grouped our rigs because their capabilities are so similar. As discussed in our response to comment 2.b above, our rigs’ specifications are similar enough that the customer is usually indifferent as to which rig is used, as long as the rig is suitable to perform the services. Our 200-foot rigs are suitable for the vast majority of the wells drilled in the U.S. Gulf of Mexico (as noted, 86% of all wells permitted to be drilled during the period were located in water depths of 200 feet or less, and 250-foot rigs drilled in water depths of 200 feet or less over 94% of the time). We view our drilling contracts as agreements to provide a service, for which we use the rig as a platform for providing the service. Our customers historically have been more concerned with the service they expect to receive, rather than the precise specifications of the rig used to perform the service.

 

 

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      We manage our rigs on an entire-fleet basis, not on a rig-by-rig basis, or on a water depth rating basis, or any other grouping. The spin-off itself is evidence of this fact—Pride’s entire mat jackup fleet, rather than some subset thereof, is being included in the Seahawk asset base. Our objective is to maximize the profitability of the entire fleet, rather than maximizing the profitability of a particular rig or subset of rigs. Our operating strategy, in fact, frequently entails cold stacking rigs in order to reduce available rig supply and maintain utilization and dayrates for the other rigs in our fleet. Stacking decisions are typically made without focusing on water depth rating or other technical specifications, but rather on contract end dates and near-term capital spending needs. Note that we have cold-stacked two 250-foot rigs, while there are four 200-foot rigs that are currently idle but not cold-stacked. Our experience has been that the benefits of stacking are not affected by the relatively minor differences in capabilities in the rigs we choose to stack.
 
      Other rig characteristics, such as age, deck space and crew accommodations, are relatively similar across our fleet and do not significantly affect interchangeability. Similarly, the drilling depth ratings of our rigs are consistent (with 95% of our fleet having a drilling depth rating of 20,000 or 25,000 feet), and they do not meaningfully impact a rig’s suitability for a particular project. Regarding the current locations of our rigs, we always try to use a rig close to the drilling site in order to minimize mobilization costs. In our experience, however, rigs in the Gulf of Mexico are relatively easy and inexpensive to move. Accordingly, we do not believe the current location of our rigs has a material effect on interchangeability.
 
  e.   Tell us how you considered PEMEX’s shifting focus towards deeper water exploration, which will increasingly require the use of rigs with greater water depth capability, as described by you on page F-30 of Exhibit 99.1 and elsewhere in your filing, when you determined that similar characteristics of your rigs permits you to group them.
 
      Response: As disclosed in the information statement, PEMEX has indicated an increased emphasis, for its current budget cycle, on exploration and prospects that require the use of rigs with water depth ratings of 250 feet or greater. We believe that this shift in emphasis is simply a result of their focus on new field development for the current budget period. Over time, we believe that PEMEX’s focus will emphasize different fields in different water depths, including less than 250 feet (its Cantarell field, for example), based largely on geologic success production profiles and current economic conditions. Even if the current trend persists indefinitely, PEMEX is only one of our customers, and we believe other opportunities will continue to be available for our 200-foot rigs in the U.S. Gulf of Mexico.
 
  f.   We note that you determined that your business will consist of two reportable segments based on geographic location, U.S. and Mexico. Please tell us what

 

 

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       operating segments you have identified and the basis for that determination under SFAS 131. Provide an analysis contrasting your conclusions regarding your SFAS 144 asset group versus your SFAS 131 operating and reportable segments.
 
      Response: SFAS 131 required that we make an assessment of reportable segments in our business. SFAS 131 defines an operating segment as a component of an enterprise:
  •   that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other components of the same enterprise),
 
  •   whose operating results are regularly reviewed by the enterprise’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance, and
 
  •   for which discrete financial information is available.
      We concluded that our operating segments will be the U.S. and Mexico due to a number of factors related to our business, including:
  •   our country-level reporting structure, in which country managers have direct profit and loss responsibilities for the operations in their region;
 
  •   differences in the operating environments in the U.S. and Mexico, including regulatory differences and the fact that U.S. customers tend to be smaller independent oil and gas companies, while our customer in Mexico is the national oil and gas company; and
 
  •   the availability of country-level financial and performance data used in our decision making.
      These facts reflect our current management structure and will apply to our reporting after the spin-off.
 
      The SFAS 144 analysis, on the other hand, addresses whether the assets and liabilities are grouped “at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities.” As described above, we believe that the lowest level for which identifiable cash flows are largely independent is our entire fleet.
 
      Importantly, SFAS 131 does not require that the operating segment analysis take cash flows into account, which distinguishes that analysis from SFAS 144. The two analyses involve different tests, and accordingly, we believe different results may be reached for each. We do not believe that the fact that our SFAS 131

 

 

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      analysis resulted in two operating segments indicates that the identifiable cash flows from those two operating segments are largely independent of one another.
 
      Additionally, please note that we grouped our rigs for impairment analysis based on our parent company’s analyses, due to the carryover basis of accounting for common control transactions similar to the spin-off. Our parent company has grouped, and we expect to continue to group, our rigs in a single asset class because that is the lowest level for which identifiable cash flows are largely independent.
          Finally, as we stated in our July 2, 2009 response to the Staff’s comments, we are currently performing a preliminary assessment of the fair value of our rig fleet as compared to its carrying value. To the extent that the carrying value exceeds fair value, we will recognize an impairment loss. We supplementally advise the Staff that this preliminary assessment is in process and we continue to expect to disclose, in the final amendment to the Registration Statement, a range for the impairment loss we anticipate recording, if any, as a result of the spin-off.
     The Company acknowledges that:
  •   the Company is responsible for the adequacy and accuracy of the disclosure in the Registration Statement;
 
  •   staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the Registration Statement; 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.