Baker Hughes Incorporated | 2929 Allen Parkway, Suite 2100 | |
| Houston, Texas 77019-2118 | ||
| Tel 713-439-8600 | ||
| Fax 713-439-8966 |
VIA EDGAR
October 20, 2011
Ethan Horowitz
Branch Chief
Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, DC 20549-7010
Branch Chief
Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, DC 20549-7010
| Re: | Baker Hughes Incorporated Form 10-K/A for Fiscal Year Ended December 31, 2010 Filed March 4, 2011 File No.: 1-09397 |
Dear Mr. Horowitz:
We are responding to comments received from the staff (the “Staff”) of the Securities and Exchange Commission (the “SEC” or “Commission”) to Baker Hughes Incorporated (the “Company”, “we”, “us” or “our”) by letter dated September 20, 2011, which supplements the Company’s letters dated August 19, 2011 and July 19, 2011 to the Commission in response to the Commission’s letters dated August 5, 2011 and July 1, 2011, regarding the filings listed above. Our response repeats the captions and comments contained in the Staff’s letter in italics for your reference.
Form 10-K/A for Fiscal Year Ended December 31, 2010
Financial Statements, page 37
Consolidated Statements of Cash Flows, page 43
| 1. | We have reviewed your response to prior comment two and it appears that the average repair cost of your drill bits, per repair and in total over the lifetime of a drill bit, is significant relative to the range of initial costs of the drill bits. By analogy, FASB ASC 350-30-35-3f. states that “a material level of required maintenance in relation to the |
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| carrying amount of the asset may suggest a very limited useful life.” To help us better understand how your repair activities relate to your determination of useful lives, please describe for us in further detail the repair activities of your PDC drill bits, including the significance of the repaired and replaced components relative to the drill bits taken as a whole before use. In addition, please provide us with an analysis of these repair activities showing whether there are any indications that the initial cost of any of your PDC drill bits should be expensed after the first use because the repaired drill bit is in substance different from the drill bit before use. Please consider whether it is necessary to stratify your response based upon the different types of PDC drill bits. |
As noted in our prior response, at the request of and in order to meet certain customer requirements, we sometimes will rent, rather than sell, drill bits. The majority of the drill bit rental activity occurs in the U.S. market and relates to PDC or diamond bits. PDC rental bits come in numerous sizes, designs and configurations, depending on the intended use of the bit. The useful life of PDC bits is one year which is an average determined by taking into consideration the repair and maintenance program for PDC rental bits and the historical experience of the usage of PDC bits. Inherent in the determination of the useful life is consideration of the issue that at some point, the bit will become damaged beyond repair and, accordingly, will be scrapped. Due to the nature of the conditions under which drill bits are used and the damage they may incur, we believe a useful life of one year is appropriate.
PDC rental bits are normally repaired and reused unless a bit is damaged beyond repair or the cost to repair is not commercially economical. The repair process and cost can vary widely and is dependent primarily on the extent of damage to the bit, the type and size of the bit and the components used in the bit. Repair activities include inspection, replacement of cutters, shank repair, gage repair and matrix crown repair. The decision to repair a bit and the steps included in the repair process consist of the following:
| • | Inspection— When a used PDC bit has been returned, it is subjected to a thorough and comprehensive inspection. This includes visual inspection, magnetic particle inspection and nozzle inspection and is done to determine the extent and nature of any damage. This includes looking for chipped or cracked cutters, dull cutters, cracks, erosion, gage wear and shank condition. Other considerations include the conditions under which the bit has been used, for example, extreme heat. The inspection process also includes preparation of a detailed repair cost estimate. Based on this inspection, PDC bits that are damaged beyond repair or for which repair costs exceed expected future commercial value are scrapped and any remaining net book value is expensed at that time. Based on the results of the inspection, various components of the PDC bit may be repaired or replaced, including the following: |
| • | Cutter replacement— This is the most common type of repair. PDC cutters are cylindrical and brazed into a cutter pocket. During service the cutter can wear. If the cutter is only slightly worn, it can be “rotated” to expose a fresh cutting surface. If the cutter is damaged badly, it is replaced. During the inspection process, the inspector will denote what needs to be done to each cutter on the bit, leave, rotate or replace. Cutters on a bit are like tires on a car, you can rotate them every so often but with too much mileage or damage; they eventually need to be replaced. |
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| • | Shank repair— The shank is the steel portion of the bit that joins the crown matrix to the thread. Sometimes the thread connection or the thread shoulder is damaged or compromised. Depending on the severity of damage, the steel shank can either be reworked, or removed and replaced with a new shank; however, this is uncommon. | ||
| • | Gage repair —The gage is the portion of the bit that maintains the hole diameter. It is imperative that the diameter of the bit remains true and is within industry standards when the bit is run. If the gage is worn, we can “flame spray” the gage pad to build up more material, then the gage is ground down to be concentric and to specifications. | ||
| • | Matrix crown repair —This repair is to replace worn down carbide matrix on the crown face of the bit. Sometimes when cutters are lost downhole or are worn too much, the formation being drilled can abrade the bit body itself; particularly in the pockets that actually holds the cutter. The matrix can be flame sprayed to rebuild the pocket or surface. This is analogous to repairing cosmetic or structural damages to the body of an automobile. |
Subject to possible technological improvements in the parts that may be used to repair a bit, when bits are repaired, they are done to their original specifications and design. The repaired bit is the same as the original bit design and size.
As noted, the decision to repair a PDC bit is driven by the cost/benefit analysis of doing so. The cost to repair a PDC bit varies depending on the extent of the required repairs and the size of the bit; however, for 2011 the cost to repair PDC bits is not considered significant. The costs to repair bits are expensed when incurred. Additional information in the response to this comment has been provided supplementally under separate cover pursuant to a confidential treatment request under the Freedom of Information Act and applicable regulations of the SEC.
Note 1 — Summary of Significant Accounting Policies, page 44
Revenue Recognition, page 44
| 2. | We have reviewed your response to prior comment three. For each of your different types of rental tools, please provide us a further analysis of your facts and circumstances as it relates to FASB ASC 840-10-15-6a. For example, your rental drill bits, which we believe would be attached to the end of drill string and physically underground during the actual drilling, appear to be operated by the drilling contractor and its personnel who operate the drilling rig, under the authority of your customer. By evidence of actual operation of the rental drill bit by the drilling contractor, the rental drill bit arrangement appears to meet the condition “the purchaser has the ability or right to operate the [...] equipment or direct others to operate the [...] equipment in a manner it determines.” In addition, it appears that a number of the factors you raise in your response are addressed by FASB ASC 840-10-15-8, which states that “agreements that transfer the right to use property, plant, or equipment meet the definition of a lease for purposes of this Topic even though substantial services by the contractor (lessor) may be called for in connection with the operation or maintenance of such assets.” |
As noted in our prior responses, in the normal course of providing various services to its customers, we use a wide variety of equipment and tools, which we refer to as “rental tools” or “tools.” Substantially all of the tools used by the Company are manufactured and owned by the
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Company. The tools are easily moveable, are frequently moved from one location to another, are interchangeable and thus, are used to provide services to different customers as demand requires. Our contracts with customers cover all services and products expected to be required for a particular project, including the possible use of our tools. These contracts provide that when our tools are to be used on a project, the customer is charged a fee for the time the tools are actually used (or on standby) based on daily or hourly rates or a similar method as specified in the contract.
Our rental tool fleet includes several hundred different types and sizes of tools and equipment; however, they can be categorized into the main areas described below. Please note that while revenue from rental bits is not considered significant, we have included them as a category below to be responsive to the Staff’s specific question. Additional information in the response to this comment has been provided supplementally under separate cover pursuant to a confidential treatment request under the Freedom of Information Act and applicable regulations of the SEC.
| • | Conventional and rotary steering systems (Drilling motors) — These tools are used to provide steering control to reduce the uncertainty of drilling away from the target and are used for directional, horizontal, and straight-hole drilling. During the conduct of drilling operations, the tools and related activities are conducted by Company personnel. | ||
| • | Measurement-while-drilling (“MWD”) systems — These include downhole tools that take measurements that are transmitted from downhole to the surface. These measurements include directional surveys, natural gamma ray, drilling dynamics, temperature, and annular pressure. MWD platforms also act as a telemetry link and power source for other real-time downhole services. During the conduct of MWD operations, the tools and related activities are conducted by Company personnel. | ||
| • | Logging-while-drilling (“LWD”) systems — LWD systems provide formation evaluation data while drilling. LWD sensors provide petrophysical data and other data for use in directional drilling, formation evaluation, and geosteering applications. In addition, sensors can provide data on lithology, and near-bore environments, nuclear measurements and formation-density images, porosity measurement, formation pressure while drilling, reservoir fluids mobility and imaging services. During the conduct of LWD operations, the tools and related activities are conducted by Company personnel. | ||
| • | Fishing Equipment — This includes wellbore obstruction removal systems and tools such as fishing, milling, cutting tools, specialty tools, intervention tools and accessory tools used in cased hole, open-hole and through-tubing applications. This also includes conventional fishing tools and systems used for packer milling and retrieving, internal and external cutting, internal and external engagement, washover and other fishing applications. During the conduct of fishing operations, the tools and related activities are conducted by Company personnel. | ||
| • | Coiled Tubing Systems equipment — The type of equipment is used for well cleanouts, stimulation, and other specialized applications deployed through the use of a coiled tubing unit. During the conduct of operations using our coiled tubing equipment, the tools and related activities are conducted by Company personnel. | ||
| • | Drill bits — These include roller cone and PDC drill bits used for drilling, hole-enlargement, and coring. The use of drill bits is generally conducted as follows: |
| • | The bit is utilized in connection with a bottom hole assembly that includes a Company drilling motor, MWD tool or LWD tool (or some combination thereof) in |
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| which case all of the tools, including the bit, and related activities are operated by Company personnel. | |||
| • | The bit is used with a bottom hole assembly provided by another service provider or is used by direct attachment to the drill string, in which case, while not directly controlling the drilling operation, our personnel substantively control use by prescribing the conditions and specifications under which the bit should be used and by conducting general monitoring of drilling activities. |
Key characteristics underlying substantially all transactions related to our tools include the following:
| • | The tools are not leased to the customer and there is no lease or similar agreement. | ||
| • | The customer is charged a fee only while the equipment is being used (or on standby) and the charge stops when the tools are no longer being used. | ||
| • | The tools may be used for a customer for as little as a few hours or as long as a number of days. The time period varies, there is no fixed time commitment or term, and the ultimate time period for usage is not readily known. | ||
| • | When the tools are ready to be used in the well, one or more of our technicians are deployed to the well site to either directly operate or oversee the operation of the tools in the well. | ||
| • | The customer does not have the ability, or right, to operate or control the tools or to direct others to operate the tools as we retain that responsibility as part of our normal operating procedure. | ||
| • | The customer does not have the ability to hire, fire or replace us as the operator of the tools or to specify or change significant operating policies or procedures in their arrangement with us. | ||
| • | The customer does not have the ability or right to control physical access to the tools. | ||
| • | The customer is the sole beneficiary of benefits from the output produced from using the tools. | ||
| • | We retain possession, ownership and control over the use of the tools; our customers do not obtain the right to control the use of the tools nor do they obtain rights to purchase or otherwise retain the tools. |
Based upon the nature of the contracts and arrangements with our customers, the method by which rental tools are owned, operated, managed and controlled, the Company does not believe that control of the use of the tools is conveyed to the customer and thus the provisions of FASB ASC 840-10-15-6a or FASB ASC 840-10-15-8 are not applicable.
Note 4 — Segment Information, page 50
| 3. | We have reviewed your response to prior comment four. Based on the information provided in your response and included on your website, it is not clear how the items grouped as Drilling and Evaluation and Completion and Production are similar. Please provide us with additional detail analyzing the similarities and dissimilarities of your products and services to support your presentation. Alternatively, please provide us with |
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| sample disclosure showing revenue attributable to each of your product line groups in accordance with FASB ASC 280-10-50-40. |
We have considered the disclosure requirements prescribed by FASB ASC 280-10-50-40 and believe presentation of aggregated revenue for each of the two groups: the Drilling and Evaluation (“D&E”) group and the Completion and Production (“C&P”) group is appropriate because the products and services within each group are similar. We formed this conclusion based on the following analysis.
The construction of an oil or gas well includes two major phases. Those two phases are the drilling phase, including all related activities, followed by the completion phase. Our product line revenue disclosures align with these two phases of a well. Specifically, the D&E group includes drill bits, drilling systems, wireline systems and drilling fluids product lines, which are all used in the drilling phase of constructing a well. The C&P group includes completion systems, wellbore intervention, artificial lift systems, upstream chemicals and pressure pumping services product lines, which are all used in the completion phase of well construction.
With regards to aggregation of product lines within each group to determine whether groups of products or services are similar, we looked to the aggregation criteria in ASC 280-10-50-11; accordingly, we considered the following factors:
| (1) | Economic characteristics— We analyzed the historical and projected gross margins and, as necessary, considered other economic characteristics of each of the product lines within the D&E group and the C&P group to determine if they exhibited similar long-term financial performance. The results of this analysis supported the aggregation of each of the product lines within each of the two groups. | ||
| (2) | Nature and use of the products and services—The products and services within the D&E group are similar in purpose and end use as they are directly related to the drilling phase, and the products and services within the C&P group are similar in purpose and end use as they are directly related to the completion phase. In addition, the products and services within each group are often used at the same time and in conjunction with each other or in successive sequence of each other during that phase of the well. For example, the drilling phase of the well would include use of bits, motors, MWD or LWD tools and drilling fluids all at the same time. | ||
| (3) | Customers— Our customers include major multi-national, independent and national or state-owned oil companies and are generally common for both groups; however, our customers are operationally aligned with the two groups. For example, it is typical for our customers to have separate and dedicated engineering and procurement staffs related to drilling operations and completions activities. In addition, while we have certain common sales, marketing and promotional efforts across product lines, we also have sales personnel dedicated solely to each group. | ||
| (4) | Production processes and research activities— We have similarities in the nature of the production process as the product lines within each group generally use the same or similar raw materials and have similar degrees of labor intensiveness. All product lines within the D&E and C&P group procure their inventory, tools and equipment from the Company’s enterprise supply chain organization, which manufactures the inventory, tools and equipment through a limited number of manufacturing facilities; however, given the unique requirements and differences in products, there are generally dedicated manufacturing |
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| facilities that support each group. Further, a large portion of the D&E products and tools used as part of our services are produced in combined D&E manufacturing facilities and use the same labor force. In addition, our research and development organization and activities are structured to support the requirements of each of the two groups. | |||
| (5) | Economic trends —The products and services in each group have similar growth opportunities and are impacted by similar economic drivers, including customer spending, current and future expectations of oil and natural gas prices, hydrocarbon demand and other similar factors. For example, a change in customer exploration budgets and spending may have a timelier and more significant impact on the D&E group but have a much less or delayed impact on the C&P group. |
Based on consideration of the factors described above and in our letters dated August 19, 2011 and July 19, 2011, we believe that the products and services within the C&P group and the D&E group are similar and are appropriately combined for purposes of the disclosure requirements prescribed by ASC 280-10-50-40 and that additional disclosures are not required. Additionally, our disclosures are consistent with those of our major competitors who also present products and services revenue on an aggregated basis into two similar primary groups and are consistent with our disclosures prior to moving to segment disclosures based on our geographic organization. In connection with our response, we are also reviewing our website to ensure that our product line presentation is consistent with our disclosures and reflects current operations.
The Company respectfully believes it has appropriately responded to the Staff’s comments contained in the Staff’s letter dated September 20, 2011. Please do not hesitate to call William Marsh, Vice President Legal, at 713-439-8709 or me at 713-439-8611 with any questions or if we may provide the Staff with any additional information. We are pleased to visit with the Staff to clarify any questions. Thank you for your assistance.
| Sincerely yours, | ||||
| /s/ Alan J. Keifer | ||||
| Alan J. Keifer | ||||
| Vice President and Controller | ||||
| cc: | Michael Fay, Securities and Exchange Commission Sandra E. Alford, Corporate Secretary William D. Marsh, Vice President Legal Western Hemisphere and Deputy General Counsel |
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