January 21, 2016
VIA EDGAR
Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-3561
Attn: Ethan Horowitz, Accounting Branch Chief
Office of Natural Resources
Re: Parker Drilling Company
Form 10-K for the Fiscal Year Ended December 31, 2014
Filed February 25, 2015
Form 10-Q for the Fiscal Quarter Ended September 30, 2015
Filed November 4, 2015
Form 8-K filed November 4, 2015
File No. 001-07573
Ladies and Gentlemen:
Set forth below are the responses of Parker Drilling Company, a Delaware corporation (“we”, the “Company” or “Parker Drilling”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated December 29, 2015 with respect to the Company’s Form 10-K for the fiscal year ended December 31, 2014 filed with the Commission on February 25, 2015 (the “Form 10-K”), Form 10-Q for the fiscal quarter ended September 30, 2015 filed with the Commission on November 4, 2015 (the “Form 10-Q”), and Form 8-K filed with the Commission on November 4, 2015 (the “Form 8-K”).
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.
Securities and Exchange Commission
January 21, 2016
Page 2
Form 10-K for Fiscal Year Ended December 31, 2014
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 23
| |
| 1. | Remarks attributed to members of management from your quarterly earnings conference call include reference to the backlog associated with your drilling service business. However, it does not appear that you have disclosed the dollar amount of backlog orders believed to be firm in your Form 10-K. Please revise your disclosure or tell us why disclosure is not required to comply with Item 101(C)(1)(viii) of Regulation S-K. |
Response: The Company acknowledges the Staff’s comment and, in future filings, intends to include the following disclosure in the Business section related to our backlog:
Backlog is our estimate of the dollar amount of revenues we expect to realize in the future as a result of executing awarded contracts. The Company's backlog of firm orders was approximately $xxx million at December 31, 2015 and $674.0 million at December 31, 2014 and is attributable to our Drilling Services business. We estimate that, as of December 31, 2015, XX% of our backlog will be recognized as revenues within one year.
The amount of actual revenues earned and the actual periods during which revenues are earned could be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations, new contracts and other factors. See the following risk factors in "Item 1A. Risk Factors":
| |
| • | "Rig upgrade, refurbishment and construction projects are subject to risks and uncertainties, including delays and costs overruns, which could have an adverse impact on our results of operations and cash flows”; |
| |
| • | "Certain of our contracts are subject to cancellation by our customers without penalty and with little or no notice”; and |
| |
| • | "Our backlog of contracted revenue may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows." |
Results of Operations, page 24
Year Ended December 31, 2014 Compared with Year Ended December 31, 2013, page 24
| |
| 2. | Please revise the analysis of your operating results to quantify the effect of each factor identified as the cause of a material change to the amounts presented as part of your financial statements. Refer to Item 303(a)(3) of Regulation S-K and section III.B. of SEC Release No. 33-8350. |
Response: The Company acknowledges the Staff’s comment. Although we believe the analysis of operating results included in our previously filed annual and quarterly reports quantifies the causes that are material to provide users of those reports with a comprehensive
Securities and Exchange Commission
January 21, 2016
Page 3
understanding of the Company’s operating results, in our future filings we will ensure that the discussion of our operating results quantifies the effect of each factor identified as the cause of a material change to the amounts presented as part of our financial statements.
Please see below for an example of the revised operating results discussion for 2014 compared to 2013 that we will provide in our upcoming filings with the Commission.
Results of Operations
Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling, and (2) International & Alaska Drilling. We eliminate inter-segment revenue and expenses.
We analyze financial results for each of our reportable segments. The reportable segments presented are consistent with our reportable segments discussed in Note X of our consolidated financial statements. We monitor our reporting segments based on several criteria, including operating gross margin and operating gross margin excluding depreciation and amortization. Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludes depreciation and amortization expense, where applicable. Operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin excluding depreciation and amortization amounts and percentages should not be used as a substitute for those amounts reported under U.S. GAAP, but should be viewed in addition to the Company’s reported results prepared in accordance with U.S. GAAP. Management believes this information may provide users of this financial information, additional meaningful comparisons between current results and results of prior periods.
Year ended December 31, 2014 Compared with Year ended December 31, 2013
Revenues increased $94.5 million, or 10.8 percent, to $968.7 million for the year ended December 31, 2014 as compared to $874.2 million for the year ended December 31, 2013. Operating gross margin decreased 8.5 percent to $154.2 million for the year ended December 31, 2014 as compared to $168.4 million for the year ended December 31, 2013.
Securities and Exchange Commission
January 21, 2016
Page 4
The following is an analysis of our operating results for the comparable periods by reportable segment:
|
| | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2014 | | 2013 |
| Dollars in Thousands | |
| Revenues: | | | | | | | |
| Drilling Services: | | | | | | | |
| U.S. (Lower 48) Drilling | $ | 158,405 |
| | 16 | % | | $ | 153,624 |
| | 18 | % |
International & Alaska Drilling (1) | 462,513 |
| | 48 | % | | 410,507 |
| | 47 | % |
| Total Drilling Services | 620,918 |
| | 64 | % | | 564,131 |
| | 65 | % |
| Rental Tools | 347,766 |
| | 36 | % | | 310,041 |
| | 35 | % |
| Total revenues | 968,684 |
| | 100 | % | | 874,172 |
| | 100 | % |
| Operating gross margin excluding depreciation and amortization: | |
| Drilling Services: | | | | | | | |
| U.S. (Lower 48) Drilling | 68,091 |
| | 43 | % | | 69,415 |
| | 45 | % |
International & Alaska Drilling (1) | 94,089 |
| | 20 | % | | 86,068 |
| | 21 | % |
| Total Drilling Services | 162,180 |
| | 26 | % | | 155,483 |
| | 28 | % |
| Rental Tools | 137,123 |
| | 39 | % | | 147,017 |
| | 47 | % |
| Total operating gross margin excluding depreciation and amortization | 299,303 |
| | 31 | % | | 302,500 |
| | 35 | % |
| Depreciation and amortization | (145,121 | ) | | | | (134,053 | ) | | |
| Total operating gross margin | 154,182 |
| | | | 168,447 |
| | |
| General and administrative expense | (35,016 | ) | | | | (68,025 | ) | | |
| Provision for reduction in carrying value of certain assets | — |
| | | | (2,544 | ) | | |
| Gain on disposition of assets, net | 1,054 |
| | | | 3,994 |
| | |
| Total operating income | $ | 120,220 |
| | | | $ | 101,872 |
| | |
| |
| (1) | Includes the close-out of a construction project and recognition of final percentage of completion revenue. The construction project was canceled in 2011 prior to final completion. |
Securities and Exchange Commission
January 21, 2016
Page 5
Operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:
|
| | | | | | | | | | | | | | | | |
| Dollars in Thousands | | U.S. (Lower 48) Drilling | | International & Alaska Drilling | | Rental Tools | | Total |
| Year Ended December 31, 2014 | | | | | | | | |
Operating gross margin(1) | | $ | 46,831 |
| | $ | 34,405 |
| | $ | 72,946 |
| | $ | 154,182 |
|
| Depreciation and amortization | | 21,260 |
| | 59,684 |
| | 64,177 |
| | 145,121 |
|
| Operating gross margin excluding depreciation and amortization | | $ | 68,091 |
| | $ | 94,089 |
| | $ | 137,123 |
| | $ | 299,303 |
|
| Year Ended December 31, 2013 | | | | | | | | |
Operating gross margin(1) | | $ | 54,203 |
| | $ | 23,080 |
| | $ | 91,164 |
| | $ | 168,447 |
|
| Depreciation and amortization | | 15,212 |
| | 62,988 |
| | 55,853 |
| | 134,053 |
|
| Operating gross margin excluding depreciation and amortization | | $ | 69,415 |
| | $ | 86,068 |
| | $ | 147,017 |
| | $ | 302,500 |
|
| |
| (1) | Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense. |
The following table presents our average utilization rates and rigs available for service for the year ended December 31, 2014 and 2013, respectively:
|
| | | | | |
| | December 31, |
| | 2014 | | 2013 |
| U.S. (Lower 48) Drilling | | | |
Rigs available for service (1) | 12.1 |
| | 11.0 |
|
Utilization rate of rigs available for service (2) | 72 | % | | 91 | % |
| International & Alaska Drilling | | | |
| Eastern Hemisphere | | | |
Rigs available for service (1) | 13.0 |
| | 14.0 |
|
Utilization rate of rigs available for service (2) | 77 | % | | 49 | % |
| Latin America Region | | | |
Rigs available for service (1) | 9.0 |
| | 9.5 |
|
Utilization rate of rigs available for service (2) | 60 | % | | 75 | % |
| Alaska | | | |
Rigs available for service (1) | 2.0 |
| | 1.9 |
|
Utilization rate of rigs available for service (2) | 100 | % | | 100 | % |
| Total International & Alaska Drilling | | | |
Rigs available for service (1) | 24.0 |
| | 25.4 |
|
Utilization rate of rigs available for service (2) | 72 | % | | 63 | % |
Securities and Exchange Commission
January 21, 2016
Page 6
| |
| (1) | The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable to other similarly titled measures of other companies. |
| |
| (2) | Rig utilization rates are based on a weighted average basis assuming total days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled measures of other companies. |
Drilling Services Business Line
U.S. (Lower 48) Drilling
U.S. (Lower 48) Drilling segment revenues increased $4.8 million, or 3.1 percent, to $158.4 million for the year ended December 31, 2014, as compared with revenues of $153.6 million for the year ended December 31, 2013. The increase in revenues was primarily due to an additional $18.7 million in higher average dayrates for the U.S. barge rig fleet, including benefits from the addition to our operating fleet of rigs 55B and 30B in the second and third quarters, respectively, of 2014. Additionally, we generated an increase of $4.1 million from the O&M contract supporting three platform operations located offshore California, which generated higher revenues from reimbursable costs ("reimbursable revenues") and was operating for the full year ended December 31, 2014, compared with just over ten months in 2013. The segment revenue increase was substantially offset by lower utilization in the offshore GOM, which declined from 91 percent for the year ended December 31, 2013 to 72 percent for the year ended December 31, 2014 as a result of lower oil prices late in 2014.
U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $1.3 million, or 1.9 percent, to $68.1 million for the year ended December 31, 2014, compared with $69.4 million for the year ended December 31, 2013. This decrease is primarily due to lower utilization of the U.S. barge rig fleet discussed above.
International & Alaska Drilling
International & Alaska Drilling segment revenues increased $52.0 million, or 12.7 percent, to $462.5 million for the year ended December 31, 2014, compared with $410.5 million for the year ended December 31, 2013. The increase in revenues was primarily due to the following:
Securities and Exchange Commission
January 21, 2016
Page 7
| |
| • | an increase in reimbursable revenues of $12.1 million which added to revenues but had a minimal impact on operating margins; |
| |
| • | an increase of $19.1 million, excluding reimbursable revenues, primarily resulting from increased utilization for Parker-owned rigs. Utilization for the segment increased from 63 percent to 72 percent for the years ended December 31, 2013 and 2014, respectively, and included the following activities: |
| |
| ◦ | successful deployment of two previously idle rigs to the Kurdistan Region of Iraq; |
| |
| ◦ | a full year of operations in 2014 for our two arctic-class drilling rigs in Alaska, compared with 2013, in which one rig was not operational until February 2013; and |
| |
| ◦ | increased activity for our Sakhalin Island drilling operations. |
| |
| ◦ | partially offsetting these increases was a decline in activity in our Latin America region. |
| |
| • | an increase of approximately $16.8 million of revenues generated from our project services activities, primarily due to a new FEED contract entered into during the fourth quarter of 2013 and increased activity under the vendor services phase of the Berkut platform project. Due to the low mark-up on vendor services, this activity had minimal impact on operating gross margin excluding depreciation and amortization; and |
| |
| • | an increase of $4.0 million, excluding reimbursable revenues, primarily resulting from increased activity for our Sakhalin Island O&M operations, partially offset by the completion of an O&M project in Papua New Guinea in May 2014. |
International & Alaska Drilling segment operating gross margin excluding depreciation and amortization increased $8.0 million, or 9.3 percent, to $94.1 million for the year ended December 31, 2014, compared with $86.1 million for the year ended December 31, 2013. The increase in operating gross margin excluding depreciation and amortization was primarily due to both arctic-class rigs being fully operational in our Alaska operations and increased activity and lower operating costs associated with our Sakhalin Island O&M operations, which combined contributed $17.1 million to the increase. This increase was partially offset by the impact of net mobilization costs associated with the deployment of two previously idle rigs to Kurdistan and a decline in activity in our Latin America region, both described above. Additionally, included in the 2013 operating gross margin excluding depreciation and amortization was $4.7 million related to the close-out of a construction project and recognition of final percentage of completion revenue. The construction project was an extended-reach drilling rig construction contract which our customer canceled in 2011 prior to final completion.
Securities and Exchange Commission
January 21, 2016
Page 8
Rental Tools Services Business Line
Rental Tools segment revenues increased $37.7 million, or 12.2 percent, to $347.8 million for the year ended December 31, 2014 compared to $310.0 million for the year ended December 31, 2013. The increase was due to a $26.7 million increase in our international revenues and an $11.0 million increase in our U.S. revenues. The increase in international revenues was primarily due to a full year of revenues from International Tubular Services (ITS), acquired in April of 2013, which contributed an increase of $23.4 million of revenues for the year ended December 31, 2014. The increase in U.S. rental tools revenues was due to increased activity in the offshore Gulf of Mexico (GOM) market and increased activity in the U.S. land drilling market.
Rental Tools segment operating gross margin excluding depreciation and amortization decreased $9.9 million, or 6.7 percent, to $137.1 million for the year ended December 31, 2014 compared with $147.0 million for the year ended December 31, 2013. The decrease was primarily due to an $11.0 million reduction in gross margin excluding depreciation and amortization for our international operations, resulting from lower utilization, increased costs related to relocation of facilities and an increase in the allowance for doubtful accounts. This decline was slightly offset by a $1.1 million increase in gross margin excluding depreciation and amortization for our U.S. operations due to the increase in activity in the offshore GOM and U.S. land drilling markets, despite an increase in competitive conditions that led to lower product pricing for rental tools and related activities in the latter part of 2014.
Other Financial Data
General and administrative expense
General and administrative expense decreased $33.0 million to $35.0 million for the year ended December 31, 2014, compared with $68.0 million for the year ended December 31, 2013. The decrease was due primarily to approximately $22.5 million of costs incurred during 2013 related to the ITS Acquisition that did not recur in 2014. During 2013 we also incurred severance costs related to the departure of our former chief financial officer and our executive chairman, along with higher legal costs for matters related to our deferred prosecution agreement and settlements with the DOJ and SEC, neither of which recurred during 2014. General and administrative expense during 2014 also benefited from a $2.75 million reimbursement from escrow related to the ITS Acquisition to reimburse the Company for certain post-acquisition expenditures. See Note XX - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for further discussion.
Provision for reduction in carrying value of certain assets
During 2014, the provision for reduction in carrying value of certain assets was zero. During 2013, the provision for reduction in carrying value of certain assets was $2.5 million which was comprised of non-cash charges recognized for three rigs reclassified from assets held for sale to assets held and used for which carrying values exceeded fair
Securities and Exchange Commission
January 21, 2016
Page 9
values. Management concluded, based on the facts and circumstances at the time, it was no longer probable that the sales of the rigs sale would be consummated.
Gain on disposition of assets
Net gains recorded on asset dispositions for the years ended December 31, 2014 and 2013 were $1.1 million and $4.0 million, respectively. The net gains for 2014 were primarily the result of long-lived asset sales, including the sale of two rigs located in Kazakhstan during the fourth quarter. The net gains for 2013 were primarily the result of long-lived asset sales, including the sale of two rigs located in New Zealand, a building located in Tulsa, Oklahoma and a barge rig located in Mexico. Additionally, during the normal course of business we periodically sell equipment deemed to be excess or not currently required for operations.
Interest income and expense
Interest expense decreased $3.6 million to $44.3 million for the year ended December 31, 2014 compared with $47.8 million for the year ended December 31, 2013. This decrease was primarily related to a decrease in debt-related interest expense of $6.2 million resulting from lower interest rates on our outstanding debt balance and a lower total debt balance, offset by an increase in amortization of debt issuance costs of $1.4 million and a decrease in capitalized interest of $1.2 million. Interest income decreased $2.3 million to $0.2 million during the 2014, compared with interest income of $2.5 million during 2013 primarily related to interest earned on an IRS refund received during 2013.
Loss on extinguishment of debt
Loss on extinguishment of debt was $30.2 million and $5.2 million for the years ended December 31, 2014 and December 31, 2013, respectively. The loss on extinguishment of debt for 2014 related to the purchase and redemption of the 9.125% Notes during the first six months of 2014. The loss on extinguishment of debt for 2013 is related to the write-off of debt issuance costs resulting from the repayment of a $125 million term loan, fully funded by Goldman Sachs Bank USA as Sole Lead Arranger and Administrative Agent (Goldman Term Loan) in July 2013.
Other income and expense
Other income and expense was $2.5 million of income and $1.5 million of income for the years ended December 31, 2014 and December 31, 2013, respectively. Other income in 2014 was primarily related to earnings from our investment in an unconsolidated subsidiary that was acquired as part of the ITS Acquisition as well as settlements of claims against a vendor. This income was partially offset by losses related to foreign currency fluctuations from our Sakhalin Island operations. Other income in 2013 was primarily related to the recognition of non-refundable deposits from a buyer in connection with the sale of three rigs for which the sales agreement was terminated in the fourth quarter of 2013.
With regard to our income tax expense, we direct the Staff to our response to Question 3. below.
Securities and Exchange Commission
January 21, 2016
Page 10
Income Tax Expense, page 28
| |
| 3. | Please provide expanded disclosure regarding the amount of income tax expense recognized during the period. For example, the explanation currently provided makes reference to the effect of tax rates in foreign jurisdictions and the relative amounts of income earned in those jurisdictions, but does not appear to provide sufficient disclosure that would enable an investor to adequately understand the impact of foreign taxes. Refer to Item 303(a)(3) of Regulation S-K. |
Response: The Company acknowledges the Staff’s comment. Although we believe the analysis of income tax expense included in our previously filed annual and quarterly reports quantifies the causes that are material to provide users of those reports with a comprehensive understanding of the Company’s income tax expense recognized in the period, in our future filings we will ensure that the discussion of our income tax expense quantifies the effect of domestic and foreign tax expense on domestic and foreign pre-tax income.
Please see below for an example of the revised income tax expense discussion for 2014 compared to 2013 that we will provide in our upcoming filings with the Commission.
Income tax expense
Income tax expense was $24.1 million for the year ended December 31, 2014, compared with $25.6 million for the year ended December 31, 2013. The decrease was driven primarily by the decrease in global pre-tax income and the mix of operations between domestic and foreign jurisdictions. For the years ended December 31, 2014 and December 31, 2013, we reported domestic tax expense of $6.6 million and $11.9 million on domestic pre-tax income of $37.5 million and $32.1 million. For the years ended December 31, 2014 and December 31, 2013, we reported foreign tax expense of $17.5 million and $13.4 million on foreign pre-tax income of $11.0 million and $20.7 million.
Our effective tax rate was 49.6 percent for the year ended December 31, 2014, compared with 48.5 percent for the year ended December 31, 2013. Our annual effective tax rate is primarily affected by recurring items, such as the relative amounts of income or loss we earn in tax paying and non-tax paying jurisdictions, the statutory tax rates applied in the jurisdictions where the income or losses are earned, and our ability to receive tax benefits for losses incurred. It is also affected by discrete items, such as return-to-accrual adjustments and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from year to year. See Note X – Income Taxes, included in our Form 10-K for the fiscal year ended December 31, 2015 for further discussion.
Liquidity, page 36
| |
| 4. | Disclosure in your filing states that unremitted earnings of your foreign subsidiaries are deemed to be permanently reinvested. Please revise your statement regarding the amount of cash and cash equivalents on hand to quantify the dollar amount held outside of the U.S. at period end. |
Securities and Exchange Commission
January 21, 2016
Page 11
Response: The Company acknowledges the Staff’s comment. Please see below for an example of the revised disclosure we intend to include in the Liquidity section of our upcoming filings with the Commission:
As of December 31, 2014, we had approximately $177.5 million of liquidity, which consisted of $108.5 million of cash and cash equivalents on hand and $69.0 million of availability under the 2012 Revolver. As of December 31, 2014, approximately $54.4 million of the $108.5 million of cash and equivalents was held by our foreign subsidiaries.
The earnings of foreign subsidiaries as of December 31, 2014 were reinvested to fund our international operations. If in the future we decide to repatriate earnings to the United States, the Company may be required to pay taxes on these amounts based on applicable United States tax law which would reduce the liquidity of the Company at that time.
Notes to the Consolidated Financial Statements
Note 12 – Reportable Segments, page 65
| |
| 5. | Please revise to disclose revenues from external customers for each product and service or each group of similar products and services. As part of your response, describe the similarities and differences between products and services presented as a group. Refer to FASB ASC 280-10-50-40. |
Response: Parker Drilling segregates its business activities into three reportable segments, which are Rental Tools, U.S. (Lower 48) Drilling and International & Alaska Drilling. The Company evaluated its products and services for the required revenue disclosures and disclosed revenue under the three reportable segments based on the similarity of the use and markets for the groups of products and services within each segment. Parker Drilling considered the similarity of the products and services for each reportable segment as follows:
| |
| • | The Rental Tools segment provides rental tools and services for land and offshore oil and natural gas drilling, workover and production applications in both the U.S. and international markets. Tools we provide include standard and heavy-weight drill pipe, pressure control equipment including blow-out preventers (BOPs), drill collars and more. We also provide well construction services which include tubular running services and downhole tools and well intervention services which include whipstock, fishing products and related services, as well as inspection and machine shop support. The segment’s tools and services are used by our customers during the development of oil and gas wells. Our customers include exploration and production (E&P) companies, drilling contractors and service companies. Depending on the requirements of the well, the geography, availability of other service providers, and other factors, our customers may use one or many of our tools and services. Our sales force includes sales people who sell across all tools and services as well as sales people who primarily sell only one service or tool. |
Securities and Exchange Commission
January 21, 2016
Page 12
| |
| • | The U.S. (Lower 48) Drilling provides drilling services in the inland waters of the U.S. Gulf Mexico utilizing Company-owned barge rigs, and U.S. (Lower 48) based O&M work utilizing customer-owned equipment. All of the rigs in the barge fleet provide a similar service, drilling for oil and natural gas. Services and activities provided on customer-owned rigs are similar to those provided on Company-owned rigs. |
| |
| • | The International & Alaska Drilling segment provides drilling services in select international and harsh-environment regions utilizing Company-owned drilling rigs and customer-owned equipment. All of the segment’s drilling rigs provide a similar service, drilling for oil and gas, for its customers. Services and activities provided on customer-owned rigs are similar to those provided on Company-owned rigs. |
Parker Drilling discloses revenues by segment in its Segment Information note to its consolidated financial statements, based on the similarity of the use and markets for the products and services within each segment. Therefore, we believe the Company is in compliance with the disclosure requirements in FASB ASC 280-10-50-40.
| |
| 6. | Please tell us in more detail about the drivers behind the change to your reportable segments effective in the first quarter of 2015. In addition, with a view toward future disclosure, describe the factors used to identify your reportable segments, address your current internal organizational structure, and identify the types of products and services from which each reportable segment derives its revenues. Refer to FASB ASC 280-10-50-21 and 280-10-50-32. |
Response:
Drivers Behind the Change
The Company changed its reportable segments to align our external reportable segments with recent organizational changes and management changes that Parker’s President and Chief Executive Officer (CEO), who is the Company’s Chief Operating Decision Maker (CODM), has made. Over the last several years, the Company solidified the executive management team through the addition of a new CEO in October 2012 and the addition of the new Senior Vice President and Chief Financial Officer (CFO) in May of 2013. After joining the Company, the CEO spent several months observing the business prior to executing some key organizational changes, including:
| |
| • | The elimination of the senior vice president (SVP), Drilling Operations position - as a result of the elimination of this position, business unit vice presidents are directly accountable to and maintain regular contact with the CEO. In this structure, the CEO regularly reviews the financial results of each operating segment’s performance to make operational and resource allocation decisions |
| |
| • | The creation of a new business unit - a new Arctic business unit was created in March 2013 by combining our new, two-rig operation in Alaska and our operations on Sakhalin Island, Russia. Key reasons for creating the new business unit included increased management focus on the start-up of our two-rig |
Securities and Exchange Commission
January 21, 2016
Page 13
operation in Alaska, to leverage harsh environment operating experience from our Sakhalin Island, Russia operations, and to focus marketing and business development activities in the Arctic region. The new business unit is now firmly established in the organization and has built the required functional support (HR, finance, purchasing, business development, etc.) to be an independent business unit., and
| |
| • | Re-assessment of how the former Technical Services segment supports the Drilling business - the CEO re-assessed the Technical Services segment and considers it a support services function and therefore does not regularly review its business results. As a result, we have concluded that Technical Services does not qualify as an operating segment but rather a support service of the Drilling business. |
In addition to the reasons above, we note that we are in the process of a multi-year implementation of a new ERP system (Oracle) for financial reporting. The new system includes Hyperion HFM, which has enhanced our internal reporting capabilities. With the implementation of our new ERP and enhanced internal reporting capabilities, we have changed our internal management reporting to align with the new segments. Each month, the Company prepares a monthly CODM internal reporting package which includes a comprehensive analysis that summarizes the financial results at the consolidated level, reporting segment level, operating segment level, and rig level. Specifically, this report includes total revenues, total operating costs, depreciation, profit before income taxes, net income/loss, EBITDA.
Internal Organization Structure
The Company organizes itself by the nature of the services it provides which are (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling, and (2) International & Alaska Drilling. The segments are managed separately due to the different services provided, technology employed, and economic characteristics.
Products and Services
As noted in our response to Question 5 above, our U.S. (Lower 48) Drilling segment derives its revenues through operation of barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama, and Texas. This segment also includes our United States (U.S.) based operations and maintenance (O&M) services. Our International & Alaska Drilling segment derives its revenues through operations related to Parker-owned and customer-owned rigs (through O&M contracts) in the Eastern Hemisphere and Latin America regions as well as Alaska. Our Rental Tools segment derives its revenue from providing premium rental equipment and services to exploration and production companies, drilling contractors and service companies on land and offshore in the U.S. and selects international markets.
Identification of Reportable Segments
Securities and Exchange Commission
January 21, 2016
Page 14
We identified our reportable segments in accordance with ASC Topic 280, Segment Reporting. The method for determining what information to report is referred to as the management approach. We based our analysis of reportable segments on the way that management organizes the segments for allocating resources, making operating decisions, and assessing performance. Consequently, our segments are evident from the structure of our internal organization. Our analysis involved the following steps:
Step 1: Identify the chief operating decision maker (“CODM”)
Step 2: Identify the operating segments reported to the CODM
Step 3: Determine which operating segments are reportable segments
Step 1 - Identification of the CODM:
Pursuant to ASC 280-10-50-5, the term CODM identifies a function or a manager that works to allocate resources to and assess the performance of the segments of a public entity. The Company’s CODM is its CEO. The Company’s management structure includes the CEO, business unit vice presidents, as well as centralized legal, compliance and financial departments. The business unit vice presidents and the head of each of these departments are directly accountable to and maintain regular contact with the CODM. The CEO regularly reviews the financial results to assess each operating segment’s performance as well as to make operational and resource allocation decisions. The CEO implemented an internal quarterly meeting with the business units referred to as the Quarterly Business Review (“QBR”), in which he reviews the current and projected results of each operating segment.
Pursuant to ASC 280-10-50-7, generally, an operating segment has a segment manager who is directly accountable to and maintains regular contact with the CODM to discuss operating activities. While the business unit vice presidents and other senior executives of the Company do have decision making responsibilities and they are directly accountable for making decisions that impact the operating activities, financial results and forecasts for their respective business unit, they are unable to unilaterally make asset investment and deployment decisions that have an impact outside of their business units, due to their lack of visibility into global contract opportunities and global availability and movement of assets.
Step 2: Identification of the operating segments reported to the CODM
In accordance with ASC 280-10-50-1, an operating segment is a component of a company that has all of the following characteristics:
| |
| A. | It engages in business activities from which it may earn revenue and incur expenses (including intercompany transactions). |
| |
| B. | Its operating results are regularly reviewed by the public entity’s CODM. |
| |
| C. | Discrete financial information of the segment is available. |
To determine our operating segments, we applied the above requirements to each of our business units identified below:
| |
| 2. | International Rental Tools |
Securities and Exchange Commission
January 21, 2016
Page 15
| |
| 3. | U.S. Barge and Offshore Drilling |
| |
| 4. | Eastern Hemisphere Drilling |
| |
| 6. | Arctic Drilling (includes Alaska and Russia) |
A.Identification of business activities and earned revenue/incurred expenses:
We conclude that all of our business units identified above earn revenue and incur expenses through their business activities, with the exception of our Corporate business unit, as it does not earn revenue (other than immaterial, non-operating revenue associated with activities such as volume rebates and internal training initiatives).
| |
| B. | Operating Results Are Regularly Reviewed by the CODM: |
The operating results of the business units are regularly reviewed by the CODM, with the exception of our Technical Services business unit. Historically, Technical Services (third party services periodically performed to leverage technical expertise) was considered to be an operating segment due to the fact the CODM would regularly review the operating results of Technical Services. However, due to the changes instituted by the CODM, the operating results are no longer regularly evaluated by the CODM as the business unit does not participate in the QBR meetings discussed above. Additionally, The SVP and Chief Technical Officer (CTO) (formerly VP of Technical Services) is now not only responsible for any revenue generated by offering technical service support to third parties (a strategy still in place to serve as a development function for future drilling services) but he is also responsible for global operations support, supply chain management, quality and projects engineering (all of which are allocated to the appropriate business units for which they support). Although separate financial information is available for Technical Services and is included in the monthly reporting package, the business is treated as a support service for the Drilling Services business. The performance of Technical Services and resource allocation is assessed by the CTO and is largely driven by the needs for the Drilling Services business for support services.
In addition, within certain of the drilling business units identified, we have O&M contracts; however, disaggregated data is not provided to the CODM regularly, rather it is reported within each applicable business unit. This treatment is consistent with the guidance that states there is no requirement to disaggregate information for segment reporting purposes if it is not provided to the CODM in disaggregated form on a regular basis.
| |
| C. | Discrete Financial Information of the Segment is Available: |
Securities and Exchange Commission
January 21, 2016
Page 16
We conclude that discrete financial information is available for all our business units listed above.
Based on the above three criteria, we have concluded that, with the exception of our Technical Services and Corporate business units, our business units meet the criteria of an operating segment as described in ASC 280-10-50-1. Pursuant to ASC 280-10-50-4, not every part of a public entity is necessarily an operating segment or part of an operating segment. For example, a corporate headquarters or certain functional departments may not earn revenues or may earn revenues that are only incidental to the activities of the public entity and would not be operating segments. As such, we have concluded the Company’s Corporate and Technical Services business units are not considered operating segments, as the revenues are incidental to the activities of the public entity.
Step 3: Determine which operating segments are reportable segments
To determine which of our operating segments are reportable segments, we first applied the aggregation criteria stated in ASC 280-10-50-11 (a) – (e) to determine if one or more of our operating segments should be aggregated into a single operating segment. Two or more operating segments may be aggregated into a single operating segment for reporting purposes even though they may be individually material, if (1) aggregation is consistent with the objective and basic principles of ASC 280-10-50-11 (a)-(e), (2) the operating segments have similar economic characteristics and (3) the operating segments are similar in all of the following areas:
| |
| a. | The nature of the products and services |
| |
| b. | The nature of the production processes |
| |
| c. | The type or class of customer for their products and services |
| |
| d. | The methods used to distribute their products or provide their services |
| |
| e. | If applicable, the nature of the regulatory environment, for example, banking, insurance, or public utilities |
Based on our review of the criteria listed above and the evolution in executive management described above, the Company’s operating segments are aggregated into three operating segments: Rental Tools, U.S. (Lower 48) Drilling, and International and Alaska Drilling. Rental tools operating segment includes the U.S. Rental Tools and the International Rental Tools operating segments. The U.S. (Lower 48) Drilling operating segment includes the U.S. Barge and Offshore Drilling operating segment; the International and Alaska Drilling segment includes the Eastern Hemisphere Drilling, the Latin America Drilling and the Arctic Drilling operating segments. The CODM reviews the financial results to assess each operating segments performance as well as to make operational and resource allocation decisions at this level.
Securities and Exchange Commission
January 21, 2016
Page 17
We believe the aggregation of operating segment into reportable segments as described above, is consistent with the objective and basic principles of the ASC 280-10-50-11. Our analysis of the application of the aggregation criteria is set forth below:
Rental Tools
Economic Characteristics:
Over time, rental tool operating gross margins will vary between international and domestic regions as well as within regions internationally and domestically. Variations can be due to macro/global factors like global commodity prices and economic conditions as well as local market factors like the local supply vs. demand balance of tools, level of competition, typical contract duration, logistics costs and geopolitical issues.
Currently, the operating gross margins of our U.S and international rental tools operations are not consistent due to the recent acquisition of ITS, an international provider of rental tools and related services. We purchased ITS out of bankruptcy and its operating gross margins at that time were lower than the level we were earning in the U.S. due to poor management. However, a key reason for the acquisition was the expectation that we can significantly improve ITS’s margins over time with better management and commercial focus. International margin improvement has been slow due to acquisition integration costs and disruptions in two key international locations, but is now trending higher. Our current 5-year business plan projects U.S. and international rental operating gross margins will converge.
In addition to the margin gap narrowing over time, we observe the following similar economic characteristics:
| |
| • | margins react similarly to changes in market conditions; |
| |
| • | nature and scale of capital investments are similar; |
| |
| • | compensation and billing models are similar; |
| |
| • | key performance indicators (product line utilization, revenue yield, operating gross margin, ROCE) are similar; and |
| |
| • | in regards to currency risk, U.S. Rental Tools transactions are denominated solely in USD while International Rental Tools operations transacts primarily in USD (approximately 75%); therefore, currency risk is not a significant differentiator in the economics between U.S. and international rental tools. |
The nature of the products and services
The U.S. Rental Tools and International Rental Tools operating segments are engaged in the business of providing premium rental tools and services for oil and natural gas drilling. We concluded the majority of services are interchangeable between U.S. Rental Tools and International Rental Tools, as they have similar opportunities for growth and end uses. Products and services are broadly interchangeable
Securities and Exchange Commission
January 21, 2016
Page 18
geographically and have overlapping markets, as evidenced by current sub-rentals between the two operating segments.
The nature of the production processes
The production process is generally the same across the U.S. Rental Tools and International Rental Tools operating segments, as each has a central procurement effort, similar pricing, uses the same equipment and purchases the equipment from the same vendors. U.S. Rental Tools and International Rental Tools are able to share common or interchangeable facilities and employees, and use the same raw materials.
The type or class of customer for their products and services
Both the U.S. Rental Tools and International Rental Tools operating segments serve a similar size and class of companies and have a similar customer base, which include major and independent oil and natural gas E&P and service companies. Examples include Exxon Mobil, Reliance, Transocean, and Schlumberger, among others.
The methods used to distribute their products or provide their services
Both the U.S. Rental Tools and International Rental Tools products are used to drill the same types of wells. Both use similar methods to distribute their products or provide their services. Rental tools contracts are typically provided on a day rate basis with rates determined based on type of equipment and competitive conditions and are usually rented on a daily or monthly basis.
If applicable, the nature of the regulatory environment, for example, banking, insurance, or public utilities
While the U.S. Rental Tools and International Rental Tools operate in disparate economic and political environments which may impact cost to operate, the differences do not drive significant variance in the underlying economics for the respective regions such that it would significantly impact the decision making process on whether to redeploy the assets between the regions.
Conclusion for Rental Tools: Based on the above criteria being met by each U.S. Rental Tools and International Rental Tools, we aggregate these operating segments into one reportable segment consistent with the guidance in ASC 280-10-50-11. Although margins differ between U.S. Rental Tools and International Rental Tools at this time, the margin gap is expected to narrow significantly and the Company believes that each of these operating segments are sufficiently similar that disaggregation would not help the users of the Company’s financial statements better understand the Company’s performance or better assess prospects for future cash flows or make more informed judgments about the Company as a whole. In addition, the Segment footnote and the MD&A presentation includes all data at the revised reportable segment level. Results of Operations are described based on the material drivers within the domestic and international operations.
International and Alaska Drilling
Securities and Exchange Commission
January 21, 2016
Page 19
The International and Alaska Drilling Segment includes the Eastern Hemisphere, Latin America and Arctic Drilling operating segments.
Economic Characteristics:
Over the operating life of each drilling rig, the dayrates and operating margin percentages earned can vary from year to year and across different geographic regions and within a geographic region. The variations in rig dayrates and operating margin percentages can be due to macro market conditions such as global commodity prices, supply of rigs and economic conditions as well as local market factors such as level of competition, local rig supply vs. demand balance, quality and availability of local infrastructure support (e.g., roads, services, crews), remoteness and/or harshness of operation, geologic complexity, geopolitical risk and the typical timing and length of contracts. Operating margin percentages can also differ in periods of utilization versus non-utilization and can differ due to where the rigs are in their life cycle.
Across the Eastern Hemisphere, Latin America and Arctic operating segments, we have operations that span multiple countries and experience highly diverse operating conditions. We also have a mix of drilling contracts that can span from shorter term, well-to-well contracts (e.g., 6+ months) to long-term contracts that last up to five years. We also have rigs that are in different operating modes (e.g., startup vs. operating vs. standby vs. stacked) at different points in time. Given these diverse conditions, the drilling rigs in these operating segments earn a wide range of rig dayrates and operating gross margins. However, while rig dayrates and operating gross margins vary widely, the median dayrate for these rigs when working typically ranges from $30,000 to $40,000 per day and the median operating gross margin percentage for these rigs when working typically ranges from 20% to 30%.
Other factors that demonstrate similar economic characteristics across our global drilling operations are:
| |
| • | Sustaining capital requirements of our all drilling rigs is generally consistent. On average we typically spend between $0.65 million and $1.0 million in sustaining capital per active rig per year. |
| |
| • | Risk is assessed through an evaluation of the risk factors related to a rig’s specific location, drilling contract terms, and counterparty credit risk. |
| |
| • | Compensation and billing models are similar. |
| |
| • | Key performance indicators (utilization, downtime, total recordable injury rate (TRIR), operating gross margin, return on capital employed (ROCE)) are similar. |
| |
| • | In regards to currency risk, International Drilling operations are predominantly denominated in USD (with many being paid into U.S. bank accounts even though the operation may be based in a foreign location). Therefore, currency risk is not a significant differentiator in the economics between the respective operating segments within the International and Alaska reportable segment |
Securities and Exchange Commission
January 21, 2016
Page 20
The nature of the products and services
All of the Company’s rigs provide drilling services and share the following characteristics:
| |
| • | Each operating segment provides services operating its own rigs and/or operating customer’s rigs, |
| |
| • | Each operating segment has a similar degree of risk, opportunities for growth and end uses. Each of our rigs can be impacted by various risks, such as the demand for oil and natural gas, development and production technology, weather conditions, delays and cost overruns, price competition, among others depending on their specific location, |
| |
| • | Both the U.S. and International operating segments encounter regulatory requirements. Our international operations are subject to laws and regulations of a number of foreign countries with political, regulatory, judicial systems and regimes that may lead to greater geopolitical cost. This may differ from those in the U.S.; however, the U.S. operating segments would face similar geopolitical cost and risk if they were operating in various countries. |
| |
| • | Opportunities for growth and end uses include advances in exploration, organic growth through the marketing and selling of our fleet and through operating and maintenance contracts, as well as growth from acquiring rigs, |
| |
| • | Contract terms are based on day rates with rates highly dependent on supply and demand, |
| |
| • | The drilling rigs are mobile assets; the majority of the rigs can be moved from one location to another. As a result, we evaluate new contract opportunities for rigs both within an existing drilling operating segment and across drilling operating segments. We have a centralized Business Development function that seeks and evaluates global contract opportunities for our drilling fleet and assists with contract negotiation as required. If there are new contract opportunities for a rig or rigs in more than one operating segment, the CODM will make the final decision on which opportunity to commit to. The decision is typically based on the relative economic and commercial attractiveness of the opportunities taking into account factors like gross margin, moving cost, long-term market demand, etc. |
Because of the similarity in our rigs’ design and operation, we are able to support them with a centralized Asset Management, Engineering and Operations Support function. This global support function: (1) defines and implements rig maintenance standards, procedures and protocols; (2) provides engineering design and support for rig modifications and upgrades; (2) supports complex rig moves (e.g. between countries and/or regions) and provides troubleshooting assistance.
The nature of the production processes
Securities and Exchange Commission
January 21, 2016
Page 21
Each is contracted by the customer for the drilling of oil and gas wells. The crews used to operate each rig are interchangeable among rigs and the rigs are supported by the same technical services and maintenance personnel.
The type or class of customer for their products and services
Each serve a similar type of customer, which are energy companies focused on the exploration, development and production of oil and gas natural resources. Their customers typically include major, independent and national oil and natural gas companies as well as integrated service providers.
The customers of each operating segment use similar criteria when evaluating oil and gas investment opportunities (e.g., commodity price outlook, finding cost, lifting cost, market access, and geopolitical risk). They also use similar criteria when selecting a contract drilling company to provide drilling services (e.g., safety record, drilling rig capability / age, drilling efficiency / uptime, technical experience, and price).
The methods used to distribute their products or provide their services
Each operates under similar contractual terms that are based on either a specified period of time or the time required to drill a specified number of wells. Each has similar purchasing and marketing practices. As such, the methods used to distribute services are similar for each rig. Drilling contract terms range from a few months to 5 years.
If applicable, the nature of the regulatory environment, for example, banking, insurance, or public utilities
While each operate in disparate economic and political environments which may impact cost to operate, the differences do not drive significant variance in the underlying economics for the respective regions such that it significantly impact the decision making process on whether to redeploy the assets between the regions
Conclusion for International and Alaska Drilling: The drilling rigs are mobile assets; the majority of the rigs can be moved from one location to another. As a result, we evaluate new contract opportunities for rigs both within an existing drilling operating segment and across drilling operating segments. Based on the above criteria being met by each operating segment and the fungibility of each rig, aggregation of the Latin America, Eastern Hemisphere, and Arctic Drilling operating segments into one reportable segment is consistent with the guidance in ASC 280-10-50-11. The Company believes that each of these operating segments are sufficiently similar that disaggregation would not help the users of the Company’s financial statements better understand the Company’s performance or better assess prospects for future cash flows or make more informed judgments about the Company as a whole. In addition, the Segment footnote and the MD&A presentation includes all data at the revised reportable segment level. Results of Operations are described based on the material drivers within International and Alaska Drilling segment.
Securities and Exchange Commission
January 21, 2016
Page 22
Additionally, the Company considered the individual reporting of operating segments that meet the quantitative threshold noted in ASC 280-10-50-12. Pursuant to ASC 280-10-50-12 (a)-(c) a public entity shall report separately information about an operating segment or those aggregated together that meet any of the quantitative thresholds set forth below:
| |
| a. | the operating segment’s reported revenue, including both sales to external customers and intersegment sales or transfers, is 10 percent or more of the combined revenue, internal and external, of all operating segments; |
| |
| b. | The absolute amount of the operating segment’s reported profit or loss is 10 percent or more of the greater, in absolute amount, of either: |
| |
| i. | The combined reported profit of all operating segments that did not report a loss |
| |
| ii. | The combined reported loss of all operating segments that did report a loss; |
| |
| c. | The operating segment’s assets are 10 percent or more of the combined assets of all operating segments. |
We evaluated the quantitative thresholds using financial information as of and for the year ended December 31, 2013. The quantitative threshold of 10% or greater has been met for revenue and profit/loss.
The asset threshold test was not performed to determine if quantitative materiality thresholds have been met, as the CODM does not receive asset information by operating segment.
The Company also considered the guidance noted in ASC 280-10-50-14 and concludes that the 75% of total consolidated revenue threshold has been met, as the total revenue reported between the Rental Tools, U.S. (Lower 48) Drilling International and Alaska Drilling operating segments equal 100% of total consolidated revenue.
As a result of our analysis, the Company had identified Rental Tools Services, U.S. (Lower 48) Drilling, and International and Alaska Drilling as our reportable segments. The Company determined that such presentation most properly reflects its operations and internal decision making and is more informative to investors. This is how management views the Company’s business and the revised disclosure permits investors to view the Company from the same perspective.
Form 10-Q for Fiscal Quarter Ended September 30, 2015
Notes to the Unaudited Consolidated Condensed Financial Statements
Note 4 – Property, Plant and Equipment, page 11
Securities and Exchange Commission
January 21, 2016
Page 23
| |
| 7. | Disclosure in your filing states that you performed a recoverability test for your long-lived assets during the quarterly period ended September 30, 2015 and determined that the current carrying values of your asset groups are fully recoverable through future estimated cash flows. Please tell us more about the results of your recoverability test. For example, describe the assumptions related to future drilling contracts especially as it relates to rigs not currently under contract. In this connection, we note your statement that the utilization and pricing of your drilling rigs has been adversely impacted by a reduction in capital and operating expenditures by your customers and that the utilization rate of rigs available for service declined from 71% for the three months ended September 30, 2014 to 57% for the three months ended September 30, 2015. Refer to FASB ASC 360-10-35. |
Response: One of the key factors driving the expected recoverability of our asset groups is the generally low net book value of our assets when compared to the replacement cost of similar assets. On average our assets are expected to recover their net book values within the first half of their remaining life. Approximately 50% of our rigs have a net book value of five million or less and further this percentage increases to 70% for those assets with a net book value of ten million or less.
It is well known that the drilling service business is highly cyclical and we incorporated this fact in our recoverability analysis. Our assumptions contemplated a recovery in the cycle that would take place over the next several years but also contemplates external and internal evidence that indicates our business will be very challenging over this period. Our operating assumptions did not assume utilization or dayrates recovered to prior peaks that existed in 2014 and prior. Our recoverability analysis as of September 30, 2015, included underlying assumptions and estimates with respect to the following:
| |
| • | utilization rate (expressed as the days per year actively working); and |
| |
| • | the per day operating cost for each rig if active or stacked |
For those rigs which are currently stacked (or not currently under contract) we assumed they would remain stacked until at least the later part of 2016 with the majority not going back to work until 2017 and we assumed a dayrate comparable or lower to respective 2015 dayrates, which reflect the weak market, for similar rigs. Further, we performed a sensitivity analysis on our September 30, 2015 future projections, which allows for a significant reduction in dayrate or utilization, or both dayrate and utilization, for our asset groups and still remain recoverable.
Securities and Exchange Commission
January 21, 2016
Page 24
Note 9 – Income Tax Benefit/Expense, page 14
| |
| 8. | We note that you recognized a valuation allowance of $36.6 million during the period ended September 30, 2015 primarily on U.S. foreign tax credits and certain foreign net operating losses. Disclosure in your filing states that this valuation allowance was established based on the weight of available evidence including results of recent and current operations and your estimates of future taxable income or loss by jurisdiction in which you operate. Please provide us with additional information regarding the analysis that led you to conclude that a valuation allowance was needed for these particular types of deferred tax assets. As part of your response, describe your assessment of the realizability of deferred tax assets related to your U.S. federal income taxes. Refer to FASB ASC 740-10-30. |
Response: We acknowledge the Staff’s comment. Pursuant to the guidance promulgated under FASB ASC 740-10-30, we measure current and deferred tax liabilities and assets based on current enacted tax law. Measurement of deferred tax assets is reduced by amounts of tax benefits not expected to be realized. We perform the measurement of current and deferred income taxes at the date of the financial statements, and all available evidence, both positive and negative, is considered to determine whether a valuation allowance is required.
For purposes of the U.S. foreign tax credits and the associated valuation allowance recorded during the 2015 third quarter, our analysis of available evidence included the following:
| |
| • | Management’s strategic forecast of operations |
| |
| ◦ | Impact of strategic forecast on expectations of future taxable income |
| |
| ◦ | Impact of future reversals of taxable temporary differences on future taxable income |
| |
| • | US foreign tax credit characteristics |
| |
| o | Expiration period of ten years |
| |
| o | Requirement to use current year credits before prior period credits which expire more rapidly |
| |
| • | Current and recent historical results and financial position, including history of foreign tax credit utilization |
| |
| • | Available prudent and feasible tax planning strategies |
As set forth in the disclosure, in the process of determining the need for a valuation allowance we noted that the measurement of the U.S. foreign tax credit deferred tax asset was most significantly impacted for the period ended September 30, 2015 by expectations of future taxable income based upon management’s strategic forecast of operations. It is well known that the drilling service business is highly cyclical and we incorporated this fact in our analysis. Our assumptions contemplated a recovery in the cycle that would take place over the next several years but also contemplates external and internal evidence that indicates
Securities and Exchange Commission
January 21, 2016
Page 25
our business will be very challenging during the period required for utilization of expiring foreign tax credits. Reductions in the price of oil along with strong market sentiment behind the economic environment being weak for longer than had previously been estimated were external signals occurring during the third quarter ended September 30, 2015 incorporated in management’s strategic forecast of operations. The weight of this, along with other negative evidence (a lack of carryback potential for the credits, the requirement to use currently generated credits before expiring credits, and the relatively short expiration periods for the credits), was compared against the weight of positive evidence (our history of foreign tax credit utilization, available prudent and feasible tax planning strategies, and timing of future reversals of taxable temporary differences) and the result indicated to management that the deferred tax asset for U.S. foreign tax credits is not more likely than not to be realized.
An analysis not unlike the analysis described above for U.S. foreign tax credits is performed for other deferred tax assets related to our U.S. federal income taxes, though the implications of the evidence vary by deferred tax asset. For example, U.S. federal net operating losses carry an expiration of twenty years versus ten years for foreign tax credits, a different utilization methodology than foreign tax credits (net operating losses are utilized with the earliest expiring loss first), and utilization order than foreign tax credits (net operating losses must be utilized prior to the use of any foreign tax credits which are not refundable credits). Further, with respect to U.S. federal net operating losses, we considered management’s strategic forecast of operations, reversing deferred tax liabilities, and other relevant financial information consistent with our analysis of U.S. foreign tax credits. However, the cyclicality and recovery assumptions in management’s strategic forecast allow for utilization of U.S. net operating losses within the same period that U.S. foreign tax credits expire (a function of the utilization order of attributes required by U.S. tax law and the life of the assets), which is positive evidence supporting realizability. The weight of all of the above evidence, positive and negative, results in management’s conclusion that these U.S. deferred tax assets are more likely than not realizable (a conclusion that differs from the U.S. foreign tax credit analysis above).
The analysis of deferred taxes extends to each taxing jurisdiction, and it was noted in the disclosure that valuation allowances were recorded against certain foreign net operating losses. Again, as provided above, the analysis (focused on the weighted evidence existing at September 30, 2015) included current and recent results of operations, forecasts of future taxable income, expiration periods, and reasonable and prudent tax planning strategies. In certain foreign jurisdictions, the weight of available evidence at September 30, 2015 indicated the deferred tax assets were not more likely than not realizable.
Form 8-K filed November 4, 2015
| |
| 9. | The non-GAAP measure “adjusted EBITDA” presented as part of the press release announcing the results of your operations for the quarter ended September 30, 2015 includes adjustments described as “non-routine.” However, it appears that many of these adjustments recur in multiple periods for which this non-GAAP measure is presented. Please revise your disclosure as the identification of these adjustments as “non-routine” does not appear to be appropriate. |
Securities and Exchange Commission
January 21, 2016
Page 26
Response: In response to the staff’s comment, we have revised the presentation of our Adjusted EBITDA table. Our revised presentation more clearly identifies “EBITDA” separate from “Adjusted EBITDA”. Additionally, we have removed reference to “non-routine” adjustments. Set forth below is the form of the disclosure that the Company will include in future filings.
|
| | | | | | | | | | | | | | | | | | | | |
| PARKER DRILLING COMPANY |
| Adjusted EBITDA |
| (Dollars in Thousands) |
| (Unaudited) |
| | | | | | | | | | | |
| | | Three Months Ended |
| | | December 31, 2015 | | September 30, 2015 | | June 30, 2015 | | March 31, 2015 | | December 31, 2014 |
| | | | | | | | | | | |
| Net Income (Loss) Attributable to Controlling Interest | | $ | — |
| | $ | (48,620 | ) | | $ | (14,029 | ) | | $ | 3,222 |
| | $ | 7,753 |
|
| Interest Expense | | — |
| | 11,293 |
| | 11,396 |
| | 11,078 |
| | 10,779 |
|
| Income Tax (Benefit) Expense | | — |
| | 31,930 |
| | (6,916 | ) | | (182 | ) | | 9,983 |
|
| Depreciation and Amortization | | — |
| | 39,584 |
| | 38,351 |
| | 40,539 |
| | 38,455 |
|
| | | | | | | | | | | |
| EBITDA | | — |
| | 34,187 |
| | 28,802 |
| | 54,657 |
| | 66,970 |
|
| | | | | | | | | | | |
| Adjustments: | | | | | | | | | | |
| Other Income and Expense | | — |
| | 712 |
| | 1,510 |
| | 1,197 |
| | (1,187 | ) |
| Impairments and other charges | | — |
| | — |
| | — |
| | — |
| | — |
|
| (Gain) Loss on Disposition of Assets, Net | | — |
| | (383 | ) | | 138 |
| | (2,441 | ) | | (621 | ) |
| Provision for Reduction in Carrying Value of Certain Assets | | — |
| | 906 |
| | 2,316 |
| | — |
| | — |
|
Special items (2) | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | |
Adjusted EBITDA (1) | | — |
| | 35,422 |
| | 32,766 |
| | 53,413 |
| | 65,162 |
|
(1) Adjusted EBITDA, a non-GAAP financial measure, includes adjustments for items that management believes detract from an understanding of normal operating performance. Management also believes that results excluding these items are more comparable to estimates provided by securities analysts and used by them in evaluating the Company's performance.
(2) Special items include items impacting operating expenses that management believes detract from an understanding of normal operating performance.
Securities and Exchange Commission
January 21, 2016
Page 27
| |
| 10. | Disclosure of per share data on your website appears to include a number of per share measures. Please tell us how you considered the guidance pursuant to Items 100(a) and 100(b) of Regulation G with regard to the presentation of measures such as cash flow per share on your website. |
Response: In response to the staff’s comment, the Company has removed the “Investor Relations – SEC Filings & Financial Info – Key Ratios” and “Investor Relations – SEC Filings & Financial Info - Snapshot” pages from its corporate website. Additionally, we have removed the “Investor Relations – SEC Filings & Financial Info – Historical Financials/Ratios” until such time that we are able to ensure that the information provided complies with the guidance provided in Regulation G. The Company has carefully reviewed its website to ensure that all remaining non-GAAP measures comply with the guidance provided in Regulation G.
* * * * *
Securities and Exchange Commission
January 21, 2016
Page 28
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. |
If you have any questions with respect to the foregoing response or require further information, please contact the undersigned at (281) 406-2000 or Kelly B. Rose of Baker Botts L.L.P. at (713) 229-1796.
Very truly yours,
PARKER DRILLING COMPANY
By: /s/ Christopher T. Weber
Christopher T. Weber
Senior Vice President and Chief Financial Officer
cc: Wei Lu, Securities and Exchange Commission
Jon-Al Duplantier, Parker Drilling Company
Kelly B. Rose, Baker Botts L.L.P.
