UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2013
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________________________ to _________________________
Commission file number: 001-16337
OIL STATES INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
Delaware
76-0476605
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
Three Allen Center, 333 Clay Street, Suite 4620,
77002
Houston, Texas
(Zip Code)
(Address of principal executive offices)
(713) 652-0582
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES [ X ]
NO [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)
YES [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "accelerated filer," "large accelerated filer" and "smaller reporting company in Rule 12b-2 of the Exchange Act.
(Check one):
Large Accelerated Filer [X]
Accelerated Filer [ ]
Non-Accelerated Filer [ ] (Do not check if a smaller reporting company)
Smaller Reporting Company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES [ ]
NO [X ]
The Registrant had 55,153,548 shares of common stock, par value $0.01, outstanding and 3,979,910 shares of treasury stock as of October 30, 2013.
INDEX
Page No.
Part I -- FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Income for the Three and Nine Month Periods Ended September 30, 2013 and 2012
3
Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Month Periods Ended September 30, 2013 and 2012
4
Consolidated Balance Sheets – September 30, 2013 (unaudited) and December 31, 2012
5
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012
6
Notes to Unaudited Condensed Consolidated Financial Statements
7 – 26
Cautionary Statement Regarding Forward-Looking Statements
27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
27 – 41
Item 3. Quantitative and Qualitative Disclosures About Market Risk
41
Item 4. Controls and Procedures
41– 42
Part II -- OTHER INFORMATION
Item 1. Legal Proceedings
42
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
43
Item 6. Exhibits
(a) Index of Exhibits
43– 44
Signature Page
45
PART I -- FINANCIAL INFORMATION
ITEM 1. Financial Statements
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30,
2013
2012
Revenues
Costs and expenses:
Cost of sales and services
Selling, general and administrative expenses
Depreciation and amortization expense
Other operating expense
Operating income
Interest expense, net of capitalized interest
Interest income
Loss on extinguishment of debt
Equity in earnings (losses) of unconsolidated affiliates
Other income
Income from continuing operations before income taxes
Income tax provision
Net income from continuing operations
Net income from discontinued operations, net of tax (including a net gain on disposal of $84,209 in the third quarter of 2013)
Net income
Less: Net income attributable to noncontrolling interest
Net income attributable to Oil States International, Inc.
Continuing operations
Discontinued operations
Basic net income per share attributable to Oil States International, Inc. common stockholders from:
Diluted net income per share attributable to Oil States International, Inc. common stockholders from:
Weighted average number of common shares outstanding:
Basic
Diluted
The accompanying notes are an integral part of
these financial statements.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)
Other comprehensive income (loss):
Foreign currency translation adjustment
Unrealized loss on forward contracts, net of tax
Total other comprehensive income (loss)
Comprehensive income
Comprehensive income attributable to noncontrolling interest
Comprehensive income attributable to Oil States International, Inc.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
(UNAUDITED)
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories, net
Current assets held for sale
Prepaid expenses and other current assets
Total current assets
Property, plant, and equipment, net
Goodwill, net
Other intangible assets, net
Noncurrent assets held for sale
Other noncurrent assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
Accrued liabilities
Income taxes
Current portion of long-term debt and capitalized leases
Deferred revenue
Current liabilities held for sale
Other current liabilities
Total current liabilities
Long-term debt and capitalized leases
Deferred income taxes
Noncurrent liabilities held for sale
Other noncurrent liabilities
Total liabilities
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 59,118,683 shares and 58,488,299 shares issued, respectively, and 55,139,418 shares and 54,695,473 shares outstanding, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income (loss)
Common stock held in treasury at cost, 3,979,265 and 3,792,826 shares, respectively
Total Oil States International, Inc. stockholders’ equity
Noncontrolling interest
Total stockholders’ equity
Total liabilities and stockholders’ equity
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NINE MONTHS
ENDED SEPTEMBER 30,
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
Deferred income tax provision
Excess tax benefits from share-based payment arrangements
Gain on sale of business
Gains on disposals of assets
Non-cash compensation charge
Accretion of debt discount
Amortization of deferred financing costs
Other, net
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable
Inventories
Accounts payable and accrued liabilities
Taxes payable
Other current assets and liabilities, net
Net cash flows provided by operating activities
Cash flows from investing activities:
Capital expenditures, including capitalized interest
Acquisitions of businesses, net of cash acquired
Proceeds from sale of business
Proceeds from disposition of property, plant and equipment
Net cash flows provided by (used in) investing activities
Cash flows from financing activities:
Revolving credit borrowings and (repayments), net
Payment of principal on 2 3/8% Notes conversion
Term loan repayments
Debt and capital lease repayments
Issuance of common stock from share-based payment arrangements
Purchase of treasury stock
Payment of financing costs
Shares added to treasury stock as a result of net share settlements due to vesting of restricted stock
Net cash flows provided by (used in) financing activities
Effect of exchange rate changes on cash
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Non-cash financing activities:
Value of common stock issued in payment of 2 3/8% Notes conversion
The accompanying notes are an integral part of these
financial statements.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
The accompanying unaudited condensed consolidated financial statements of Oil States International, Inc. and its wholly-owned subsidiaries (referred to in this report as we or the Company) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the Commission) pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the full year.
In September 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu Tubulars America, Inc. (Marubeni-Itochu) for the sale of Sooner, Inc. and its subsidiaries (Sooner), which comprised the entirety of the Company’s tubular services segment. The applicable assets and liabilities of this business have been classified as held for sale in the Consolidated Balance Sheet as of December 31, 2012. The unaudited Condensed Consolidated Statements of Income for all periods presented have been reclassified to reflect the presentation of discontinued operations. Unless otherwise indicated, all disclosures and amounts in the Notes to Unaudited Condensed Consolidated Financial Statements relate to the Company’s continuing operations.
The preparation of condensed consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying condensed consolidated financial statements.
The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2012 (the 2012 Form 10-K).
2. RECENT ACCOUNTING PRONOUNCEMENTS
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
Additional information regarding selected balance sheet accounts at September 30, 2013 and December 31, 2012 is presented below (in thousands):
September 30,
December 31,
Accounts receivable, net:
Trade
Unbilled revenue
Other
Total accounts receivable
Allowance for doubtful accounts
(Continued)
Inventories, net:
Finished goods and purchased products
Work in process
Raw materials
Total inventories
Allowance for excess, damaged, or obsolete inventory
Estimated
Useful Life (years)
Property, plant and equipment, net:
Land
Accommodations assets
Buildings and leasehold improvements
Machinery and equipment
Completion services equipment
Office furniture and equipment
Vehicles
Construction in progress
Total property, plant and equipment
Accumulated depreciation
Accrued liabilities:
Accrued compensation
Insurance liabilities
Accrued taxes, other than income taxes
Accrued interest
Accrued commissions
4. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated other comprehensive income decreased from $107.1 million at December 31, 2012 to an accumulated other comprehensive loss of $18.4 million at September 30, 2013, a net change of $125.5 million, primarily as a result of decreases in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar was valued at an exchange rate of U.S. $0.97 at September 30, 2013 compared to U.S. $1.01 at December 31, 2012, a decrease of 4%. The Australian dollar was valued at an exchange rate of U.S. $0.93 at September 30, 2013 compared to U.S. $1.04 at December 31, 2012, a decrease of 11%. Excluding intercompany balances, our Canadian dollar and Australian dollar functional currency net assets total approximately C$926 million and A$941 million, respectively, at September 30, 2013.
5. EARNINGS PER SHARE
The calculation of earnings per share attributable to the Company is presented below (in thousands, except per share amounts):
Three Months Ended
Nine Months Ended
Numerator:
Net income attributable to Oil States International, Inc.:
Net income from discontinued operations
Denominator:
Denominator for basic earnings per share – weighted average shares outstanding during the period
Effect of dilutive securities:
Options on common stock
2 3/8% Contingent Convertible Senior Subordinated Notes
Restricted stock awards and other
Denominator for diluted earnings per share – adjusted weighted average shares and assumed conversions
Basic earnings per share:
Diluted earnings per share:
Our calculation of diluted earnings per share for the three and nine months ended September 30, 2013 excludes 247,432 shares and 344,251 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect. Our calculation of diluted earnings per share for the three and nine months ended September 30, 2012 excludes 303,833 shares and 424,299 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.
See Note 8 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for a discussion of the conversion of our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes).
6. BUSINESS ACQUISITIONS AND GOODWILL
On August 29, 2013, we acquired the 51% majority interest in a venture we had previously accounted for under the equity method. The acquired business provides design, manufacturing, sales and aftermarket services for newly manufactured cranes in India. Consideration paid for the majority interest was $1.45 million in cash. The operations of this business have been included in the offshore products segment since the acquisition date.
On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $49.5 million consisting of $32.5 million in cash plus contingent consideration with an estimated fair market value of $17.0 million at closing. During the second quarter of 2013, the estimated fair market value of the contingent liability was increased to $20.0 million due to favorable developments related to a patent application by Tempress, resulting in a $3.0 million, or $0.05 per diluted share after tax, charge to other operating expense. The patent was granted in the third quarter of 2013 and the $20.0 million in contingent consideration was paid to the former shareholders of Tempress. The Company’s current escrowed deposits of $5.3 million include other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our September 30, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for escrowed amounts expected to be paid to the seller also totaled $5.3 million and are classified as “Other current liabilities” in our September 30, 2013 Consolidated Balance Sheet and “Other noncurrent liabilities” in our December 31, 2012 Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.
On July 2, 2012, we acquired all of the operating assets of Piper Valve Systems, Ltd (Piper). Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects offshore (surface and subsea) and onshore. Piper's valve technology complements our offshore products segment, allowing us to integrate their valve products and services into our existing subsea products such as pipeline end manifolds and terminals, increasing our suite of global deepwater product and service offerings. Cash consideration paid for the acquisition totaled $48.0 million. The operations of Piper have been included in our offshore products segment since the acquisition date.
In December 2010, we also acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million including estimated contingent consideration of $4.0 million. During the first quarter of 2013, the liability for the estimated contingent consideration recorded in connection with this transaction was adjusted to its estimated fair value of zero resulting in the recording of other operating income of $4.0 million. Contingent consideration for the Mountain West acquisition was estimated based upon the amount of earnings before interest, depreciation, amortization and taxes expected to be earned by the acquired business during the three-year period ended December 31, 2013, subject to adjustment for capital spending levels.
Changes in the carrying amount of goodwill for the nine month period ended September 30, 2013 are as follows (in thousands):
Well Site Services
Completion Services
Drilling Services
Subtotal
Accommodations
Offshore Products
Total
Balance as of December 31, 2011
Goodwill
Accumulated Impairment Losses
Goodwill acquired and purchase price adjustments
Foreign currency translation and other changes
Balance as of December 31, 2012
Balance as of September 30, 2013
7. DISCONTINUED OPERATIONS
On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu for the sale of Sooner, which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600 million, which remains subject to customary post-closing adjustments, including final working capital determination. We recognized a net gain on disposal of $128.6 million ($84.2 million after-tax) during the third quarter of 2013, which is included within “Net income from discontinued operations, net of tax” in the Unaudited Condensed Consolidated Statements of Income.
In connection with this transaction, the parties have entered into a transition services agreement for the Company to provide certain information technology applications and infrastructure and various administrative services to Sooner during the transition period ranging from one to three months from the closing date depending on the nature of the service provided in exchange for monthly service fees. Either party has the option to terminate such transition services with notice at any time and Sooner may elect to extend such services for up to one month. The future continuing cash flows from the disposed business to the Company resulting from the transition services agreement are not significant and do not constitute a material continuing financial interest in Sooner.
Sooner, which had previously been presented as a separate reporting unit, meets the criteria for being reported as a discontinued operation and has been reclassified from continuing operations. The amounts in the table below reflect the operating results of Sooner reported as discontinued operations (in thousands). The $128.6 million ($84.2 after-tax) net gain related to the disposal of Sooner is excluded.
Two
Months
Ended
Three
Eight
Nine
August 31, 2013
September 30, 2012
Income from discontinued operations before income taxes
Net income from discontinued operations, net of tax
The following table summarizes the major classes of assets and liabilities held for sale in the Company’s Consolidated Balance Sheet related to Sooner (in thousands):
December 31, 2012
Assets
Total current assets held for sale
Property, plant and equipment, net
Total noncurrent assets held for sale
Liabilities
Total current liabilities held for sale
Total noncurrent liabilities held for sale
8. DEBT
As of September 30, 2013 and December 31, 2012, long-term debt consisted of the following (in thousands):
September 30, 2013
U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million; no borrowings outstanding during the nine month period ended September 30, 2013
U.S. term loan of $200 million, which was repaid in full in 2013; weighted average interest rate of 2.3% for the nine month period ended September 30, 2013
Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million; no borrowings outstanding during the nine month period ended September 30, 2013
Canadian term loan of $100 million, which was repaid in full in 2013; weighted average interest rate of 3.3% for the nine month period ended September 30, 2013
Australian revolving credit facility, which matures December 10, 2015, with available commitments up to A$300 million and with a weighted average interest rate of 5.1% for the nine month period ended September 30, 2013
6 1/2% senior unsecured notes - due June 2019
5 1/8% senior unsecured notes - due January 2023
Capital lease obligations and other debt
Total debt
Less: Current portion
Total long-term debt and capitalized leases
5 1/8% Senior Unsecured Notes
On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Senior Notes due 2023 (5 1/8% Notes) through a private placement to qualified institutional buyers. The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
Twelve Month Period Beginning January 15,
% of Principal Amount
2018
102.563%
2019
101.708%
2020
100.854%
2021 and thereafter
100.000%
The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. revolving credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.
6 1/2% Senior Unsecured Notes
On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% senior unsecured notes (6 1/2% Notes) due 2019 through a private placement to qualified institutional buyers. The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
Twelve Month Period Beginning June 1,
2014
104.875%
2015
103.250%
2016
101.625%
2017 and thereafter
The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Notes to repay borrowings outstanding under its U.S. and Canadian credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.
2 3/8% Contingent Convertible Senior Notes
On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025 (2 3/8% Notes), totaling $174,990,000 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and, in the aggregate, 3,012,380 shares of the Company’s common stock valued at $220.6 million.
An effective interest rate of 7.17% was applied as of the issuance date for our 2 3/8% Notes in accordance with ASC 470-20 – Debt with Conversion and Other Options. Interest expense on the 2 3/8% Notes, excluding amortization of debt issue costs, was as follows (in thousands):
Three months ended
Nine months ended
Interest expense
As of September 30, 2013, the Company had approximately $776.0 million of cash and cash equivalents and $716.8 million of the Company’s U.S. and Canadian credit facilities available for future financing needs. The Company also had availability totaling A$300 million under its Australian credit facility. As of September 30, 2013, the Company had $33.2 million of outstanding letters of credit which reduced amounts available under its credit facilities.
Interest expense on the condensed consolidated statements of income is net of capitalized interest of $0.2 million and $0.8 million, respectively, for the three and nine months ended September 30, 2013 and $0.7 million and $3.2 million, respectively, for the same periods in 2012.
9. FAIR VALUE MEASUREMENTS
The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, bank debt and foreign currency forward contracts. The Company believes that the carrying values of these instruments on the accompanying consolidated balance sheets approximate their fair values.
The fair values of the Company’s 6 1/2% Notes and 5 1/8% Notes are estimated based on quoted prices and analysis of similar instruments (Level 2 fair value measurements). The carrying values and fair values of these notes are as follows for the periods indicated (in thousands):
Carrying
Fair
Value
5 1/8% Notes
Principal amount due 2023
6 1/2% Notes
Principal amount due 2019
10. CHANGES IN COMMON STOCK OUTSTANDING
Shares of common stock outstanding – January 1, 2013
Shares issued upon exercise of stock options and vesting of restricted stock awards
Repurchase of shares – transferred to treasury
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury
Shares of common stock outstanding – September 30, 2013
11. STOCK BASED COMPENSATION
During the first nine months of 2013, we granted restricted stock awards totaling 311,410 shares valued at a total of $25.3 million. Of the restricted stock awards granted in the first nine months of 2013, a total of 264,557 awards vest in four equal annual installments beginning in February 2014, 30,314 awards are performance based awards that may vest in February 2016 in an amount that will depend on the Company’s achievement of specified performance objectives, 9,880 awards vest 100% in May 2014, 3,500 awards vest 100% in February 2014 and 2,750 awards vest 100% in March 2014. The 2013 performance based awards have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period commencing January 1, 2013 and ending December 31, 2015. During the nine months ended September 30, 2013, the Company also granted 71,500 units of phantom shares under the Canadian Long-Term Incentive Plan, which provides for the granting of units of phantom shares to key Canadian employees. These awards vest in three equal annual installments beginning in February 2014 and are accounted for as a liability until paid. Participants granted units of phantom shares are entitled to a lump sum cash payment equal to the fair market value of a share of the Company’s common stock on the vesting date. A total of 149,402 stock options with a ten-year term were awarded in the nine months ended September 30, 2013 with an average exercise price of $80.25, a fair value of $4.2 million and that will vest in four equal annual installments starting in February 2014.
Stock based compensation pre-tax expense from continuing operations recognized in the nine month periods ended September 30, 2013 and 2012 totaled $21.7 million and $13.5 million, or $0.31 and $0.19 per diluted share after tax, respectively. Stock based compensation pre-tax expense from continuing operations recognized in the three month periods ended September 30, 2013 and 2012 totaled $7.8 million and $4.7 million, or $0.11 and $0.07 per diluted share after tax, respectively. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2013 and 2012 was $13.4 million and $14.2 million, respectively. At September 30, 2013, $46.2 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.
In connection with the September 2013 sale of Sooner, modifications were made to outstanding equity options and awards for Sooner employees which resulted in $4.7 million in expense. This expense is included in “Net income from discontinued operations, net of tax” on the Unaudited Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2013 and is included in the transaction costs considered in the calculation of the $128.6 million pre-tax gain on the disposal of Sooner.
12. INCOME TAXES
Income tax expense for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the three and nine months ended September 30, 2013 totaled $27.1 million, or 25.9% of pretax income, and $86.4 million, or 26.6% of pretax income, respectively, compared to income tax expense of $33.6 million, or 25.7% of pretax income, and $113.9 million, or 26.5% of pretax income, respectively, for the three and nine months ended September 30, 2012. The effective tax rates for the three and nine months ended September 30, 2013 and 2012 are comparable, and are both lower than U.S. statutory rates because of lower foreign tax rates.
13. SEGMENT AND RELATED INFORMATION
In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, accommodations and offshore products. The Company’s reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technologies and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. Separate business lines within the well site services segment have been disclosed to provide additional detail for that segment. Results of a portion of our accommodations segment supporting Steam-Assisted Gravity Drainage (SAGD) and traditional oil and natural gas drilling activities are impacted by seasonally higher activity during the Canadian winter drilling season occurring in the first calendar quarter, typically followed by lower activity during Spring break-up in the second quarter.
Financial information by business segment for continuing operations for each of the three and nine months ended September 30, 2013 and 2012 is summarized in the following table (in thousands):
Revenues from unaffiliated customers
Operating income (loss)
Equity in earnings (loss) of unconsolidated affiliates
Capital expenditures
Three months ended September 30, 2013
Well site services –
Completion services
Drilling services
Total well site services
Offshore products
Corporate and eliminations
Three months ended September 30, 2012
Nine months ended September 30, 2013
Nine months ended September 30, 2012
14. COMMITMENTS AND CONTINGENCIES
The Company is a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials as a result of its products or operations. Some of these claims relate to matters occurring prior to its acquisition of businesses, and some relate to businesses it has sold. In certain cases, the Company is entitled to indemnification from the sellers of businesses, and in other cases, it has indemnified the buyers of businesses from it. Although the Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on it, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its consolidated financial position, results of operations or liquidity.
15. PLANNED SPIN-OFF OF ACCOMMODATIONS BUSINESS
On July 30, 2013, we announced that our board of directors has approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to the Company’s shareholders. The objective of the spin-off is to more effectively focus on two distinct businesses, achieve lower cost of capital for our accommodations business, to pursue more tailored and aggressive growth strategies and optimize operating efficiencies among other objectives. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 to be filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our board of directors and is expected to be completed in or before the summer of 2014. The Accommodations business will initially be spun-off as a C-Corporation, which offers a faster path to separation. The Accommodations business will continue to assess the feasibility and advisability of a potential future conversion into a real estate investment trust (REIT). In connection with this announced spin-off, we anticipate the need to separately capitalize the accommodations business and to refinance the Company’s existing debt.
16. CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Certain wholly-owned subsidiaries, as detailed below (the Guarantor Subsidiaries), have guaranteed all of the 6 1/2% Notes and all of the 5 1/8% Notes. These guarantees are full and unconditional, subject to the following release provisions:
●
in connection with any sale, exchange or transfer (by merger, consolidation or otherwise) of the capital stock of that guarantor after which that guarantor is no longer a restricted subsidiary;
upon proper designation of a guarantor by the Company as an unrestricted subsidiary;
upon the release or discharge of all outstanding guarantees by a guarantor of indebtedness of the Company and its restricted subsidiaries under any credit facility;
upon legal or covenant defeasance or satisfaction and discharge of the indenture; or
upon the dissolution of a guarantor, provided no event of default has occurred under the indentures and is continuing.
The following condensed consolidating financial information is included so that separate financial statements of the Guarantor Subsidiaries are not required to be filed with the Commission. The condensed consolidating financial information presents investments in both consolidated and unconsolidated affiliates using the equity method of accounting.
The following condensed consolidating financial information presents: condensed consolidating statements of income for each of the three and nine month periods ended September 30, 2013 and 2012, condensed consolidating balance sheets as of September 30, 2013 and December 31, 2012 and the statements of cash flows for each of the nine months ended September 30, 2013 and 2012 of (a) the Company, parent/guarantor, (b) Acute Technological Services, Inc., Capstar Holding, L.L.C., Capstar Drilling, Inc., General Marine Leasing, LLC, Oil States Energy Services L.L.C., Oil States Energy Services Holding, Inc., OSES International Holding, L.L.C., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, LLC, PTI Group USA LLC, PTI Mars Holdco 1, LLC and Tempress Technologies, Inc. (the Guarantor Subsidiaries), (c) the non-guarantor subsidiaries, (d) consolidating adjustments necessary to consolidate the Company and its subsidiaries and (e) the Company on a consolidated basis.
With our sale of Sooner, Inc. on September 6, 2013, it is no longer a Guarantor Subsidiary. The Condensed Consolidated Statements of Income and Balance Sheets have been reclassified for all periods presented to reflect only the Company’s continuing operations.
We have revised the presentation of our condensed consolidating statement of cash flows for the nine month period ended September 30, 2012 to reflect equity contributions by the Parent Guarantor to Guarantor Subsidiaries of $14 million and by Guarantor Subsidiaries to Non-Guarantor Subsidiaries of $10 million between investing and financing activities in accordance with SEC Regulation S-X, which were previously presented as net amounts in investing activities as “proceeds from (funding of) accounts and notes with affiliates.” These changes had no impact on consolidated results, as previously reported.
Condensed Consolidating Statements of Income and Comprehensive Income
Three Months Ended September 30, 2013
Oil States
International,
Inc. (Parent/
Guarantor)
Guarantor
Subsidiaries
(Non-
Guarantors)
Consolidating
Adjustments
Consolidated Oil
States
Inc.
(In thousands)
REVENUES
Operating revenues
Intercompany revenues
Total revenues
OPERATING EXPENSES
Intercompany cost of sales and services
Other operating (income) expense
Other income (expense)
Net income from discontinued operations, net of tax (including a net gain on disposal of $84,209)
Total other comprehensive income
Three Months Ended September 30, 2012
Other operating (income)expense
Nine Months Ended September 30, 2013
Unrealized loss on forward contracts
Nine Months Ended September 30, 2012
Consolidating Balance Sheets
Consolidated
ASSETS
Investments in unconsolidated affiliates
Long-term intercompany receivables (payables)
LIABILITIES AND EQUITY
Stockholders’ equity
Non-controlling interest
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Cash Flows
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for equity contributions
Net cash provided by (used in) investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net
Debt and capital lease payments
Proceeds from (funding of) accounts and notes with affiliates, net
Payments from equity contributions
Net cash provided by (used in) financing activities
Payment of principal on 2 3/8% Notes conversion```
This quarterly report on Form 10-Q contains "certain forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Some of the information in the quarterly report may contain "forward-looking statements." The "forward-looking statements" can be identified by the use of forward-looking terminology including "may," "expect," "anticipate," "estimate," "continue," "believe," or other similar words. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of known material factors that could affect our results, please refer to “Part II, Item 1A. Risk Factors” in this report and "Part I, Item 1A. Risk Factors" and the financial statement line item discussions set forth in "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in our 2012 Form 10-K filed with the Commission on February 20, 2013. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.
In addition, in certain places in this quarterly report, we refer to reports published by third parties that purport to describe trends or developments in the energy industry. The Company does so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’s investors in a better understanding of the market environment in which the Company operates. However, the Company specifically disclaims any responsibility for the accuracy and completeness of such information and undertakes no obligation to update such information.
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis together with our condensed consolidated financial statements and the notes to those statements included elsewhere in this quarterly report on Form 10-Q.
Macroeconomic Environment
We provide a broad range of products and services to the oil and gas industry through our accommodations, offshore products and well site services business segments, and our accommodations segment also supports the mining industry. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to invest capital in the exploration for and development of oil, natural gas, metallurgical (met) coal and other mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is highly sensitive to current and expected commodity prices, principally that of crude oil, met coal and natural gas.
In the past few years, crude oil prices in North America have been volatile due to global economic uncertainties as well as inadequate regional take-away pipeline capacity. However, crude oil prices continue to trade at relatively high historic levels. This volatility continued in the first nine months of 2013 with fluctuations in crude oil prices in response to changing market sentiment regarding the outlook for economic growth in the U.S. and China, decreased crude oil production by Organization of the Petroleum Exporting Countries (OPEC), heightened geopolitical risks in the Middle East and North Africa and increased oil production in the U.S. The price of West Texas Intermediate (WTI) crude oil increased from an average price of $88 per barrel in the fourth quarter of 2012 to $98 per barrel in the first nine months of 2013, finishing the first nine months of 2013 at $102 per barrel. The price of Intercontinental Exchange (ICE) Brent crude decreased modestly from an average price of $110 per barrel in the fourth quarter of 2012 to $108 per barrel in the first nine months of 2013, finishing the first nine months of 2013 at $108 per barrel. As of October 30, 2013, WTI crude traded at approximately $97 per barrel while ICE Brent crude traded at approximately $110 per barrel. The price for WTI will influence our customers spending in U.S. shale play developments, such as the Bakken, Niobrara, Permian and Eagle Ford. Spending in these regions will influence the overall drilling and completion activity in the area and, therefore, the activity of our well site services segment.
In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Pricing for WCS is driven by several factors. A significant factor offsetting WCS pricing is the underlying price for WTI. As WTI prices have improved over the past few years with the global economic recovery, WCS prices have also improved. Another significant factor offsetting WCS pricing has been transportation. Historically, WCS has traded at a discount to WTI due to transportation costs and limited capacity to move Canadian crude to U.S. refineries. Depending on the extent of pipeline capacity availability, the discount of WCS to WTI has varied. With the improvement in global oil prices and some added transportation from the oil sands region utilizing rail and barge alternatives, the absolute price of WCS and its discount to WTI have improved. WCS prices in the third quarter of 2013 averaged $83.10 per barrel compared to $76.10 per barrel in the third quarter of 2012. However, the WCS discount to WTI crude widened substantially from below $15 per barrel by the end of the second quarter of 2013 to over $30 per barrel by the end of the third quarter of 2013, as production increased and demand from U.S. refineries declined due to maintenance requirements. As of October 30, 2013, WCS crude traded at a $36 discount to WTI crude. Should the price of WTI decline or the WCS discount to WTI widen further, our oil sands customers’ may delay additional investments or reduce their spending in the oil sands region.
Given the historical volatility of crude prices, there remains a risk that prices could deteriorate going forward due to increased domestic crude oil production or potentially slower economic growth in China, fiscal and financial uncertainty in the U.S. and various European countries, potentially negative effects on economic growth in the U.S. due to automatic government spending cuts and a prolonged level of relatively high unemployment in the U.S. and other advanced economies. However, if the global supply of oil or global inventory levels were to decrease due to government instability in a major oil-producing nation and energy demand continues to increase in countries such as China, India and the U.S., WTI crude prices may stabilize or improve which could positively affect future U.S. drilling activity. Conversely, if WCS crude prices continue to experience a significant discount to WTI crude, our oil sands customers’ may defer investments.
Prices for natural gas in the United States have improved during the first nine months of 2013, largely due to above average storage withdrawals in response to colder winter weather, continued elevated demand for natural gas for electric power generation (in substitution for coal, so called “gas for coal switching”), lower net imports from Canada and higher industrial demand. These improvements in demand have been largely supplied by increased domestic production of natural gas. Natural gas prices continue to be weak relative to prices experienced in 2006 through 2008 due to the rise in production from unconventional natural gas resources in North America. Natural gas production in the U.S. has increased due to onshore dry-gas shale production as well as associated natural gas production from shale oil wells and liquids-oriented wells in onshore basins resulting from the broad application of horizontal drilling and hydraulic fracturing techniques. Natural gas prices traded at approximately $3.60 per Mcf as of October 30, 2013. As a result of natural gas production growth outpacing demand in the U.S., the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 380 rigs as of October 25, 2013. Natural gas inventories in the U.S. have declined from 8% above the 5-year average as of the end of the third quarter of 2012 to 1% above the 5-year average as of the end of the third quarter of 2013. Any increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, could constrain prices for natural gas for an extended period and result in fewer rigs drilling for gas in the near-term.
Recent WTI crude, ICE Brent crude, WCS crude and natural gas pricing trends are as follows:
Average Price(1)
Quarter ended
WTI Crude (per bbl)
ICE Brent Crude (per bbl)
WCS Crude (per bbl)
Natural Gas (per mcf)
9/30/2013
6/30/2013
3/31/2013
12/31/2012
9/30/2012
6/30/2012
3/31/2012
12/31/2011
9/30/2011
__________
(1) Source: WTI crude, ICE Brent crude and natural gas prices from U.S. Energy Information Administration (EIA) and WCS crude prices from Bloomberg.
Because Chinese steel production has been growing at a slower pace than that experienced in 2010 and early 2011, Chinese demand for imported steel inputs such as met coal and iron ore decreased during the first nine months of 2013 compared to the first nine months of 2012. Met coal pricing has improved from the second quarter of 2013 but is still well below 2012 pricing levels. Due to lower Chinese demand met coal prices have decreased materially from over $200/metric ton at the beginning of 2012 to approximately $150/metric ton at the end of the third quarter of 2013. Continued depressed met coal prices have led to reduced operating and capital spending by our customers, certain coal mine closures and deferral of expansionary coal mining projects in Australia.
Overview
Demand for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, demand for our well site services segment responds to shorter-term movements in oil and natural gas prices and, specifically, changes in North American drilling and completion activity. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the U. S. and internationally.
Our accommodations business is predominantly located in northern Alberta, Canada and Queensland, Australia and derives most of its business from resource companies who are developing and producing oil sands and met coal resources and, to a lesser extent, other mineral resources. More than three-fourths of our accommodations revenue is generated by our large-scale lodge and village facilities. Where traditional accommodations and infrastructure are not accessible or cost effective, our lodge and village facilities provide comprehensive accommodations services similar to those found in an urban hotel. We typically contract our facilities to our customers on a fee per day basis covering lodging and meals that is based on the duration of their needs which can range from several months to several years.
Generally, our oil sands and mining accommodations’ customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of ten years to in excess of thirty years and, consequently, these investments are dependent on those customers' longer-term view of commodity demand and prices. Oil sands development activity has increased over the past several years and has had a positive impact on our accommodations segment. However, the growth rate slowed during 2012 and 2013 due to weaker WCS crude pricing and concerns over a lack of transportation infrastructure. Sanctioning of new and expanded oil sands projects by our customers, if they occur, may create the opportunity for extensions of existing accommodations contracts and incremental accommodations contracts in Canada.
We have been expanding our Australian accommodations capacity to meet increasing demand, notably in the Bowen Basin in Queensland and in the Gunnedah Basin in New South Wales to support met coal production, and in Western Australia to support LNG and other energy-related projects. However, these expansions have slowed significantly in 2013, primarily due to reduced customer expansion plans with the decline in met coal prices beginning in late 2012 and lasting through the first nine months of 2013.
Our offshore products segment provides highly engineered products for offshore oil and natural gas drilling and production systems and facilities. Sales of our offshore products and services depend primarily upon capital spending for offshore production systems and subsea pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices.
As a result of the positive outlook for long-term oil demand, along with continued high oil prices, bidding and quoting activity for our offshore products segment continued to be very active during the first nine months of 2013. Backlog in our offshore products segment remained strong, totaling $569 million as of September 30, 2013 compared to $561 million at December 31, 2012 and $561 million at June 30, 2013. We anticipate global deepwater spending to continue at robust levels due to new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico and Southeast Asia over the next twelve months.
Our well site services business segment is affected by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world. As recently as 2008, overall North American drilling and completion activity was primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, considering higher oil prices, lower natural gas prices and the advancement of horizontal drilling and completion activity in North America has shifted to a greater proportion of oil and liquids-rich drilling. According to rig count data published by Baker Hughes Incorporated, the oil rig count in the U.S. as of October 25, 2013 totals approximately 1,360 rigs, comprising approximately 74% of total U.S. drilling activity.
In our well site services business segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our completion services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the completion services business is dependent primarily upon the level and complexity of drilling, completion and workover activity throughout North America. Well complexity has increased as the number of productive areas completed in connection with horizontal drilling and the number of wells drilled at a specific drill-site have increased. Demand for our drilling services is driven by land drilling activity in our primary drilling markets of West Texas, where we primarily drill oil wells, and the Rocky Mountain area in the U.S., where we drill both liquids-rich and natural gas wells.
We have a diversified product and service offering, which has exposure to activities conducted throughout the oil and gas cycle. Demand for our land drilling and completion services businesses is highly correlated to changes in the drilling rig count in the United States and, to a much lesser extent, Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.
Average Drilling Rig Count for
U.S. Land – Oil
U.S. Land – Natural gas and other
U.S. Offshore
Total U.S.
Canada
Total North America
The average North American rig count for the nine months ended September 30, 2013 decreased by 126 rigs, or 5.6%, compared to the nine months ended September 30, 2012 largely due to a decline in natural gas drilling.
A factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and between the U.S. dollar and the Australian dollar. Our accommodations segment derives a majority of its revenues and operating income in Canada and Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. The Canadian dollar was valued at an average exchange rate of U.S. $0.98 for the first nine months of 2013 compared to U.S. $1.00 for the first nine month of 2012, a decrease of 2%. The Australian dollar was valued at an average exchange rate of U.S. $0.98 for the first nine months of 2013 compared to U.S. $1.04 for the first nine months of 2012, a decrease of 6%. Importantly, exchange rates had weakened further by the end of the third quarter of 2013, standing at U.S. $0.93 per Australian dollar and U.S. $0.97 per Canadian dollar, respectively, as of September 30, 2013. This weakening of the Canadian and Australian dollars has and may continue to have a proportionately negative impact on the translation of earnings generated from our Canadian and Australian subsidiaries and, therefore, the financial results of our accommodations segment.
While global demand for oil and natural gas are significant factors influencing our business generally, certain other factors also influence our business, such as the pace of worldwide economic growth and the recovery in U.S. Gulf of Mexico drilling following the lifting of the government imposed drilling moratorium.
Although 83% higher than in 2012, the drilling rig count in the first nine months of 2013 in the U.S. Gulf of Mexico remains below historical levels following the April 2010 Macondo well incident and resultant oil spill in the U.S. Gulf of Mexico. Beginning in the third quarter of 2011, however, U.S. Gulf of Mexico drilling activity has shown signs of a slow but steady recovery as permitting levels remain strong.
We continue to monitor the global economy, the demand for crude oil, met coal and natural gas and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. During the nine months ended September 30, 2013, we have spent $354.7 million on capital expenditures for our continuing operations and we expect that our capital expenditures for the entire year will total approximately $500 million to $550 million, compared to 2012 capital expenditures of $488 million, to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Whether planned expenditures will actually be spent in 2013 depends on industry conditions, project approvals and schedules and vendor delivery timing. Our 2013 capital expenditures include funding to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total expected 2013 capital expenditures will be spent in our accommodations segment. We expect to fund these capital expenditures with cash available and internally generated funds. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on an evaluation of both the market outlook and industry fundamentals.
On July 30, 2013, we announced that our board of directors has approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to the Company’s shareholders. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 to be filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our board of directors and is expected to be completed in or before the summer of 2014.
On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu Tubulars America, Inc. (Marubeni-Itochu) for the sale of Sooner, Inc. and its subsidiaries (Sooner), which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600 million, which remains subject to customary post-closing adjustments, including final working capital determination. We recognized a net gain on disposal of $128.6 million ($84.2 million after-tax) during the third quarter of 2013, which is included within “Net income from discontinued operations, net of tax” in the Unaudited Condensed Consolidated Statements of Income. Operating results for the Company’s tubular services business have been classified as discontinued operations for all periods presented.
Consolidated Results of Continuing Operations (in millions)
Nine Months ended
Variance
2013 vs. 2012
$
%
Well site services -
Product costs; service and other costs
(“Cost of sales and service”)
Gross margin
< 1
Gross margin as a percentage of revenues
THREE MONTHS ENDED SEPTEMBER 30, 2013 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2012
We reported net income from continuing operations attributable to the Company for the quarter ended September 30, 2013 of $77.1 million, or $1.38 per diluted share, including a pre-tax gain on the disposal of land and an associated building of $4.6 million, or $0.06 per diluted share after tax, and a pre-tax loss on the extinguishment of debt of $3.3 million, or $0.04 per diluted share after tax. In addition, the Company incurred $2.6 million, or $0.04 per diluted share after tax, of transaction costs in the third quarter of 2013 related to the proposed spin-off of our accommodations segment which is included in “Other operating (income) expense.” These results compare to net income from continuing operations attributable to the Company of $97.0 million, or $1.75 per diluted share, reported for the three months ended September 30, 2012.
Revenues. Consolidated revenues increased $40.0 million, or 6%, in the third quarter of 2013 compared to the third quarter of 2012.
Our well site services segment revenues increased $14.2 million, or 8%, in the third quarter of 2013 compared to the third quarter of 2012 primarily due to an increase in completion services revenues, partially offset by a decrease in drilling services revenues. Our completion services revenues increased $21.2 million, or 16%, in the third quarter of 2013 compared to the third quarter of 2012 as a result of increased service intensity in the active shale basins along with contributions from the Tempress acquisition completed in the fourth quarter of 2012. Our revenue per ticket increased 13% year-over-year (excluding the contribution from the acquisition of Tempress) as the industry favored our higher specification equipment. The number of service tickets issued in the third quarter of 2013 was relatively flat compared to the third quarter of 2012 (also excluding the contribution from the acquisition of Tempress). Our drilling services revenues decreased $7.0 million, or 14%, in the third quarter of 2013 compared to the third quarter of 2012 primarily as a result of decreased utilization of our rigs, particularly in the Permian basin, from an average of approximately 92% for the third quarter of 2012 to an average of approximately 78% for the third quarter of 2013.
Our accommodations segment reported revenues in the third quarter of 2013 that were $27.0 million, or 10%, lower than the third quarter of 2012. This decrease was primarily due to the weakening of the Australian and Canadian dollars relative to U.S. dollar by 12% and 4%, respectively, in the third quarter of 2013 compared to the third quarter of 2012. Excluding the year-over-year impact of exchange rates, accommodations revenues decreased 4% primarily due to a 16% decline in other accommodations revenue and a 1% decline in lodge and village revenue. Other accommodations revenue was lower year-over-year due to lower mobile camp activity in Canada coupled with lower third-party manufacturing revenues in Canada. Lodge and village revenues declined due to an 11% year-over-year decrease in revenue per available room (RevPAR) related to lower contracted rates in Canada and lower occupancy levels, primarily in Australia as a result of the continued slowdown in mining activity, partially offset by an 11% increase in average available rooms in 2013 compared to 2012.
Our offshore products segment revenues increased $52.8 million, or 28%, in the third quarter of 2013 compared to the third quarter of 2012. This increase was primarily the result of a revenue mix favoring our subsea equipment and drilling products, increased sales associated with sourced material acquired for our customers for the Jack St. Malo deepwater development, partially offset by lower production equipment revenues.
Cost of Sales and Service. Our consolidated cost of sales increased $40.2 million, or 10%, in the third quarter of 2013 compared to the third quarter of 2012 primarily as a result of increased cost of sales at our offshore products segment of $36.0 million, or 25%. Our consolidated gross margin as a percentage of revenues decreased from 39% in the third quarter of 2012 to 37% in the third quarter of 2013 primarily due to decreased margins in our accommodations segment and a higher proportion of relatively lower-margin offshore products revenues.
Our well site services segment cost of sales increased $8.6 million, or 7%, in the third quarter of 2013 compared to the third quarter of 2012 as a result of a $11.1 million, or 14%, increase in completion services cost of sales, partially offset by a $2.5 million, or 7%, decrease in drilling services cost of sales. Our completion services segment gross margin as a percentage of revenues increased from 38% in the third quarter of 2013 to 40% in the third quarter of 2012 primarily due to the 13% year-over-year increase in revenue per ticket. Our drilling services gross margin as a percentage of revenues decreased from 33% in the third quarter of 2012 to 28% in the third quarter of 2013 primarily due to the decreased rig utilization and cost absorption.
Our accommodations segment cost of sales decreased $4.4 million, or 3%, in the third quarter of 2013 compared to the third quarter of 2012. Our accommodations segment gross margin as a percentage of revenues decreased from 50% in the third quarter of 2012 to 46% in the third quarter of 2013 primarily due to lower contracted rates in Canada, lower cost absorption in Canada and the U.S. and lower pricing in the U.S.
Our offshore products segment cost of sales increased $36.0 million, or 25%, in the third quarter of 2013 compared to the third quarter of 2012 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues increased from 25% in the third quarter of 2012 to 26% in the third quarter of 2013, primarily due to an unfavorable margin adjustment in the third quarter of 2012 on a subsea pipeline project in Brazil. The increase in margins in 2013 was despite an increase in lower-margin sales associated with sourced material acquired for our customers.
Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expense increased $7.8 million, or 17%, in the third quarter of 2013 compared to the third quarter of 2012 primarily due to increased employee-related costs, commissions, advertising and trade show costs, insurance costs and professional fees, partially offset by decreased bad debt expense and the weakening of the Australian and Canadian dollars relative to U.S. dollar in the third quarter of 2013 compared to the third quarter of 2012.
Depreciation and Amortization. Depreciation and amortization expense increased $11.3 million, or 19%, in the third quarter of 2013 compared to the third quarter of 2012 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and completion services businesses.
Operating Income. Consolidated operating income decreased $22.2 million, or 15%, in the third quarter of 2013 compared to the third quarter of 2012 primarily as a result of a decrease in operating income from our accommodations segment of $28.3 million, or 33%, primarily due to the lower contracted rates in Canada, lower occupancy levels in Australia and lower utilization for our U.S. accommodations assets, partially offset by the increase in average available rooms in the third quarter of 2013 compared to the third quarter of 2012. The Company also incurred $2.6 million of transaction costs in the third quarter of 2013 related to the proposed spin-off of our accommodations segment which is included in “Other operating (income) expense.” These decreases in operating income were partially offset by an increase in operating income from our offshore products segment of $12.9 million, or 46%, in the third quarter of 2013 compared to the third quarter of 2012.
Interest Expense and Interest Income. Net interest expense increased by $2.9 million, or 19%, in the third quarter of 2013 compared to the third quarter of 2012 primarily due to interest expense on the 5 1/8% Senior Notes due 2023 (5 1/8% Notes) issued on December 21, 2012, partially offset by decreased interest expense on our revolving credit facilities due to no outstanding borrowings during the third quarter of 2013. The weighted average interest rate on the Company’s total outstanding debt was 5.5% in the third quarter of 2013 compared to 4.8% in the third quarter of 2012. Interest income increased as a result of increased cash balances in interest bearing accounts.
Loss on Extinguishment of Debt. During the third quarter of 2013, $3.3 million of deferred financing costs, representing the remaining book value of deferred financing costs associated with our U.S. and Canadian term loans, was expensed due to their repayment in full.
Income Tax Expense. Our income tax provision for the three months ended September 30, 2013 totaled $27.1 million, or 25.9% of pretax income, compared to income tax expense of $33.6 million, or 25.7% of pretax income, for the three months ended September 30, 2012. The effective tax rates for the three months ended September 30, 2013 and 2012 are comparable, and are both lower than U.S. statutory rates because of lower foreign tax rates.
Discontinued Operations. Exclusive of a $128.6 million pre-tax gain ($84.2 million after tax) recorded on the disposal of our tubular services business, net income from discontinued operations for the three months ended September 30, 2013 was $6.5 million compared to $6.8 million for the three months ended September 30, 2012. Revenues reported within discontinued operations were $273.6 million and $436.2 million during the three month periods ended September 30, 2013 and 2012, respectively. The decrease in revenue primarily relates to the disposal of our tubular services business on September 6, 2013. The operating income included within discontinued operations was $10.2 million for the three month periods ended September 30, 2013 and 2012. The operating income for the third quarter of 2012 includes $7.5 million in non-cash unfavorable out-of-period adjustments to correct accruals of customer credits and related returned inventory and other cost accrual adjustments.
Other Comprehensive Income. Other comprehensive income increased $1.4 million in the third quarter of 2013 compared to the third quarter of 2012 primarily as a result of foreign currency translation adjustments due to increases in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar exchange rate compared to the U.S. dollar increased 2% in the third quarter of 2013 compared to a 4% increase in the third quarter of 2012. The Australian dollar exchange rate compared to the U.S. dollar increased 2% in the third quarter of 2013 compared to a 1% increase in the third quarter of 2012.
NINE MONTHS ENDED SEPTEMBER 30, 2013 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2012
We reported net income from continuing operations attributable to the Company for the nine months ended September 30, 2013 of $237.0 million, or $4.27 per diluted share, including a pre-tax gain on the disposal of land and an associated building of $4.6 million, or $0.06 per diluted share after tax, a pre-tax loss on the extinguishment of debt of $3.3 million, or $0.04 per diluted share after tax, a gain of $4.0 million, or $0.07 per diluted share, from a decrease to a liability associated with contingent acquisition consideration in our U.S. accommodations business and a charge of $3.0 million, or $0.04 per diluted share, from an increase in contingent acquisition consideration in our completion services business. In addition, the Company incurred $4.1 million, or $0.05 per diluted share after tax, of transaction costs in the first nine months of 2013 which is included in “other operating (income) expense” and primarily relate to the planned spin-off of our accommodations segment. These results compare to net income from continuing operations attributable to the Company of $314.5 million, or $5.68 per diluted share, reported for the nine months ended September 30, 2012, including a gain of $17.9 million, or $0.23 per diluted share after tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after tax, related to insurance proceeds received for a land drilling rig lost in a fire that occurred in the first quarter of 2012.
Revenues. Consolidated revenues increased $50.8 million, or 3%, in the first nine months of 2013 compared to the first nine months of 2012.
Our well site services segment revenues increased $18.5 million, or 3%, in the first nine months of 2013 compared to the first nine months of 2012 due to an increase in completion services revenues, partially offset by a decrease in drilling services revenues. Our completion services revenues increased $40.0 million, or 10%, in the first nine months of 2013 compared to the first nine months of 2012 as a result of increased service intensity in the active shale basins along with contributions from the Tempress acquisition completed in the fourth quarter of 2012. Our revenue per ticket increased 12% year-over-year (excluding the contribution from the acquisition of Tempress) as the industry favored our higher specification equipment. The number of service tickets issued in the first nine months of 2013 decreased 4% compared to the first nine months of 2012 (also excluding the contribution from the acquisition of Tempress) due primarily to reduced activity, particularly in the Haynesville and Barnett regions, resulting from reduced customer spending in dry gas markets, partially offset by increased activity in the Bakken region. The results for the completion services business were also negatively impacted by a revenue accrual adjustment for international operations which reduced revenues in the first nine months of 2013 by $1.4 million. Our drilling services revenues decreased $21.5 million, or 14%, in the first nine months of 2013 compared to the first nine months of 2012 primarily as a result of decreased utilization of our rigs, particularly in the Permian basin, from an average of approximately 91% for the first nine months of 2012 to an average of approximately 76% for the first nine months of 2013.
Our accommodations segment reported revenues in the first nine months of 2013 that were $48.9 million, or 6%, lower than the first nine months of 2012. This decrease was primarily due to a 13% decline in other accommodations revenue, the weakening of the Canadian and Australian dollars relative to U.S. dollar by 2% and 6%, respectively, in the first nine months of 2013 compared to the first nine months of 2012, a favorable contract settlement reported in our U.S. accommodations business of $18.3 million in the first quarter of 2012 and a 3% decline in lodge and village revenue. Other accommodations revenue declined due to lower mobile camp activity in Canada, lower utilization for our U.S. accommodation assets coupled with lower third-party manufacturing revenues. Lodge and village revenues declined due to an 8% year-over-year decrease in RevPAR related to lower contracted rates in Canada and lower occupancy levels, primarily in Australia as a result of the continued slowdown in mining activity, partially offset by a 12% increase in average available rooms in 2013 compared to 2012. In the U.S., utilization for our U.S. accommodations was negatively impacted by poor weather conditions in the Bakken region, lower U.S. rig count and increased competition. U.S. accommodations are driven by shorter-term and spot contracts and, therefore, have more exposure to reduced activity due to commodity price changes.
Our offshore products segment revenues increased $81.2 million, or 14%, in the first nine months of 2013 compared to the first nine months of 2012. This increase was primarily the result of increased drilling and subsea product sales along with contributions from the acquisition of Piper, which was acquired in July 2012.
Cost of Sales and Service. Our consolidated cost of sales increased $76.4 million, or 7%, in the first nine months of 2013 compared to the first nine months of 2012 as a result of increased cost of sales at our offshore products and well site services segments of $59.2 million, or 14%, and $10.7 million, or 3%, respectively. Our consolidated gross margin as a percentage of revenues decreased from 40% in the first nine months of 2012 to 37% in the first nine months of 2013 primarily due to the favorable contract settlement reported in our U.S. accommodations business in 2012, lower margins realized in our Canadian accommodations business and a higher proportion of relatively lower-margin offshore products revenues.
Our well site services segment cost of sales increased $10.7 million, or 3%, in the first nine months of 2013 compared to the first nine months of 2012 as a result of a $24.5 million, or 10%, increase in completion services cost of sales, partially offset by a $13.8 million, or 13%, decrease in drilling services cost of sales. Our completion services segment gross margin as a percentage of revenues was 38% in both the first nine months of 2013 and 2012. Our drilling services gross margin as a percentage of revenues decreased from 30% in the first nine months of 2012 to 29% in the first nine months of 2013 primarily due to decreased rig utilization and cost absorption.
Our accommodations segment cost of sales increased $6.5 million, or 2%, in the first nine months of 2013 compared to the first nine months of 2012 primarily due to increased room capacity in Canada, partially offset by lower third-party manufacturing costs. Our accommodations segment gross margin as a percentage of revenues decreased from 51% in the first nine months of 2012 to 47% in the first nine months of 2013 primarily due to lower contracted rates in Canada and the favorable contract settlement reported in our U.S. accommodations business in the first nine months of 2012.
Our offshore products segment cost of sales increased $59.2 million, or 14%, in the first nine months of 2013 compared to the first nine months of 2012 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 26% in both the first nine months of 2013 and 2012.
Selling, General and Administrative Expenses. SG&A expense increased $23.0 million, or 17%, in the first nine months of 2013 compared to the first nine months of 2012 primarily due to increased employee-related costs, SG&A expense associated with the inclusion of Piper, which was acquired in July 2012, increased advertising and trade show expenses, professional fees, insurance costs and rent, partially offset by the weakening of the Australian and Canadian dollars to U.S. dollar exchange rates in 2013 compared to 2012.
Depreciation and Amortization. Depreciation and amortization expense increased $41.9 million, or 26%, in the first nine months of 2013 compared to the first nine months of 2012 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and completion services businesses.
Operating Income. Consolidated operating income decreased $92.4 million, or 20%, in the first nine months of 2013 compared to the first nine months of 2012 primarily as a result of a decrease in operating income from our accommodations segment of $80.8 million, or 28%, primarily due to the favorable contract settlement reported in our U.S. accommodations business in 2012, the lower contracted rates in Canada, lower occupancy levels in Australia, increased depreciation expense on accommodations assets and lower utilization for our U.S. accommodations assets, partially offset by the increase in average available rooms in 2013 compared to 2012.
Interest Expense and Interest Income. Net interest expense increased by $6.1 million, or 12%, in the first nine months of 2013 compared to the first nine months of 2012 primarily due to interest expense on our 5 1/8% Notes, issued on December 21, 2012, partially offset by decreased interest expense on our 2 3/8% Notes due to their conversion in July 2012. The weighted average interest rate on the Company’s total outstanding debt was 5.4% in the first nine months of 2013 compared to 4.8% in the first nine months of 2012. Interest income increased as a result of increased cash balances in interest bearing accounts.
Loss on Extinguishment of Debt. During the first nine months of 2013, $3.3 million of deferred financing costs, representing the remaining book value of deferred financing costs associated with our U.S. and Canadian term loans, was expensed due to their repayment in full.
Income Tax Expense. Our income tax provision for the nine months ended September 30, 2013 totaled $86.4 million, or 26.6% of pretax income, compared to income tax expense of $113.9 million, or 26.5% of pretax income, for the nine months ended September 30, 2012. The effective tax rates for the nine months ended September 30, 2013 and 2012 are comparable, and are both lower than U.S. statutory rates because of lower foreign tax rates.
Discontinued Operations. Exclusive of a $128.6 million pre-tax gain ($84.2 million after tax) recorded on the disposal of our tubular services business, net income from discontinued operations for the nine months ended September 30, 2013 was $25.2 million compared to $35.6 million for the nine months ended September 30, 2012. Revenues reported within discontinued operations were $1,073.1 million and $1,326.6 million during the nine month periods ended September 30, 2013 and 2012, respectively. The decrease in revenue primarily relates to the disposal of our tubular services business on September 6, 2013 and a 9% decrease in realized revenues per ton shipped in our tubular services business in 2013 compared to 2012 due to sales mix and reduced mill pricing. The operating income included within discontinued operations was $40.1 million and $55.8 million for the nine month periods ended September 30, 2013 and 2012, respectively.
Other Comprehensive Income (Loss). Other comprehensive income decreased from other comprehensive income of $40.1 million in the first nine months of 2012 to other comprehensive loss of $125.5 million in the first nine months of 2013 primarily as a result of foreign currency translation adjustments due to decreases in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar exchange rate compared to the U.S. dollar decreased 3% in the first nine months of 2013 compared to a 3% increase in the first nine months of 2012. The Australian dollar exchange rate compared to the U.S. dollar decreased 10% in the first nine months of 2013 compared to a 1% increase in the first nine months of 2012.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures, which in the past have included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, replacing and increasing completion services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our credit facilities and capital markets transactions.
Cash flows from discontinued operations are combined with cash flows from continuing operations within each cash flow statement category on the Company’s Unaudited Condensed Consolidated Statements of Cash Flows.
Cash totaling $582.7 million was provided by operations during the first nine months of 2013 compared to $445.5 million provided by operations during the first nine months of 2012. During the first nine months of 2013, $90.4 million was provided from net working capital reductions, primarily due to decreased investments in working capital for our tubular services business. During the first nine months of 2012, $83.4 million was used to fund working capital, primarily due to increased investments in working capital for discontinued operations and increases in receivables.
Cash was provided by investing activities during the nine months ended September 30, 2013 in the amount of $251.2 million compared to cash used in investing activities during the nine months ended September 30, 2012 in the amount of $371.8 million. A total of $600 million of cash proceeds was received from the sale of our tubular services business in September 2013. Capital expenditures totaled $355.6 million and $331.8 million during the nine months ended September 30, 2013 and 2012, respectively. Capital expenditures in both years consisted principally of purchases and installation of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments and Australian mining developments.
We expect our capital expenditures for the entire year will total approximately $500 million to $550 million, compared to 2012 capital expenditures of $488 million, to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Whether planned expenditures will actually be spent in 2013 depends on industry conditions, project approvals and schedules and vendor delivery timing. Approximately two-thirds of our total estimated 2013 capital expenditures are expected to be spent in our accommodations segment. We expect to fund these capital expenditures with cash available and internally generated funds. The foregoing capital expenditure forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company. At September 30, 2013, we had cash totaling $244.4 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where, in the case of Canada, we have assumed indefinite reinvestment of earnings and where we have not recorded a U.S. tax liability upon the assumed repatriation of foreign earnings. We believe these cash balances will be utilized for future investment outside the United States.
On August 29, 2013, we acquired the 51% majority interest in a venture we had previously accounted for under the equity method. Subject to customary post-closing adjustments, total transaction consideration was $1.45 million.
On July 2, 2012, we acquired Piper Valve Systems, Ltd (Piper). Total transaction consideration was $48.0 million, funded from amounts available under the Company’s U.S. credit facility.
Net cash of $299.5 million was used in financing activities during the nine months ended September 30, 2013, primarily as a result of the repayment of all amounts outstanding under our U.S. and Canadian term loan and repayments under our Australian credit facility. Net cash of $15.3 million was provided by financing activities during the nine months ended September 30, 2012, primarily as a result of borrowings under our U.S. revolving credit facility, partially offset by payments of principal amounts on the conversion of our 2 3/8% Notes and repayments on our U.S. and Canadian term loans.
The Company’s discontinued operations impacted the cash flows of the Company as summarized in the table below (in thousands):
Nine Months
Ended September 30,
Discontinued operations impact on:
Cash from operating activities
Cash used in investing activities
Cash used in financing activities-cash transferred to parent
Net cash impact of discontinued operations
Cash balance of discontinued operations:
At start of period
At end of period
Decrease in cash of discontinued operations
The cash used in financing activities primarily represents the net transfers of cash between the discontinued operations and Oil States International, Inc. The absence of cash flows from discontinued operations is not expected to adversely affect the investing or financing activities of the Company.
We believe that cash on hand, cash flow from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. We anticipate the need to refinance our existing debt in connection with the announced spin-off of our accommodations business in or before the summer of 2014. We also anticipate the need to separately capitalize the accommodations business which is expected to be distributed to shareholders in a tax-free spin-off in 2014. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.
Stock Repurchase Program. On September 6, 2013, the Company announced an increase in its Board-authorized Company stock repurchase program from $200 million to $500 million for the repurchase of the Company’s common stock, par value $.01 per share. As of September 30, 2013, the Company had approximately 55.1 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2014. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of September 30, 2013, a total of $27.1 million of our stock (361,175 shares) had been repurchased under this program, leaving a total authorization of up to approximately $472.9 million remaining available under the program. During the nine months ended September 30, 2013, $11.9 million of our stock (135,379 shares) was repurchased under this program at an average price of $87.82 per share.
Credit Facilities. Our current bank credit facilities include a U.S. revolving credit facility and a Canadian revolving facility. These credit facilities are governed by an Amended and Restated Credit Agreement dated of December 10, 2010 (Credit Agreement) by and among the Company, PTI Group Inc., PTI Premium Camp Services, Ltd., the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent and U.S. collateral agent and Royal Bank of Canada, as Canadian administrative agent and Canadian collateral agent. The U.S. and Canadian bank credit facilities currently contain total commitments available of $750 million, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $500 million, and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $250 million. We repaid Canadian and U.S. term loan balances previously outstanding in full during 2013, which are permanent reductions of availability under our credit facilities. The maturity date of the Credit Agreement is December 10, 2015. We currently have 19 lenders in our Credit Agreement with commitments ranging from $25.3 million to $150 million. As of September 30, 2013, we had $33.2 million of outstanding letters of credit, leaving $716.8 million available to be drawn under the U.S. and Canadian facilities.
The Credit Agreement contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0 in 2012 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of September 30, 2013, we were in compliance with our debt covenants and expect to continue to be in compliance during the remainder of 2013. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During the first nine months of 2013, our applicable margin over LIBOR was 2.00%.
On September 18, 2012, the Company’s Australian accommodations subsidiary, The MAC Services Group Pty Limited (The MAC), entered into a A$300 million revolving loan facility governed by a Syndicated Facility Agreement (The MAC Group Facility Agreement), between The MAC, J.P. Morgan Australia Limited, as Australian agent and security trustee, JPMorgan Chase Bank, N.A., as U.S. agent, and the lenders party thereto, which is guaranteed by the Company and The MAC’s subsidiaries. We currently have 11 lenders in The MAC Group Facility Agreement with commitments ranging from A$14 million to A$35 million. The maturity date of The MAC Group Facility Agreement is December 10, 2015. The MAC Group Facility Agreement replaced The MAC’s previous A$150 million revolving loan facility. As of September 30, 2013, we had no borrowings outstanding under The MAC Group Facility Agreement.
5 1/8% Notes. On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Notes through a private placement to qualified institutional buyers.
The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.
On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 5 1/8% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 5 1/8% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The 5 1/8% Notes Indenture contains customary events of default. As of September 30, 2013, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.
6 1/2% Notes. On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% Notes through a private placement to qualified institutional buyers.
The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our Guarantors, bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Note offering in June 2011 to repay borrowings under its U.S. and Canadian credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.
On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the 6 1/2% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 1/2% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 6 1/2% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The 6 1/2% Notes Indenture contains customary events of default. As of September 30, 2013, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.
Our total debt represented 27.1% of our combined total debt and stockholders’ equity at September 30, 2013 compared to 34.7% at December 31, 2012 and 33.2% at September 30, 2012.
Critical Accounting Policies
For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2012 Form 10-K. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. There have been no material changes to the judgments, assumptions and estimates, upon which our critical accounting estimates are based.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates.
Interest Rate Risk
We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2013, we had no floating-rate obligations outstanding under our credit facilities.
Foreign Currency Exchange Rate Risk
Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S. (primarily in our offshore products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the nine months ended September 30, 2013, our reported foreign exchange losses were $0.8 million and are included in “Other operating (income) expense” in the Consolidated Statements of Income. Excluding intercompany balances, our Canadian dollar and Australian dollar functional currency net assets total approximately C$926 million and A$941 million, respectively, at September 30, 2013. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into foreign exchange agreements with financial institutions. As of September 30, 2013 and December 31, 2012, we had outstanding foreign currency forward purchase contracts with notional amounts of $7.4 million and $12.4 million, respectively, hedging expected cash flows denominated in Euros. We have recorded other comprehensive losses of $0.1 million in the nine months ended September 30, 2013 as a result of this contract.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2013 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
During the three months ended September 30, 2013, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors, which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.
PART II -- OTHER INFORMATION
ITEM 1. Legal Proceedings
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
ITEM 1A. Risk Factors
“Item 1A. Risk Factors” of our 2012 Form 10-K includes a detailed discussion of our risk factors. The risks described in this Quarterly Report on Form 10-Q and our 2012 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes to our risk factors as set forth in our 2012 Form 10-K except for the additional risk factors below:
The proposed spin-off of our accommodations business is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.
We expect that the spin-off can be executed by the summer of 2014. Our ability to timely effect the spin-off is subject to several conditions, including among other things, market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, completion of a review by the Commission of a Form 10 to be filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our board of directors. We cannot assure that we will be able to complete the spin-off in a timely fashion, if at all. For these and other reasons, the spin-off may not be completed on the terms or timeline contemplated. Further, if the spin-off is completed, it may not achieve the intended results. Any such delays or difficulties could adversely affect our business, results of operations or financial condition.
We may be required to refinance our debt in connection with the contemplated spin-off of our accommodations business.
On July 30, 2013, we announced that our board of directors has approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to our shareholders. In connection with the spin-off, we will be required to refinance all or a portion of our credit facilities and outstanding 5 1/8% Notes and 6 ½% Notes unless we obtain the consent of our lenders under our credit facilities and the holders of the notes. If we are required to refinance our debt, we may be required to pay significant redemption premiums, and the terms of any new indebtedness may not be as favorable as our current debt. In addition, if refinancing opportunities are not available to us, we may be required to delay the consummation of the spin-off of our accommodations business.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Period
Total Number of Shares Purchased
Average Price Paid per Share
as Part of Publicly Announced Program
Approximate
Dollar Value of Shares That May Yet Be Purchased Under the Program (1)
July 1, 2013 –
July 31, 2013
469(2)
$93.98(3)
--
$ 183,269,354
August 1, 2013 –
115,511(4)
$90.18(5)
115,379
$ 172,865,339
September 1, 2013 -
4,015(2)
$95.28(6)
$ 472,865,339
119,995
$90.36
(1)
On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization, which was set to expire on September 1, 2012. On September 6, 2013, we announced an increase in the program from $200,000,000 to $500,000,000. The current share repurchase program expires on September 1, 2014.
(2)
Shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.
(3)
The price paid per share was based on the weighted average closing price of our Company’s common stock on July 2, 2013, which represents the date the restrictions lapsed on such shares.
(4)
Includes 132 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.
(5)
The price paid per share was based on the closing price of our Company’s common stock on August 13, 2013, which represents the date the restrictions lapsed on such shares, and on the weighted average closing price of our Company’s common stock on the dates in which we repurchased shares under our common stock repurchase program.
(6)
The price paid per share was based on the weighted average closing price of our Company’s common stock on September 6, 2013, which represents the date the restrictions lapsed on such shares.
ITEM 6. Exhibits
(a)
INDEX OF EXHIBITS
Exhibit No.
Description
—
Stock Purchase Agreement by and among Marubeni-Itochu Tubulars America Inc., Sooner, Inc. and Oil States International, Inc. dated September 5, 2013 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 6, 2013 (File No. 001-16337)).
3.1
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
3.2
Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).
3.3
Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
12.1*
Computation of Ratio of Earnings to Fixed Charges.
Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document
---------
* Filed herewith.
** Management contracts or compensatory plans or arrangements.
*** Furnished herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: November 1, 2013
By /s/ BRADLEY J. DODSON
Bradley J. Dodson
Senior Vice President, Chief Financial Officer and
Treasurer (Duly Authorized Officer and Principal Financial Officer)
By /s/ ROBERT W. HAMPTON
Robert W. Hampton
Senior Vice President -- Accounting and
Secretary (Duly Authorized Officer and Chief Accounting Officer)
Exhibit Index
2.1
46