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 June 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)
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 55,153,849 shares of common stock, par value $0.01, outstanding and 3,859,739 shares of treasury stock as of July 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 Six Month Periods Ended June 30, 2013 and 2012
Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Six Month Periods Ended June 30, 2013 and 2012
Consolidated Balance Sheets – June 30, 2013 (unaudited) and December 31, 2012
5
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012
Notes to Unaudited Condensed Consolidated Financial Statements
7 – 24
Cautionary Statement Regarding Forward-Looking Statements
25
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
25 – 38
Item 3. Quantitative and Qualitative Disclosures About Market Risk
38
Item 4. Controls and Procedures
39
Part II -- OTHER INFORMATION
Item 1. Legal Proceedings
Item 1A. Risk Factors
40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
41
(a) Index of Exhibits
Signature Page
42
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
JUNE 30,
SIX MONTHS ENDED
2013
2012
Revenues
Costs and expenses:
Cost of sales and services
Selling, general and administrative expenses
Depreciation and amortization expense
Other operating (income) expense
Operating income
Interest expense, net of capitalized interest
Interest income
Equity in earnings (losses) of unconsolidated affiliates
Other income
Income before income taxes
Income tax provision
Net income
Less: Net income attributable to noncontrolling interest
Net income attributable to Oil States International, Inc.
Net income per share attributable to Oil States International, Inc. common stockholders:
Basic
Diluted
Weighted average number of common shares outstanding:
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 gain (loss) on forward contracts, net of tax
Total other comprehensive income (loss)
Comprehensive income (loss)
Comprehensive income attributable to noncontrolling interest
Comprehensive income (loss) attributable to Oil States International, Inc.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories, net
Prepaid expenses and other current assets
Total current assets
Property, plant, and equipment, net
Goodwill, net
Other intangible assets, net
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
Other current liabilities
Total current liabilities
Long-term debt and capitalized leases
Deferred income taxes
Other noncurrent liabilities
Total liabilities
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 59,008,138 shares and 58,488,299 shares issued, respectively, and 55,148,868 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, 3,859,270 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
SIX MONTHS
ENDED JUNE 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
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 disposition of property, plant and equipment
Net cash flows used in investing activities
Cash flows from financing activities:
Revolving credit borrowings and (repayments), net
Term loan repayments
Debt and capital lease repayments
Issuance of common stock from share-based payment arrangements
Purchase of treasury stock
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 from continuing operations
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
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.
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.
In February 2013, the FASB issued a new accounting standard related to the reporting of amounts reclassified out of accumulated other comprehensive income (OCI). Under this standard, an entity is required to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated OCI by the respective line items of net income, but only if the amount reclassified is required to be reclassified in its entirety in the same reporting period. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. This standard does not change the current requirements for reporting net income or other comprehensive income in the financial statements and was effective for interim and annual periods beginning on or after December 15, 2012. We adopted this standard in the Quarterly Report on Form 10-Q for the three month period ended March 31, 2013, and the adoption of this standard did not have a material effect on our consolidated financial statements.
(Continued)
3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
Additional information regarding selected balance sheet accounts at June 30, 2013 and December 31, 2012 is presented below (in thousands):
Accounts receivable, net:
Trade
Unbilled revenue
Other
Total accounts receivable
Allowance for doubtful accounts
Inventories, net:
Tubular goods
Other finished goods and purchased products
Work in process
Raw materials
Total inventories
Allowance for excess, damaged, remnant 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 $62.9 million at June 30, 2013, a net change of $170.0 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. $0.95 at June 30, 2013 compared to U.S. $1.01 at December 31, 2012, a decrease of 6%. The Australian dollar was valued at an exchange rate of U.S. $0.92 at June 30, 2013 compared to U.S. $1.04 at December 31, 2012, a decrease of 12%. Excluding intercompany balances, our Canadian dollar and Australian dollar functional currency net assets total approximately C$880 million and A$926 million, respectively, at June 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):
Basic earnings per share:
Weighted average number of shares outstanding
Basic earnings per share
Diluted earnings per share:
Effect of dilutive securities:
Options on common stock
2 3/8% Contingent Convertible Senior Subordinated Notes
Restricted stock awards and other
Total shares and dilutive securities
Diluted earnings per share
Our calculation of diluted earnings per share for the three and six months ended June 30, 2013 excludes 392,416 shares and 392,660 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 six months ended June 30, 2012 excludes 625,565 shares and 484,533 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.
See Note 7 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 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, resulting in a $3.0 million, or $0.05 per diluted share after tax, charge to other operating expense. The contingent liability increased to $20.0 million during the second quarter due to favorable developments related to a patent application by Tempress. It is now estimated that the patent will be issued in a form satisfactory to the Company. The Company’s total escrowed deposits of $25.3 million include this contingent consideration and other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our June 30, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for contingent consideration and escrowed amounts expected to be paid to the seller also totaled $25.3 million at June 30, 2013 and are classified as “Other current liabilities” in our 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. Subject to customary post-closing adjustments, 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 six month period ended June 30, 2013 are as follows (in thousands):
Well Site Services
Completion Services
Drilling Services
Subtotal
Accommodations
Offshore Products
Tubular Services
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 June 30, 2013
7. DEBT
As of June 30, 2013 and December 31, 2012, long-term debt consisted of the following (in thousands):
June 30, 2013
December 31, 2012
U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million; no borrowings outstanding during the six month period ended June 30, 2013
U.S. term loan, which matures December 10, 2015, of $200 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 2.2% for the six month period ended June 30, 2013
Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million; no borrowings outstanding during the six month period ended June 30, 2013
Canadian term loan, which matures December 10, 2015, of $100 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 3.3% for the six month period ended June 30, 2013
Australian revolving credit facility, which matures December 10, 2015, with available commitments up to AUD$300 million and with a weighted average interest rate of 5.1% for the six month period ended June 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
2019
2020
2021 and thereafter
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
2015
2016
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
June 30,
Six months ended
Interest expense
As of June 30, 2013, the Company had approximately $225.9 million of cash and cash equivalents and $713.0 million of the Company’s U.S. and Canadian credit facilities available for future financing needs. The Company also had availability totaling AUD$300 million under its Australian credit facility. As of June 30, 2013, the Company had $37.0 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 $0.5 million, respectively, for the three and six months ended June 30, 2013 and $1.2 million and $2.5 million, respectively, for the same periods in 2012.
8. 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
Value
Fair
5 1/8% Notes
Principal amount due 2023
6 1/2% Notes
Principal amount due 2019
As of June 30, 2013, the carrying value of the Company's debt outstanding under its credit facilities was estimated to be at fair value.
9. 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 – June 30, 2013
10. STOCK BASED COMPENSATION
During the first six months of 2013, we granted restricted stock awards totaling 308,539 shares valued at a total of $25.0 million. Of the restricted stock awards granted in the first six 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 and 3,500 awards vest 100% in February 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 six months ended June 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 six months ended June 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 recognized in the six month periods ended June 30, 2013 and 2012 totaled $13.1 million and $9.2 million, or $0.17 and $0.12 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the three month periods ended June 30, 2013 and 2012 totaled $6.8 million and $4.8 million, or $0.09 and $0.07 per diluted share after tax, respectively. The total fair value of restricted stock awards that vested during the six months ended June 30, 2013 and 2012 was $14.7 million and $15.8 million, respectively. At June 30, 2013, $55.0 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.
11. 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 six months ended June 30, 2013 totaled $31.7 million, or 29.2% of pretax income, and $71.1 million, or 28.4% of pretax income, respectively, compared to income tax expense of $44.6 million, or 28.6% of pretax income, and $97.9 million, or 28.4% of pretax income, respectively, for the three and six months ended June 30, 2012. The higher effective tax rate for the three months ended June 30, 2013 is primarily due to a slightly higher foreign effective tax rate. The Company’s effective tax rates are lower than U.S. statutory rates because of lower foreign tax rates.
12. 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, offshore products and tubular services. 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 each of the three and six months ended June 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 June 30, 2013
Well site services –
Completion services
Drilling services
Total well site services
Offshore products
Tubular services
Corporate and eliminations
Three months ended June 30, 2012
Six months ended June 30, 2013
Six months ended June 30, 2012
13. 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.
14. 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 the first half of 2014.
15. 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 six month periods ended June 30, 2013 and 2012, condensed consolidating balance sheets as of June 30, 2013 and December 31, 2012 and the statements of cash flows for each of the six months ended June 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, L.L.C., Oil States Energy Services L.L.C., Oil States Energy Services Holding, Inc., Oil States Energy Services International Holding, L.L.C., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, L.L.C., PTI Group USA L.L.C., PTI Mars Holdco 1, L.L.C., Sooner Inc., Sooner Pipe, L.L.C., Sooner Holding Company 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.
We have corrected the presentation of our condensed consolidating statement of cash flows for the six month period ended June 30, 2012 to properly reflect equity contributions by the Parent Guarantor to Guarantor Subsidiaries of $14 million and by Guarantor Subsidiaries to Non-Guarantor Subsidiaries of $5.8 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 June 30, 2013
Oil States
Consolidated Oil
International,
Subsidiaries
States
Inc. (Parent/
Guarantor
(Non-
Consolidating
Guarantor)
Guarantors)
Adjustments
Inc.
(In thousands)
REVENUES
Operating revenues
Intercompany revenues
Total revenues
OPERATING EXPENSES
Intercompany cost of sales and services
Other comprehensive income:
Unrealized gain on forward contracts
Total other comprehensive income
Comprehensive income
Comprehensive income attributable to Oil States International, Inc.
Three Months Ended June 30, 2012
(Non-Guarantors)
Consolidated Oil States
International, Inc.
Other operating (income)expense
Six Months Ended June 30, 2013
Six Months Ended June 30, 2012
International, Inc. (Parent/
Consolidating Balance Sheets
GuarantorSubsidiaries
Consolidated
Property, plant and equipment, net
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
Proceeds from sale of equipment
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, well site services and tubular services business segments. In our accommodations segment, we support both the oil and gas and mining industries. 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 spend capital on 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 have been volatile due to global economic movements and uncertainties including regional take-away pipeline capacity. This volatility continued in the first half of 2013 with fluctuations in crude oil prices in response to changing market sentiment regarding the outlook for growth in the economies of the U.S. and China, decreased crude oil production by Organization of the Petroleum Exporting Countries (OPEC) member countries, heightened geopolitical risks in the Middle East and North Africa, increased oil production in the U.S. and delays in the start-up of the Seaway pipeline expansion which is intended to reduce surplus crude oil supplies in the U.S. Midwest. 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 $94 per barrel in the first half of 2013, finishing the first half of 2013 at $96 per barrel. The price of Intercontinental Exchange (ICE) Brent crude decreased from an average price of $110 per barrel in the fourth quarter of 2012 to $107 per barrel in the first half of 2013, finishing the first half of 2013 at $102 per barrel. As of July 30, 2013, WTI crude traded at approximately $103 per barrel while ICE Brent crude traded at approximately $107 per barrel. In Canada, Western Canadian Select (WCS) crude, which is a benchmark price affecting what many of our oil sands accommodations customers receive for production, traded at a discount to WTI crude that narrowed substantially from above $40 per barrel in early January 2013, when limited pipeline capacity and Canadian and U.S. refinery maintenance work caused increased inventory levels within the Alberta market, to below $15 per barrel by the end of the second quarter of 2013 once the pipeline issues were resolved and refinery maintenance decreased. As of July 30, 2013, WCS crude traded at a $21 discount to WTI crude.
Given the historical volatility of WTI crude prices, there remains a risk that prices could deteriorate going forward due to potentially slowing growth rates in China, fiscal and financial uncertainty in 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 and 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., we could see continued and/or additional increases in WTI crude prices 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 have an incentive to delay increased investments in oil sands production.
Prices for natural gas in the United States improved during the first half of 2013, largely due to above average storage withdrawals in response to colder than normal 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. However, 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, specifically onshore shale production, resulting from the broad application of horizontal drilling and hydraulic fracturing techniques. Natural gas prices traded at approximately $3.40 per Mcf as of July 30, 2013. In addition, a considerable amount of natural gas is being derived as a by-product of drilling crude oil and natural gas liquids-oriented wells in liquids-rich onshore basins. As a result, the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 370 rigs as of July 26, 2013, a 14-year low. Natural gas inventories in the U.S. have declined from 60% above the 5-year average as of the end of the second quarter of 2012 to 10% below the 5-year average as of the end of the second 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)
6/30/2013
3/31/2013
12/31/2012
9/30/2012
6/30/2012
3/31/2012
12/31/2011
9/30/2011
6/30/2011
3/31/2011
12/31/2010
__________
(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 half of 2013 compared to the first half of 2012. Met coal prices have decreased materially from over $200/metric ton at the beginning of 2012 to approximately $135/metric ton at the end of the first half of 2013. Depressed met coal prices have led to cost control measures being implemented by our customers, some coal mine closures and delays in the start-up of new coal mining projects in Australia.
Various oil and gas industry analysts have projected increased 2013 global exploration and production expenditures compared to 2012. North American capital spending plans are likely to be lower year-over-year and are expected to be focused in oil-related onshore shale areas while international exploration and production budgets are expected to increase and primarily be spent on offshore projects.
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 and tubular services segments 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 semi-permanent 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. The narrowing of the WCS crude to WTI crude discount gap in the second quarter of 2013 could provide support for the economics of new oil sands projects as well as the ongoing expansions and maintenance of existing oil sands projects. 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 and Hunter basins 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 in 2013 due to the material decline in met coal prices during the first half 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 development of infrastructure 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 half of 2013. As a result, backlog in our offshore products segment remained strong, totaling $561 million as of June 30, 2013 compared to $561 million at December 31, 2012 and $564 million at March 31, 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 techniques, 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 July 26, 2013 totals approximately 1,400 rigs, comprising approximately 79% 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.
Through our tubular services segment, we distribute a broad range of casing and tubing used in the drilling and completion of oil and natural gas wells primarily in North America. Accordingly, sales and gross margins in our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, movements in global steel input prices and the overall industry level of oil country tubular goods (OCTG) manufacturing capacity, inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. Our tubular services business segment has historically been our most cyclical business segment. OCTG prices fell throughout 2012, and pricing pressures continued throughout the first half of 2013 due to strong import levels and increasing domestic capacity and production. Petitions were filed by certain pipe manufacturers in July 2013 with the U.S. Department of Commerce and the U.S. International Trade Commission to seek antidumping and countervailing duties against nine countries importing OCTG into the United States. The potential imposition of trade sanctions on OCTG imports could impact the future level of OCTG imports from the sanctioned countries and, thus, the supply and pricing of OCTG in the U.S.
We have a diversified product and service offering, which has exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services, 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
Three Months Ended
Six Months Ended
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 six months ended June 30, 2013 decreased by 258 rigs, or 10.9%, compared to the six months ended June 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 has derived 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 half of 2013 compared to U.S. $0.99 for the first half of 2012, a decrease of 1%. The Australian dollar was valued at an average exchange rate of U.S. $1.02 for the first half of 2013 compared to U.S. $1.03 for the first half of 2012, a decrease of 1%. Importantly, exchange rates had weakened further at the end of the second quarter of 2013, standing at $0.95 Canadian dollars and $0.92 Australian dollars per U.S. dollar, respectively, at June 30, 2013. This weakening of the Canadian and Australian dollars had 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.
Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby impacting the pricing and margins of our tubular services segment. During 2011 and 2012, OCTG marketplace supply and demand became more balanced compared to the previous two years as increased supplies of OCTG met the increased demand created by expanded drilling activity. Throughout 2012 and into the first half of 2013, imports of OCTG have increased, particularly goods imported from Canada and South Korea followed by India, Mexico and Japan. Additionally, domestic OCTG mill capacity increased in 2012. These increases in supply have primarily been in response to increased well complexity and offshore drilling. The OCTG Situation Report suggests that industry OCTG inventory levels increased throughout 2012 but decreased slightly during the first half 2013, and currently stand at four to five months' supply. Ample industry inventory on the ground along with increasing imports and domestic production put downward pressure on OCTG prices throughout 2012 and the first half of 2013. Petitions were filed by certain pipe manufacturers in July 2013 with the U.S. Department of Commerce and the U.S. International Trade Commission to seek antidumping and countervailing duties against nine countries importing OCTG into the United States. The potential imposition of trade sanctions on OCTG imports could impact the future level of OCTG imports from the sanctioned countries and, thus, the supply and pricing of OCTG in the U.S.
We remain focused on working capital management and generating returns on invested capital in our tubular services segment and will continue to monitor industry inventory levels, forecasted drilling and completion activity and OCTG prices.
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 higher than in 2012, the drilling rig count in the first half 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 six months ended June 30, 2013, we have spent $240.4 million on capital expenditures and we expect that our capital expenditures for the entire year will total approximately $550 million to $600 million compared to 2012 capital expenditures of $488 million. 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 three-fifths of our total expected 2013 capital expenditures will be spent in our accommodations segment. 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 the first half of 2014.
Consolidated Results of Operations (in millions)
Variance
2013 vs. 2012
Well site services -
Product costs; service and other costs
(“Cost of sales and service”)
Gross margin
20.6
Gross margin as a percentage of revenues
THREE MONTHS ENDED JUNE 30, 2013 COMPARED TO THREE MONTHS ENDED JUNE 30, 2012
We reported net income attributable to the Company for the quarter ended June 30, 2013 of $76.5 million, or $1.38 per diluted share, including a charge of $3.0 million, or $0.05 per diluted share, from an increase in a contingent liability in our completion services business. This expense is included in “Other operating (income) expense” in the Consolidated Statements of Income and resulted from an increase in the estimated fair value of contingent consideration due to favorable developments in a patent. In addition, the Company incurred $1.9 million, or $0.02 per diluted share after tax, of strategic transaction costs in the second quarter of 2013 included in “Other operating (income) expense.” These results compare to net income attributable to the Company of $111.2 million, or $2.01 per diluted share, including a pre-tax gain of $2.5 million, or $0.03 per diluted share after tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012.
Revenues. Consolidated revenues decreased $50.6 million, or 5%, in the second quarter of 2013 compared to the second quarter of 2012.
Our well site services segment revenues increased $9.9 million, or 6%, in the second quarter of 2013 compared to the second 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 $17.1 million, or 14%, in the second quarter of 2013 compared to the second quarter of 2012 as a favorable mix of demand for the Company’s proprietary tools, particularly in the Bakken and Marcellus regions, led to a 17% increase in revenue per ticket (excluding the contribution from the acquisition of Tempress completed in the fourth quarter of 2012.) The number of service tickets issued in the second quarter of 2013 decreased 5% compared to the second quarter of 2012 (also excluding the contribution from the acquisition of Tempress) due primarily to reduced activity, particularly in the Haynesville, Barnett, Eagle Ford and Permian basin regions, resulting from reduced customer spending in dry gas markets, partially offset by increased activity in the Bakken region. In addition, our completion services business reduced a revenue accrual for its foreign operations by $1.6 million, or $0.02 per diluted share after tax, during the second quarter of 2013. Our drilling services revenues decreased $7.2 million, or 14%, in the second quarter of 2013 compared to the second 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 second quarter of 2012 to an average of approximately 77% for the second quarter of 2013.
Our accommodations segment reported revenues in the second quarter of 2013 that were $16.8 million, or 6%, lower than the second quarter of 2012. This decrease was primarily due to a 12% decrease in revenue per available room (RevPAR) related to lower contracted rates in Canada and lower occupancy levels in Australia, decreased third-party manufacturing revenues and lower utilization for our U.S. accommodations assets, partially offset by a 12% increase in average available rooms in 2013 compared to 2012. Utilization for our U.S. accommodations was negatively impacted by poor weather conditions in the Bakken region, lower rig count and increased competition.
Our offshore products segment revenues increased $12.8 million, or 7%, in the second quarter of 2013 compared to the second quarter of 2012. This increase was primarily the result of contributions from the acquisition of Piper, which was acquired in July 2012, along with increased drilling and subsea product sales.
Our tubular services segment revenues decreased $56.5 million, or 12%, in the second quarter of 2013 compared to the second quarter of 2012. This decrease was primarily due to a 12% decrease in realized revenues per ton shipped in the second quarter of 2013 compared to the second quarter of 2012 due to sales mix and reduced mill pricing. We also reported a 4% decrease in tons shipped from 230,000 in the second quarter of 2012 to 221,100 in the second quarter of 2013 related to the 11% year-over-year decrease in U.S. drilling and completion activity.
Cost of Sales and Service. Our consolidated cost of sales decreased $35.9 million, or 4%, in the second quarter of 2013 compared to the second quarter of 2012 as a result of decreased cost of sales at our tubular services segment of $48.1 million, or 11%, partially offset by increased cost of sales at our offshore products and well site services segments of $8.2 million, or 6%, and $4.1 million, or 4%, respectively. Our consolidated gross margin as a percentage of revenues was 25% in both the second quarter of 2013 and 2012.
Our well site services segment cost of sales increased $4.1 million, or 4%, in the second quarter of 2013 compared to the second quarter of 2012 as a result of a $10.8 million, or 14%, increase in completion services cost of sales, partially offset by a $6.7 million, or 18%, decrease in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues increased modestly from 35% in the second quarter of 2012 to 36% in the second quarter of 2013. Our completion services segment gross margin as a percentage of revenues was 37% in both the second quarter of 2013 and 2012. Our drilling services gross margin as a percentage of revenues increased from 29% in the second quarter of 2012 to 33% in the second quarter of 2013 primarily due to decreased trucking and repairs and maintenance costs.
Our accommodations segment cost of sales decreased $0.1 million, or less than 1%, in the second quarter of 2013 compared to the second quarter of 2012. Our accommodations segment gross margin as a percentage of revenues decreased from 49% in the second quarter of 2012 to 46% in the second quarter of 2013 primarily due to lower contracted rates in Canada.
Our offshore products segment cost of sales increased $8.2 million, or 6%, in the second quarter of 2013 compared to the second quarter of 2012 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 28% in both the second quarter of 2013 and 2012.
Our tubular services segment cost of sales decreased by $48.1 million, or 11%, in the second quarter of 2013 compared to the second quarter of 2012 primarily as a result of lower priced OCTG inventory being sold and the decrease in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 6.3% in the second quarter of 2012 to 5.1% in the second quarter of 2013 primarily due to lower industry pricing and product mix.
Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expense increased $8.3 million, or 17%, in the second quarter of 2013 compared to the second quarter of 2012 primarily due to increased employee-related costs, SG&A expense associated with the inclusion of Piper, which was acquired in July 2012, and increased bad debt expense.
Depreciation and Amortization. Depreciation and amortization expense increased $14.4 million, or 27%, in the second quarter of 2013 compared to the second 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 $42.7 million, or 25%, in the second quarter of 2013 compared to the second quarter of 2012 primarily as a result of a decrease in operating income from our accommodations segment of $28.3 million, or 34%, primarily due to the lower contracted rates in Canada, lower occupancy levels in Australia, lower utilization for our U.S. accommodations assets and the increased depreciation expense on accommodations assets, partially offset by the increase in average available rooms in the second quarter of 2013 compared to the second quarter of 2012. In addition, operating income from our tubular services segment decreased $8.2 million, or 34%, in the second quarter of 2013 compared to the second quarter of 2012 primarily due to the lower industry pricing and product mix. The Company also incurred $1.9 million of strategic transaction costs in the second quarter of 2013 included in “Other operating (income) expense.”
Interest Expense and Interest Income. Net interest expense increased by $1.3 million, or 7%, in the second quarter of 2013 compared to the second 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 2 3/8% Contingent Convertible Senior Subordinated Notes due 2025 (2 3/8% Notes) due to their conversion in July 2012. The weighted average interest rate on the Company’s total outstanding debt was 5.3% in the second quarter of 2013 compared to 5.5% in the second quarter of 2012. Interest income increased as a result of increased cash balances in interest bearing accounts.
Income Tax Expense. Our income tax provision for the three months ended June 30, 2013 totaled $31.7 million, or 29.2% of pretax income, compared to income tax expense of $44.6 million, or 28.6% of pretax income, for the three months ended June 30, 2012. The higher effective tax rate for the three months ended June 30, 2013 is primarily due to a slightly higher foreign effective tax rate. The Company’s effective tax rates are lower than U.S. statutory rates because of lower foreign tax rates.
Other Comprehensive Loss. Other comprehensive loss increased $119.6 million in the second quarter of 2013 compared to the second quarter of 2012 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 second quarter of 2013 compared to a 2% decrease in the second quarter of 2012. The Australian dollar exchange rate compared to the U.S. dollar decreased 12% in the second quarter of 2013 compared to a 1% decrease in the second quarter of 2012.
SIX MONTHS ENDED JUNE 30, 2013 COMPARED TO SIX MONTHS ENDED JUNE 30, 2012
We reported net income attributable to the Company for the six months ended June 30, 2013 of $178.7 million, or $3.22 per diluted share, including a gain of $4.0 million 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 $0.05 per diluted share, from an increase in a contingent liability in our completion services business. These two items are included in “Other operating (income) expense” in the Consolidated Statements of Income and resulted from changes in the estimated fair value of contingent consideration. These results compare to net income attributable to the Company of $246.3 million, or $4.45 per diluted share, reported for the six months ended June 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 in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012.
Revenues. Consolidated revenues decreased $80.1 million, or 4%, in the first half of 2013 compared to the first half of 2012.
Our well site services segment revenues increased $4.4 million, or 1%, in the first half of 2013 compared to the first half of 2012 due to an increase in completion services revenues, partially offset by a decrease in drilling services revenues. Our completion services revenues increased $18.9 million, or 7%, in the first half of 2013 compared to the first half of 2012 as a favorable mix of demand for the Company’s proprietary tools, particularly in the Bakken and Marcellus regions, led to a 11% increase in revenue per ticket (excluding the contribution from the acquisition of Tempress completed in the fourth quarter of 2012.) The number of service tickets issued in the first half of 2013 decreased 6% compared to the first half of 2012 (also excluding the contribution from the acquisition of Tempress) due primarily to reduced activity, particularly in the Haynesville, Barnett, Eagle Ford, Permian basin and Marcellus 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 negatively impacted by a revenue accrual adjustment for international operations which reduced revenues in the first half of 2013 by $1.4 million. Our drilling services revenues decreased $14.5 million, or 15%, in the first half of 2013 compared to the first half of 2012 primarily as a result of decreased utilization of our rigs, particularly in the Permian basin, from an average of approximately 90% for the first half of 2012 to an average of approximately 75% for the first half of 2013.
Our accommodations segment reported revenues in the first half of 2013 that were $21.9 million, or 4%, lower than the first half of 2012. This decrease was primarily due to a 7% decrease in RevPAR related to lower contracted rates in Canada and lower occupancy levels in Australia, a favorable contract settlement reported in our U.S. accommodations business of $18.3 million in the first quarter of 2012, decreased third-party manufacturing revenues in 2013 and lower utilization in 2013 for our U.S. accommodations assets, partially offset by a 13% 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.
Our offshore products segment revenues increased $28.3 million, or 7%, in the first half of 2013 compared to the first half of 2012. This increase was primarily the result of contributions from the acquisition of Piper, which was acquired in July 2012, along with increased drilling and subsea product sales.
Our tubular services segment revenues decreased $90.9 million, or 10%, in the first half of 2013 compared to the first half of 2012. This decrease was primarily due to a 9% decrease in realized revenues per ton shipped in the first half of 2013 compared to the first half of 2012 due to sales mix and reduced mill pricing. We also reported a 1% decrease in tons shipped from 435,400 in the first half of 2012 to 429,000 in the first half of 2013 related to the 11% year-over-year decrease in U.S. drilling and completion activity.
Cost of Sales and Service. Our consolidated cost of sales decreased $39.3 million, or 2%, in the first half of 2013 compared to the first half of 2012 as a result of decreased cost of sales at our tubular services of $75.5 million, or 9%, partially offset by increased cost of sales at our offshore products and accommodations segments of $23.1 million, or 8%, and $10.9 million, or 4%, respectively. Our consolidated gross margin as a percentage of revenues decreased from 26% in the first half of 2012 to 25% in the first half of 2013 primarily due to the favorable contract settlement reported in our U.S. accommodations business in 2012 and lower margins realized in our tubular services segment and Canadian accommodations business.
Our well site services segment cost of sales increased $2.2 million, or 1%, in the first half of 2013 compared to the first half of 2012 as a result of a $13.4 million, or 8%, increase in completion services cost of sales, partially offset by an $11.2 million, or 16%, decrease in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues was 35% in both the first half of 2013 and 2012. Our completion services segment gross margin as a percentage of revenues was 37% in both the first half of 2013 and 2012. Our drilling services gross margin as a percentage of revenues increased from 29% in the first half of 2012 to 30% in the first half of 2013 primarily due to decreased repairs and maintenance costs and costs of trouble wells, partially offset by decreased rig utilization and cost absorption.
Our accommodations segment cost of sales increased $10.9 million, or 4%, in the first half of 2013 compared to the first half 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 52% in the first half of 2012 to 48% in the first half of 2013 primarily due to the favorable contract settlement reported in our U.S. accommodations business in the first half of 2012. Excluding the favorable contract settlement, our accommodations segment gross margin as a percentage of revenues would have been 50% in the first half of 2012. The decrease in gross margin as a percentage of revenues from the adjusted 50% in the first half of 2012 to 48% in the first half of 2013 was primarily due to lower contracted rates in Canada.
Our offshore products segment cost of sales increased $23.1 million, or 8%, in the first half of 2013 compared to the first half of 2012 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 27% in both the first half of 2013 and 2012.
Our tubular services segment cost of sales decreased by $75.5 million, or 9%, in the first half of 2013 compared to the first half of 2012 primarily as a result of lower priced OCTG inventory being sold. Our tubular services segment gross margin as a percentage of revenues decreased from 6.3% in the first half of 2012 to 5.1% in the first half of 2013 primarily due to lower industry pricing and product mix.
Selling, General and Administrative Expenses. SG&A expense increased $15.5 million, or 16%, in the first half of 2013 compared to the first half 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 bad debt expense and increased professional fees.
Depreciation and Amortization. Depreciation and amortization expense increased $30.7 million, or 29%, in the first half of 2013 compared to the first half 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 $85.9 million, or 23%, in the first half of 2013 compared to the first half of 2012 primarily as a result of a decrease in operating income from our accommodations segment of $52.4 million, or 26%, 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 and the gain of $4.0 million from the reversal of a liability associated with contingent acquisition consideration in our U.S. accommodations business. In addition, operating income from our tubular services segment decreased $15.6 million, or 34%, primarily due to the lower industry pricing and product mix. Operating income from our well site services segment decreased $11.2 million, or 14%, primarily due to the increased depreciation expense on completion services assets, decreased rig utilization in our drilling services business, the $3.0 million charge in the second quarter of 2013 from an increased fair value of a liability associated with contingent acquisition consideration in our completion services business, partially offset by contributions from the acquisition of Tempress, which was acquired in the fourth quarter of 2012.
Interest Expense and Interest Income. Net interest expense increased by $3.2 million, or 9%, in the first half of 2013 compared to the first half 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 5.3% in the first half of 2013 compared to 5.5% in the first half of 2012. Interest income increased as a result of increased cash balances in interest bearing accounts.
Income Tax Expense. Our income tax provision for the six months ended June 30, 2013 totaled $71.1 million, or 28.4% of pretax income, compared to income tax expense of $97.9 million, or 28.4% of pretax income, for the six months ended June 30, 2012. The effective tax rates for the six months ended June 30, 2013 and 2012 are comparable and are lower than U.S. statutory rates because of lower foreign tax rates.
Other Comprehensive Loss. Other comprehensive loss increased $166.9 million in the first half of 2013 compared to the first half of 2012 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 6% in the first half of 2013 compared to a less than 1% decrease in the second quarter of 2012. The Australian dollar exchange rate compared to the U.S. dollar decreased 12% in the first half of 2013 compared to a less than 1% decrease in the second quarter 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 totaling $359.0 million was provided by operations during the first six months of 2013 compared to cash totaling $251.0 million provided by operations during the first six months of 2012. During the first six months of 2013, $31.8 million was provided from net working capital reductions, primarily due to decreases in receivables. During the first six months of 2012, $111.0 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services business and increases in receivables.
Cash was used in investing activities during the six months ended June 30, 2013 and 2012 in the amounts of $238.0 million and $196.4 million, respectively. Capital expenditures totaled $240.4 million and $200.0 million during the six months ended June 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.
For the six months ended June 30, 2013, we have spent $240.4 million on capital expenditures, and we expect our capital expenditures for the entire year will total approximately $550 million to $600 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 three-fifths 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, internally generated funds and borrowings under our U.S., Canadian and Australian credit facilities. 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 June 30, 2013, we had cash totaling $161.2 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.
Net cash of $130.6 million was used in financing activities during the six months ended June 30, 2013, primarily as a result of the repayment of all amounts outstanding under our Canadian term loan and repayments under our Australian credit facility. Net cash of $8.5 million was used in financing activities during the six months ended June 30, 2012, primarily as a result of repayments on our U.S. and Canadian term loans, partially offset by proceeds from the issuance of common stock from share-based payment arrangements.
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. 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 August 23, 2012, the Company announced that its Board of Directors authorized $200 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which was set to expire on September 1, 2012. As of June 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 June 30, 2013, a total of $16.7 million of our stock (245,796 shares) had been repurchased under this program, leaving a total authorization of up to approximately $183.3 million remaining available under the program. During the three months ended June 30, 2013, $1.5 million of our stock (20,000 shares) was repurchased under this program.
Credit Facilities. Our current bank credit facilities include a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. 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 contain total commitments available of $1.05 billion, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $700 million (including $200 million in U.S. term loans), and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $350 million (including $100 million in Canadian term loans). We repaid the Canadian term loan balance in full during the second quarter of 2013. The maturity date of the Credit Agreement is December 10, 2015. The current principal balance of the term loans is repayable at a rate of 2.5% per quarter of the aggregate principal amount until maturity on December 10, 2015 when the remaining principal is due. We currently have 19 lenders in our Credit Agreement with commitments ranging from $25.3 million to $150 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position. As of June 30, 2013, we had $160.0 million outstanding under the term loans of the Credit Agreement and an additional $37.0 million of outstanding letters of credit, leaving $713.0 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 June 30, 2013, we were in compliance with our debt covenants and expect to continue to be in compliance during 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 half 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 AUD$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 AUD$14 million to AUD$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 AUD$150 million revolving loan facility. As of June 30, 2013, we had no borrowings outstanding under the Australian credit facility.
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 June 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 June 30, 2013, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.
Our total debt represented 31.8% of our combined total debt and stockholders’ equity at June 30, 2013 compared to 34.7% at December 31, 2012 and 34.3% at June 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 June 30, 2013, we had floating-rate obligations totaling approximately $160.0 million drawn under our credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If floating interest rates increase by 1%, our consolidated interest expense would increase by a total of approximately $1.6 million annually based on our floating debt obligations as of June 30, 2013.
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 six months ended June 30, 2013, our reported foreign exchange gains were $1.3 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$880 million and A$926 million, respectively, at June 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 June 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 income of $0.1 million in the six months ended June 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 June 30, 2013 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
During the three months ended June 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.
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)
April 1, 2013 - April 30, 2013
20,000
$74.27(2)
$ 183,269,354
May 1, 2013 - May 31, 2013
582(3)
$101.46(4)
--
June 1, 2013 - June 30, 2013
750(3)
$92.64(5)
21,332
$75.66
(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. The current share repurchase program expires on September 1, 2014.
(2)
The price paid per share was based on the weighted average closing price of our Company’s common stock on the date in which we repurchased shares under our common stock repurchase program.
(3)
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.
(4)
The price paid per share was based on the weighted average closing price of our Company’s common stock on May 15, 2013 and May 17, 2013, which represent the dates the restrictions lapsed on such shares.
(5)
The price paid per share was based on the closing price of our Company’s common stock on June 30, 2013, which represents the date the restrictions lapsed on such shares.
ITEM 5. Other Information
Disclosure under Section 13(r) of the Exchange Act
The Iran Threat Reduction and Syria Human Rights Act of 2012, signed into law by President Obama on August 10, 2012, added a new Section 13(r) to the Exchange Act, which requires us to disclose whether the Company or any of its affiliates has engaged in certain Iran-related activities during the reporting period. In the second quarter of 2013, our wholly-owned Singaporean subsidiary, Oil States (Asia) Ptd Ltd (Oil States (Asia)), received two payments in connection with a prior transaction for the sale of riser pipe and associated material to a United Arab Emirates company, for ultimate use in the South Pars Gas Field. This field is controlled and mandated by Pars Oil & Gas Co, an entity designated in December 2010 by the Office of Foreign Assets Control (OFAC) as being owned or controlled by the Government of Iran. The transaction that is the subject of this disclosure commenced at a time when Oil States (Asia) was not subject to the Iranian Transactions and Sanctions Regulations, 31 C.F.R. Part 560 (ITSR). The total value of Oil States (Asia)’s transaction was approximately $4.2 million, for which it received an estimated net profit of $0.4 million. The two payments that Oil States (Asia) received during the reporting period totaled approximately $2.2 million. Except for the receipt of these two final payments from its customer during April 2013, Oil States (Asia) completed the transaction in accordance with and during the validity period of the wind-down general license at ITSR Section 560.555, which expired on March 8, 2013. Oil States (Asia) has wound down its Iran-related business, and the Company has submitted voluntary self-disclosures to OFAC and the State Department about this transaction.
ITEM 6. Exhibits
(a) INDEX OF EXHIBITS
Exhibit No.
Description
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)).
10.1*,**
Second Amended and Restated 2001 Equity Participation Plan effective February 19, 2013.
31.1*
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.
31.2*
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.
32.1***
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.
32.2***
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: July 31, 2013
/s/ BRADLEY J. DODSON
Bradley J. Dodson
Senior Vice President, Chief Financial Officer and
Treasurer (Duly Authorized Officer and Principal Financial Officer)
/s/ ROBERT W. HAMPTON
Robert W. Hampton
Senior Vice President -- Accounting and
Secretary (Duly Authorized Officer and Chief Accounting Officer)
Exhibit Index