As filed with the Securities and Exchange Commission on September 1, 2011

Registration No. 333-      

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Form S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

 

OIL STATES INTERNATIONAL, INC.

(Exact Name of Registrant as Specified in Its Charter)

 

 

Three Allen Center, 333 Clay Street, Suite 4620

Houston, Texas 77002

(713) 652-0582

(Address, Including Zip Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

Bradley J. Dodson

Senior Vice President, Chief Financial Officer and Treasurer

Three Allen Center, 333 Clay Street, Suite 4620

Houston, Texas 77002

(713) 652-0582

(Name, Address, Including Zip Code, and Telephone Number,

Including Area Code, of Agent For Service)

 

 

 

 

Copies to:

Matthew R. Pacey

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

 

 

 

 

Approximate date of commencement of proposed sale of the securities to the public:  As soon as practicable after the effective date of this Registration Statement.

 

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  o

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

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 “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

 

Exchange Act Rule 13e-4(i) (Cross-Border Issue Tender Offer)  o

 

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  o

 

 

CALCULATION OF REGISTRATION FEE

 

 

 

Each Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

TABLE OF ADDITIONAL REGISTRANT GUARANTORS

 

 

 

 

 

 

SUBJECT TO COMPLETION, DATED SEPTEMBER 1, 2011

 

PROSPECTUS

 

 

Offer to Exchange

Up To $600,000,000 of

6.50% Senior Notes due 2019

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $600,000,000 of

6.50% Senior Notes due 2019

That Have Been Registered Under

The Securities Act of 1933

 

 

 

 

Terms of the New 6.50% Senior Notes due 2019 Offered in the Exchange Offer:

 

 

Terms of the Exchange Offer:

 

 

 

 

 

You should carefully consider the risk factors beginning on page 8 of this prospectus before participating in the exchange offer.

 

 

 

 

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. Please read “Plan of Distribution.”

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

The date of this prospectus is          , 2011

 

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its respective date.

 

TABLE OF CONTENTS

 

 

 

In this prospectus, “we,” “us,” “our,” the “Company,” and “Oil States” refer to Oil States International, Inc. and its material domestic subsidiaries, unless otherwise indicated or the context otherwise requires.

 

 

This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. Such information is available without charge to holders of old notes upon written or oral request made to Oil States International, Inc., Three Allen Center, 333 Clay Street, Suite 4620, Houston, TX 77002 (Telephone (713) 652-0582). To obtain timely delivery of any requested information, holders of old notes must make any request no later than five business days prior to the expiration of the exchange offer.

 

We include the following cautionary statement to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act, for any “forward-looking statement” made by us, or on our behalf. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. You can typically identify “forward-looking statements” by the use of forward-looking words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast,” and other similar words. All statements other than statements of historical facts contained in this prospectus, including statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions, are forward-looking statements. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

 

In any forward-looking statement where we, or our management, express an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. Taking this into account, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our company:

 

 

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

 

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

PROSPECTUS SUMMARY

Exchange Offer		We are offering to exchange new notes for old notes.
Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on          , 2011, unless we decide to extend it.
Condition to the Exchange Offer		The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.
Procedures for Tendering Old Notes		To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, which we call “DTC,” for tendering notes held in book-entry form. These procedures, which we call “ATOP,” require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC confirm that:
		• DTC has received your instructions to exchange your notes, and
		• you agree to be bound by the terms of the letter of transmittal.
		For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer” and “Procedures for Tendering.”
Guaranteed Delivery Procedures		None.
Withdrawal of Tenders		You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal by telegram, facsimile transmission or letter to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Withdrawal of Tenders.”
Acceptance of Old Notes and Delivery of New Notes		If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m. New York City time on the expiration date. We will return any old note that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer.”
Fees and Expenses		We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Fees and Expenses.”

Use of Proceeds		The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our registration rights agreement.
Consequences of Failure to Exchange Old Notes		If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act of 1933 (the Securities Act) except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
U.S. Federal Income Tax Consequences		The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Material United States Federal Income Tax Consequences.”
Exchange Agent		We have appointed Wells Fargo Bank, N.A. as exchange agent for the exchange offer. You should direct questions and requests for assistance, additional copies of this prospectus or the letter of transmittal to the exchange agent addressed as follows:
		Wells Fargo Bank, N.A. Corporate Trust Operations MAC N9303-121 Sixth & Marquette Avenue Minneapolis, MN 55479
		Eligible institutions may make requests by facsimile at (612) 667-6282 and may confirm facsimile delivery by calling (800) 344-5128.

Issuer		Oil States International, Inc.
Notes Offered		$600 million aggregate principal amount of 6.500% senior notes due 2019.
Maturity		June 1, 2019.
Interest Payment Dates		Interest on the new notes will be paid semi-annually in arrears on June 1 and December 1 of each year commencing on December 1, 2011. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, or, if no interest has been paid on the old note, from the date of the original issue of the old note.
Guarantees		Our obligations under the new notes will be fully and unconditionally guaranteed on a senior unsecured basis by our existing material domestic subsidiaries and by certain of our future subsidiaries. See “Description of the Notes — Guarantees.”
Ranking		The new notes will be our general unsecured senior obligations. The new notes will:
		• rank equally in right of payment with all of our existing and future senior indebtedness;
		• rank senior in right of payment to any of our future subordinated indebtedness; and
		• effectively rank junior in right of payment to all of our existing and future secured indebtedness and other obligations, including borrowings under our credit facilities, to the extent of the value of the assets securing such indebtedness and other obligations.
		The guarantees will be the guarantors’ general senior unsecured obligations and will:
		• rank equally in right of payment with any existing and future senior indebtedness of such guarantor;
		• rank senior in right of payment to any future subordinated indebtedness of such guarantor; and
		• effectively rank junior in right of payment to existing and future secured indebtedness and other obligations of such guarantor to the extent of the value of the assets securing such indebtedness and other obligations.
Optional Redemption		We will have the option to redeem the new notes, in whole or in part, at any time on or after June 1, 2014, in each case at the redemption prices described in this prospectus under the heading

		“Description of the Notes — Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.
		Prior to June 1, 2014, we may redeem the new notes, in whole or in part, at a “make-whole” redemption price described under “Description of the Notes — Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.
		In addition, prior to June 1, 2014, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the notes with the net proceeds of certain equity offerings at a redemption price equal to 106.500% of the principal amount of the new notes, plus any accrued and unpaid interest to the date of redemption.
Mandatory Offers to Purchase		Upon the occurrence of a change of control, holders of the new notes will have the right to require us to purchase all or a portion of the new notes at a price equal to 101% of the principal amount, together with any accrued and unpaid interest to the date of purchase.
Certain Covenants		We will issue the new notes under an indenture, dated June 1, 2011, with Wells Fargo Bank, N.A., as trustee. The indenture, among other things, limits our ability and the ability of our restricted subsidiaries to:
		• incur, assume or guarantee additional indebtedness or issue redeemable stock;
		• pay dividends on stock, repurchase stock or redeem subordinated debt;
		• make investments;
		• enter into transactions with affiliates;
		• create liens on our assets;
		• sell or otherwise dispose of assets, including capital stock of subsidiaries;
		• restrict dividends, loans or other asset transfers from our restricted subsidiaries; and
		• consolidate with or merge with or into, or sell all or substantially all of our properties to, another person.
		However, many of these covenants will terminate if:
		• either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. assigns the notes an investment grade rating; and
		• no default under the indenture exists.
		These covenants are subject to important exceptions and qualifications, which are described under “Description of the Notes — Certain Covenants.”

Transfer Restrictions; Absence of a Public Market for the Notes		The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes. We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system.
Risk Factors		Investing in the notes involves risks. See “Risk Factors” beginning on page 8 for a discussion of certain factors you should consider in evaluating an investment in the new notes.

 

Ratio of Earnings to Fixed Charges

		Six Months
		Ended
		June 30,				Year Ended December 31,
		2011				2010				2009				2008				2007				2006
Ratio of earnings to fixed charges			7.82				12.81				6.63				15.06				11.79				11.81

 

You should carefully consider the information included in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before investing in the notes.

 

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us, or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

 

Risks Relating to the Notes

 

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

 

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

 

If you do not exchange your old notes for new notes pursuant to the exchange offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless our registration rights agreement with the initial purchasers of the old notes requires us to do so. Further, if you continue to hold any old notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of these notes outstanding.

 

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

 

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the notes.

 

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness, including the notes. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments and the indenture governing the notes may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. The Amended and Restated Credit Agreement (the Credit Agreement) governing our U.S. and Canadian credit facilities and the indenture governing the notes restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then

due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

 

If we are unable to comply with the restrictions and covenants in the agreements governing our notes and other debt, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on the notes.

 

If we are unable to comply with the restrictions and covenants in the Credit Agreement and the indenture governing the notes or in current or future debt financing agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure you that we will be able to comply with these restrictions and covenants or meet these tests. Any default under the agreements governing our indebtedness, including a default under our Credit Agreement, that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our Credit Agreement and the indenture governing the notes), we could be in default under the terms of the agreements governing such indebtedness, including our Credit Agreement and the indenture governing the notes. In the event of such default:

 

 

If our operating performance declines, we may in the future need to obtain waivers from the required lenders under our Credit Agreement to avoid being in default. If we breach our covenants under our Credit Agreement and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our Credit Agreement, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

 

We may not be able to repurchase the notes in certain circumstances.

 

Under the terms of the indenture governing the notes, you may require us to repurchase all or a portion of your notes if we sell certain assets or in the event of a change of control. We may not have enough funds to pay the repurchase price on a purchase date. Our existing and any future credit agreements or other debt agreements to which we become a party may provide that our obligation to purchase or redeem the notes would be an event of default under such agreement. As a result, we may be restricted or prohibited from repurchasing or redeeming the notes. If we are prohibited from repurchasing or redeeming the notes, we could seek the consent of our then-existing lenders to repurchase or redeem the notes or we could attempt to refinance the borrowings that contain such prohibition. If we are unable to obtain a consent or refinance the debt, we could not repurchase or redeem the notes. Our failure to redeem tendered notes would constitute a default under the indenture governing the notes and might constitute a default under the terms of other indebtedness that we incur.

 

The term “change of control” is limited to certain specified transactions and may not include other events that might adversely affect our financial condition. Our obligation to repurchase the notes upon a change of control would not necessarily afford holders of notes protection in the event of a highly leveraged transaction, reorganization, merger or similar transaction involving us.

One of the circumstances under which a change of control may occur is upon the sale or disposition of all or substantially all of our assets. However, the phrase “all or substantially all” will likely be interpreted under applicable state law and will be dependent upon particular facts and circumstances. As a result, there may be a degree of uncertainty in ascertaining whether a sale or disposition of “all or substantially all” of our assets has occurred, in which case, the ability of a holder of the notes to obtain the benefit of an offer to repurchase all or a portion of the notes held by such holder may be impaired.

 

Any guarantees of the notes by our subsidiaries could be deemed fraudulent conveyances under certain circumstances, and a court may subordinate or void the subsidiary guarantees.

 

A court could subordinate or void the subsidiary guarantees under various fraudulent conveyance or fraudulent transfer laws. Generally, a subsidiary guarantee may be voided as a fraudulent conveyance or held unenforceable if a U.S. court was to find that at the time one of our subsidiaries entered into a subsidiary guarantee and either:

 

 

 

A legal challenge of a subsidiary guarantee on fraudulent conveyance grounds may focus, among other things, on the benefits, if any, the subsidiary realized as a result of our issuing the notes. To the extent a subsidiary guarantee is voided as a fraudulent conveyance or held unenforceable for any other reason, the holders of the notes would not have any claim against that subsidiary and would be creditors solely of us and any other subsidiary guarantors whose guarantees are not held unenforceable.

 

Many of the covenants contained in the indenture governing the notes terminate if the notes are rated investment grade by Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc.

 

Many of the covenants in the indenture governing the notes terminate if the notes are rated investment grade by Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. These covenants restrict, among other things, our ability to pay dividends, to incur debt and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, that the notes will maintain such ratings. However, termination of these covenants would, for the term of the notes, allow us to engage in certain transactions that would not be permitted while these covenants were in force. Please read “Description of the Notes — Certain Covenants — Covenant Termination.”

 

Your right to receive payments on the notes is effectively junior to our current and future indebtedness to the extent it is secured by our assets.

 

The notes and any guarantee effectively rank junior to any secured indebtedness we or the applicable guarantor currently have or may incur in the future, to the extent of the value of the assets that secure such indebtedness, including current and future borrowings under our credit facilities. As a result, upon any distribution to our creditors or the creditors of our guarantor subsidiaries in a bankruptcy, liquidation or reorganization or similar proceeding relating to us, our guarantor subsidiaries or our respective property, the

holders of our secured debt will be entitled to be paid in cash, to the extent of the value of the collateral securing such debt, before any payment may be made with respect to the notes.

 

In the event of a bankruptcy, liquidation or reorganization or similar proceeding relating to us, our subsidiaries or our respective properties, holders of the notes will participate with our trade creditors and all other holders of our senior unsecured indebtedness in the assets remaining. In any of these cases, we may not have sufficient funds to pay all of our creditors, and holders of the notes may receive less, ratably, than the holders of secured debt.

 

The notes are structurally subordinated to all indebtedness of our subsidiaries that are not guarantors of the notes.

 

The notes are guaranteed by each of our existing material domestic subsidiaries and will be guaranteed by certain of our future subsidiaries. Our subsidiaries that do not guarantee the notes, including all of our non-domestic subsidiaries, have no obligation, contingent or otherwise, to pay amounts due under the notes or to make any funds available to pay those amounts, whether by dividend, distribution, loan or other payment. The notes and guarantees are structurally subordinated to all indebtedness and other obligations of any non-guarantor subsidiary such that in the event of insolvency, liquidation, reorganization, dissolution or other winding up of any subsidiary that is not a guarantor, all of that subsidiary’s creditors (including trade creditors) would be entitled to payment in full out of that subsidiary’s assets before we would be entitled to any payment.

 

In addition, the indenture governing the notes, subject to some limitations, permits these subsidiaries to incur additional indebtedness and does not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries.

 

In addition, our subsidiaries that provide, or will provide, guarantees of the notes will be automatically released from those guarantees upon the occurrence of certain events, including the following:

 

 

If any subsidiary guarantee is released, no holder of the notes will have a claim as a creditor against that subsidiary, and the indebtedness and other liabilities, including trade payables and preferred stock, if any, whether secured or unsecured, of that subsidiary will be effectively senior to the claim of any holders of the notes. See “Description of the Notes — Guarantees.”

 

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

 

The old notes have not been registered under the Securities Act, and may not be resold by holders thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. At the time of the private placement of the old notes, the initial purchasers advised us that they intended to make a market in the old notes and, if issued, the new notes. The initial purchasers are not obligated, however, to make a market in the old notes or the new notes and any market making may be discontinued at any time at their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

 

The liquidity of any trading market for the notes and the market price quoted for the notes will depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

Risks Relating to Our Business

 

Our business is subject to a number of economic risks.

 

Financial markets worldwide experienced extreme disruption in the past three years, including, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others. Governments took unprecedented actions intended to address extreme market conditions such as severely restricted credit and declines in real estate values. Such economic events can recur and can potentially affect businesses such as ours in a number of ways. Tightening of credit in financial markets and a slowing economy adversely affects the ability of our customers and suppliers to obtain financing for significant operations, can result in lower demand for our products and services, and could result in a decrease in or cancellation of orders included in our backlog and adversely affect the collectability of our receivables. Additionally, tightening of credit in financial markets coupled with a slowing economy could negatively impact our cost of capital and ability to grow. Our business is also adversely affected when energy demand declines as a result of lower overall economic activity. Typically, lower energy demand negatively affects commodity prices that reduces the earnings and cash flow of our exploration and production and mining customers, reducing their spending and demand for our products and services. These conditions could have an adverse effect on our operating results and our ability to recover our assets at their stated values. Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Strengthening of the rate of exchange for the U.S. Dollar against certain major currencies, such as the Euro, the British Pound and the Canadian and Australian Dollar, could also adversely affect our results.

 

Decreased customer expenditure levels will adversely affect our results of operations.

 

Demand for our products and services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and gas and mining companies, including national oil companies. If our customers’ expenditures decline, our business will suffer. The industry’s willingness to explore, develop and produce depends largely upon the availability of attractive drilling prospects and the prevailing view of future commodity prices. Prices for oil, coal, natural gas, and other minerals are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other factors that are beyond our control. A sudden or long-term decline in product pricing would have material adverse effects on our results of operations. Any prolonged reduction in oil and natural gas prices will depress levels of exploration, development, and production activity, often reflected as reductions in rig counts. Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil and gas. Many factors affect the supply and demand for oil, coal, natural gas and other minerals and, therefore, influence product prices, including:

 

 

 

Our business may be adversely affected by extended periods of low oil prices or unsuccessful exploration results may decrease deepwater exploration and production activity or oil sands development and production in Canada.

 

Two of our businesses, where we manufacture offshore products for deepwater exploration and production and where we supply accommodations for oil sands developments, typically support our customers’ projects that are more capital intensive and take longer to generate first production than traditional oil and natural gas exploration and development activities. The economic analyses conducted by exploration and production companies in deepwater and oil sands areas have historically assumed a relatively conservative longer-term price outlook for production from such projects to determine economic viability. Perceptions of lower longer-term oil prices by these companies can cause our customers to reduce or defer major expenditures given the long-term nature of many large scale development projects, which could adversely affect our revenues and profitability in our offshore products segment and our accommodations segment.

 

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our services.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. In the U.S., the process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency, or EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent action. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study expected to be available in late 2012 and final results in 2014. In addition, for the second consecutive session, the federal Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. This legislation, if adopted, would require federal regulation of hydraulic fracturing as well as disclosure of the chemicals used in the fracturing process. Also, some states, such as New York, Pennsylvania, Colorado and Wyoming, have adopted, and other states, including Texas, are considering adopting, laws or regulations imposing disclosure obligations or restrictions on hydraulic fracturing activities in certain circumstances. The adoption of the FRAC Act or any

other federal, state or local laws or regulations or similar measures in other countries imposing disclosure obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in certain formations, increase our costs of compliance, and adversely affect the demand for the well site services that we provide.

 

Unconventional natural gas sources are exerting downward pricing pressures on the price of natural gas.

 

The rise in production of unconventional gas resources (onshore shale plays resulting from technological advancements in horizontal drilling and fracturing) in North America and the commissioning of a number of new large Liquefied Natural Gas (LNG) export facilities around the world are contributing to an over-supplied natural gas market. While production of natural gas from unconventional sources is a relatively small portion of the worldwide natural gas production, it is increasing because improved drilling efficiencies are lowering the costs of extraction. There is a significant oversupply of natural gas inventories in the United States in part due to the increase of unconventional gas in the market. Prolonged increases in the worldwide supply of natural gas, whether from conventional or unconventional sources, will likely continue to suppress natural gas prices. A prolonged period of suppressed natural gas prices would likely have a negative impact on development plans of exploration and production companies, which in turn, may result in a decrease in demand for drilling and completion products and services supplied by our well site services and tubular services segments.

 

Our financial results could be adversely impacted by the Macondo well incident and the resulting changes in regulation of offshore oil and natural gas exploration and development activity.

 

The U.S. Department of the Interior has issued Notices to Lessees and Operators (NTLs), has implemented additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, has imposed additional requirements with respect to development and production activities in U.S. waters and has delayed the approval of drilling plans and well permits in both deepwater and shallow water areas. The delays caused by new regulations and requirements have and will continue to have an overall negative effect on Gulf of Mexico drilling activity, and to a certain extent, our financial results.

 

The Macondo well incident, the subsequent oil spill and moratorium on drilling has caused offshore drilling delays, and is expected to result in increased state, federal and international regulation of our and our customer’s operations that could negatively impact our earnings, prospects and the availability and cost of insurance coverage. This delay could result in decreased demand for all of our business segments. There have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, including proposals to significantly increase the minimum financial responsibility demonstration required under the federal Oil Pollution Act of 1990. Any increased regulation of the exploration and production industry as a whole that arises out of the Macondo well incident could result in fewer companies being financially qualified to operate offshore in the U.S., could result in higher operating costs for our customers and could reduce demand for our services.

 

We have a significant concentration of our accommodations business located in the oil sands region of Alberta, Canada.

 

Because of the concentration of our accommodations business in the Canadian oil sands in one relatively small geographic area, we have increased exposure to political, regulatory, environmental, labor, climate or natural disaster events or developments that could negatively impact our operations and financial results.

 

In our accommodations business supporting mining, our clients’ production or price issues may adversely affect us.

 

The volumes and prices of the products of our clients, including coal and gold, have historically varied significantly and are difficult to predict. The demand for, and price of, these minerals and commodities is highly dependent on a variety of factors, including international supply and demand, the price and availability of alternative fuels, actions taken by governments and global economic and political developments. Mineral

and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. We expect that a material decline in mineral and commodity prices could result in a decrease in the activity of our clients with the possibility that this would materially adversely affect us. No assurance can be given regarding future volumes and/or prices relating to the activities of our clients.

 

Because the oil and gas industry is cyclical, our operating results may fluctuate.

 

Oil and natural gas prices have been and are expected to remain volatile. This volatility causes oil and gas companies and drilling contractors to change their strategies and expenditure levels. Supplies of oil and natural gas can be influenced by many factors, including improved technology such as the hydraulic fracturing of horizontally drilled wells in shale discoveries, access to potential productive regions and availability of required infrastructure to deliver production to the marketplace. We have experienced in the past, and expect to experience in the future, significant fluctuations in operating results based on these changes.

 

The cyclical nature of our business and a severe prolonged downturn could negatively affect the value of our goodwill.

 

As of June 30, 2011 and December 31, 2010, goodwill represented approximately 14% and 16%, respectively, of our total assets. We have recorded goodwill because we paid more for some of our businesses than the fair market value of the tangible and separately measurable intangible net assets of those businesses. Current accounting standards, which were effective January 1, 2002, require a periodic review of goodwill for impairment in value and a non-cash charge against earnings with a corresponding decrease in stockholders’ equity if circumstances, some of which are beyond our control, indicate that the carrying amount will not be recoverable. In the fourth quarter of 2008, we recognized an impairment of a portion of our goodwill totaling $85.6 million as a result of several factors affecting our tubular services and drilling reporting units. In the second quarter of 2009, we recognized an impairment of $94.5 million representing a portion of our remaining goodwill as a result of several factors affecting our rental tools reporting unit. It is possible that we could recognize additional goodwill impairment losses in the future if, among other factors:

 

 

The level and pricing of tubular goods imported into the U.S. could decrease demand for our tubular goods inventory and adversely impact our results of operations. Also, if steel mills were to sell a substantial amount of goods directly to end users in the U.S., our results of operations could be adversely impacted.

 

Although imports of oil country tubular goods (OCTG) from China are currently restricted by trade sanctions imposed by the U.S. government, lower-priced tubular goods from a number of foreign countries are still imported into the U.S. tubular goods market. If the level of imported lower-priced tubular goods were to otherwise increase from current levels or if prices and margins are driven down by increased supplies of tubular goods, our tubular services segment could be adversely affected to the extent that we would then have higher-cost tubular goods in inventory. If prices were to decrease significantly, we might not be able to profitably sell our inventory of tubular goods. In addition, significant price decreases could result in a longer holding period for some of our inventory, which could also have an adverse effect on our tubular services segment.

We do not manufacture any of the tubular goods that we distribute. Historically, users of tubular goods in the U.S., in contrast to those outside the U.S., have purchased tubular goods through distributors. If customers were to purchase tubular goods directly from steel mills, our results of operations could be adversely impacted.

 

We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the U.S.

 

A portion of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 29% (8% excluding Canada) of our consolidated revenue in the year ended December 31, 2010. Risks associated with our operations in foreign areas include, but are not limited to:

 

 

Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete.

 

Our international business operations also include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to the same ethics related laws and regulations such as the Foreign Corrupt Practices Act in the U.S. and the Anti-Bribery law in the U.K., can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that certain ethics related laws and regulations prohibit us from using. For example, our non-U.S. competitors are not subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally owned oil companies in order to obtain or retain any business or other advantage. While many countries, like the U.S. and the U.K., have adopted similar anti-bribery statutes, there has not been universal adoption and enforcement of such statutes. Therefore, we may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.

 

Violations of these laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.

 

We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.

 

All of our operations are significantly affected by stringent and complex foreign, federal, provincial, state and local laws and regulations governing the discharge of substances into the environment or otherwise

relating to protection of natural resources and the environment. These laws and regulations may impose restrictions and numerous obligations applicable to our operations including the acquisition of permits before conducting regulated activities, the restriction on the types, quantities and concentration of materials that can be released into the environment, and the imposition of substantial liabilities for pollution resulting from our operations. Any failure by us to comply with these applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:

 

 

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of the handling of petroleum hydrocarbons, naturally occurring radioactive materials and wastes, the occurrence of spills or other unauthorized releases, and legacies arising from historical industry activities and waste disposal practices. We could be exposed to liability for cleanup costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Moreover, environmental laws and regulations are subject to change in the future, possibly resulting in more stringent requirements. If existing regulatory requirements or enforcement policies change or are more stringently enforced, we may be required to make significant unanticipated capital and operating expenditures.

 

We may be exposed to certain regulatory and financial risks related to climate change.

 

Climate change is receiving increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions. A significant focus is being made on companies that are active producers of depleting natural resources.

 

There are a number of legislative and regulatory initiatives addressing greenhouse gas emissions both in the U.S. and abroad, which are in various phases of discussion or implementation. The outcome of foreign, U.S. federal, regional, provincial and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional costs to conduct energy efficiency activities, or other regulatory actions. These actions could:

 

 

Any adoption by foreign, U.S. federal, regional, provincial or state governments of enforceable requirements mandating a substantial reduction in greenhouse gas emissions, implementation of the Kyoto Protocol, or other foreign, U.S. federal, regional or state requirements or other efforts to regulate greenhouse gas emissions, could have far-reaching and significant impacts on the energy industry in general and our customers in particular. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our services. See “Business — Government Regulation” for a more detailed description of our climate-change related risks.

Currently proposed legislative changes could materially, negatively impact the company, increase the costs of doing business and decrease the demand for our products.

 

The current U.S. administration and Congress have proposed several new articles of legislation or legislative and administration changes which could have a material negative effect on our company. Some of the proposed changes that could negatively impact us are:

 

 

Our customers in the accommodations business are exposed to a number of unique operating risks which could also adversely affect us.

 

We could be materially adversely affected by disruptions to the operation of our clients caused by any one of or all of the following singularly or in combination:

 

 

 

Our accommodations business is exposed to a number of general risks that could materially adversely affect our assets and liabilities, financial position, profits, prospects and share price.

 

Examples of these broad general risks which may impact our performance include:

 

 

Development of permanent infrastructure in the oil sands region or regions of Australia where we locate accommodations villages could negatively impact our accommodations business.

 

Our accommodations business specializes in providing housing and personnel logistics for work forces in remote areas which lack the infrastructure typically available in nearby towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of northern Alberta, Canada, or regions of Australia where we locate accommodations villages, demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

 

Construction risks exist in our accommodations business.

 

There are a number of general risks that might impinge on companies involved in the development, construction, manufacture and installation of facilities as a prerequisite to the management of those assets in an operational sense. We might be exposed to these risks from time to time by relying on these corporations and/or other third parties which could include any and/or all of the following:

 

 

We are susceptible to seasonal earnings volatility due to adverse weather conditions in our regions of operations.

 

Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, Australia, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian accommodations operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the spring months and, as a result, adversely affects our operations and sales of products and services in the second and, to a lesser extent, third quarters. Our operations in the Gulf of Mexico are also affected by weather patterns. Weather conditions in the Gulf Coast region generally result in higher drilling activity in the spring, summer and fall months with the lowest activity in the winter months. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. In addition, summer and fall drilling activity can be restricted due to hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast. For example, during 2005, a significant disruption occurred in oil and natural gas drilling and production operations in the U.S. Gulf of Mexico due to damage inflicted by Hurricanes Katrina and Rita and, during 2008, from Hurricane Ike. Cyclones can affect our operations in Australia.

 

We are exposed to risk relating to subcontractors’ performance in some of our projects.

 

In many cases, we subcontract the performance of parts of our operations to subcontractors. While we seek to obtain appropriate indemnities and guarantees from these subcontractors, we remain ultimately responsible for the performance of our subcontractors. Industrial disputes, natural disasters, financial failure or default or inadequate performance in the provision of services, or the inability to provide services by such subcontractors has the potential to materially adversely affect us.

 

Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.

 

Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our growth strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition.

 

We expect to gain certain business, financial and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize these intended benefits. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition. Additional risks we could face in connection with acquisitions include:

 

 

Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition.

 

We may not have adequate insurance for potential liabilities.

 

Our operations are subject to many hazards. We face the following risks under our insurance coverage:

 

 

Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position.

 

We are subject to litigation risks that may not be covered by insurance.

 

In the ordinary course of business, we become the subject of various 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 the activities of businesses that we have sold, and some relate to the activities of businesses that we have acquired, even though these activities may have occurred prior to our acquisition of such businesses. We maintain insurance to cover many of our potential losses, and we are subject to various self-retentions and deductibles under our insurance. It is possible, however, that a judgment could be rendered against us in cases in which we could be uninsured and beyond the amounts that we currently have reserved or anticipate incurring for such matters.

 

Our concentration of customers in two industries may impact overall exposure to credit risk.

 

Substantially all of our customers operate in the energy or mining industries. This concentration of customers in two industries may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.

 

We may assume contractual risk in developing, manufacturing and delivering products in our offshore products business segment.

 

Many of our products from our offshore products segment are ordered by customers under frame agreements or project specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. In addition, some customer contracts stipulate consequential damages payable, generally as a result of our gross negligence or willful misconduct. The final delivered products may also include customer and third party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.

 

In certain cases these orders include new technology or unspecified design elements. In some cases we may not be fully or properly compensated for the cost to develop and design the final products, negatively

impacting our profitability on the projects. In addition, our customers, in many cases, request changes to the original design or bid specifications for which we may not be fully or properly compensated.

 

As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs and any gross profit realized on these fixed-price contracts may vary from the initially expected contract economics. There is inherent risk in the estimation process including significant unforeseen technical and logistical challenges or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices (including the price of steel) through increased pricing. In fulfilling some contracts, we provide limited warranties for our products. Although we estimate and record a provision for potential warranty claims, repair or replacement costs under warranty provisions in our contracts could exceed the estimated cost to cure the claim which could be material to our financial results. We utilize percentage completion accounting, depending on the size of a project and variations from estimated contract performance could have a significant impact on our reported operating results as we progress toward completion of major jobs.

 

Our backlog is subject to unexpected adjustments and cancellations and is, therefore, an imperfect indicator of our future revenues and earnings.

 

The revenues projected in our backlog may not be realized or, if realized, may not result in profits. Because of potential changes in the scope or schedule of our customers’ projects, we cannot predict with certainty when or if backlog will be realized. In addition, even where a project proceeds as scheduled, it is possible that contracted parties may default and fail to pay amounts owed to us. Material delays, cancellations or payment defaults could materially affect our financial condition, results of operations and cash flows.

 

Reductions in our backlog due to cancellations by customers or for other reasons would adversely affect, potentially to a material extent, the revenues and earnings we actually receive from contracts included in our backlog. Some of the contracts in our backlog are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. We typically have no contractual right upon cancellation to the total revenues reflected in our backlog. If we experience significant project terminations, suspensions or scope adjustments to contracts reflected in our backlog, our financial condition, results of operations and cash flows may be adversely impacted.

 

We might be unable to employ a sufficient number of technical personnel.

 

Many of the products that we sell, especially in our offshore products segment, are complex and highly engineered and often must perform in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize and enhance these products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. During periods of increased activity, the demand for skilled workers is high, and the supply is limited. We have already experienced high demand and increased wages for labor forces serving our accommodations business in Canada. When these events occur, our cost structure increases and our growth potential could be impaired.

 

We might be unable to compete successfully with other companies in our industry.

 

The markets in which we operate are highly competitive and certain of them have relatively few barriers to entry. The principal competitive factors in our markets are product, equipment and service quality, availability, responsiveness, experience, technology, safety performance and price. In some of our business segments, we compete with the oil and gas industry’s largest oilfield service providers. These large national and multi-national companies have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts

are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.

 

If we do not develop new competitive technologies and products, our business and revenues may be adversely affected.

 

The market for our offshore products is characterized by continual technological developments to provide better performance in increasingly greater water depths, higher pressure levels and harsher conditions. If we are not able to design, develop and produce commercially competitive products in a timely manner in response to changes in technology, our business and revenues will be adversely affected. In addition, competitors or customers may develop new technology, which addresses similar or improved solutions to our existing technology. Should our technology, particularly in offshore products or in our rental tool business, become the less attractive solution, our operations and profitability would be negatively impacted.

 

During periods of strong demand, we may be unable to obtain critical project materials on a timely basis.

 

Our operations depend on our ability to procure, on a timely basis, certain project materials, such as forgings, to complete projects in an efficient manner. Our inability to procure critical materials during times of strong demand could have a material adverse effect on our business and operations.

 

Our oilfield operations involve a variety of operating hazards and risks that could cause losses.

 

Our operations are subject to the hazards inherent in the oilfield business. These include, but are not limited to, equipment defects, blowouts, explosions, fires, collisions, capsizing and severe weather conditions. These hazards could result in personal injury and loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage and suspension of operations. We may incur substantial liabilities or losses as a result of these hazards as part of our ongoing business operations. We may agree to indemnify our customers against specific risks and liabilities. While we maintain insurance protection against some of these risks, and seek to obtain indemnity agreements from our customers requiring the customers to hold us harmless from some of these risks, our insurance and contractual indemnity protection may not be sufficient or effective enough to protect us under all circumstances or against all risks. The occurrence of a significant event not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition.

 

If we were to lose a significant supplier of our tubular goods, we could be adversely affected.

 

During the year ended December 31, 2010, we purchased 56% of our total tubular goods from a single domestic supplier and 72% of our total OCTG purchases from three domestic suppliers. If we were to lose any of these suppliers or if production at one or more of the suppliers was interrupted, our tubular services segment’s business, financial condition and results of operations could be adversely affected. If the extent of the loss or interruption were sufficiently large, the impact on us could be material.

 

Our operations may suffer due to increased industry-wide capacity of certain types of equipment or assets.

 

The demand for and pricing of certain types of our assets and equipment, particularly our drilling rigs and rental tool assets, is subject to the overall availability of such assets in the marketplace. If demand for our assets were to decrease, or to the extent that we and our competitors increase our fleets in excess of current demand, we may encounter decreased pricing for or utilization of our assets and services, which could adversely impact our operations and profits.

 

In addition, we have significantly increased our accommodations capacity in the oil sands region over the past five years based on our expectation for current and future customer demand for accommodations in the area. Should our customers build their own facilities to meet their accommodations needs or our competitors likewise increase their available accommodations, or activity in the oil sands decline significantly, demand

and/or pricing for our accommodations could decrease, negatively impacting the profitability of our accommodations segment.

 

We might be unable to protect our intellectual property rights.

 

We rely on a variety of intellectual property rights that we use in our offshore products and well site services segments, particularly our patents relating to our FlexJoint^® technology and intervention tools utilized in the completion or workover of oil and natural gas wells. The market success of our technologies will depend, in part, on our ability to obtain and enforce our proprietary rights in these technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented or challenged. If any of our patents or other intellectual property rights are determined to be invalid or unenforceable, or if a court limits the scope of claims in a patent or fails to recognize our trade secret rights, our competitive advantages could be significantly reduced in the relevant technology, allowing competition for our customer base to increase. In addition, the laws of some foreign countries in which our products and services may be sold do not protect intellectual property rights to the same extent as the laws of the U.S. The failure of our company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position.

 

Loss of key members of our management could adversely affect our business.

 

We depend on the continued employment and performance of key members of management. If any of our key managers resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain “key man” life insurance for any of our officers.

 

We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonpayment and nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.

 

Risks of nonpayment and nonperformance by our counterparties are a concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counter-parties, such as our lenders and insurers. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In connection with the recent economic downturn, commodity prices declined sharply, and the credit markets and availability of credit were constrained. Additionally, many of our customers’ equity values declined substantially. The combination of lower cash flow due to commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of available debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any increase in the nonpayment and nonperformance by our counterparties could have an adverse impact on our results of operations, cash flows and financial condition, adversely affecting our liquidity.

 

Employee and customer labor problems could adversely affect us.

 

As of December 31, 2010, we were party to collective bargaining agreements covering 1,689 employees in Canada, Australia, the United Kingdom and Argentina. In addition, our accommodations facilities serving oil sands development work in Northern Alberta, Canada house both union and non-union customer employees. We have not experienced strikes, work stoppages or other slowdowns in the recent past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business, financial condition and results of operations.

 

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

 

 

For purposes of computing the ratio of earnings to fixed charges, “earnings” consists of the sum of pre-tax income from continuing operations before income or loss from equity investees, adjusted to reflect actual distributions from equity investments, fixed charges, amortization of capitalized interest less interest capitalized and the non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges. “Fixed charges” consists of the sum of interest costs expensed and capitalized, amortized discounts and debt issue costs related to indebtedness and the portion of rental expense, which we believe represents an interest factor.

 

We did not have any preferred stock outstanding and there were no preferred stock dividends paid or accrued during the periods presented above.

 

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act of 1933 and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

 

The following tables show our historical consolidated financial data for the periods and as of the dates indicated. The summary consolidated statements of income and cash flows data for the years ended December 31, 2010, 2009, 2008 and 2007 and the consolidated balance sheet data as of December 31, 2010, 2009 and 2008 are derived from our audited consolidated financial statements. The summary consolidated statement of income and cash flows data for the year ended December 31, 2006 and the consolidated balance sheet data as of December 31, 2007 and 2006 are derived from our unaudited accounting records, which were adjusted for the retrospective application of ASC 470-20 “Debt With Conversion and Other Options.” The consolidated statements of income and cash flows data for the six months ended June 30, 2011 and 2010 and consolidated balance sheet data as of June 30, 2011 are derived from our unaudited condensed consolidated financial statements included in this registration statement. The summary financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this registration statement.

 

 

 

 

 

The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data, included elsewhere in this registration statement. Our operating results for the periods discussed may not be indicative of future performance. Statements concerning future results are forward-looking statements that should be read in connection with “Cautionary Statement Regarding Forward-Looking Statements” included elsewhere in this registration statement.

 

Overview

 

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 also support the mining industry in Australia. 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, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services is highly sensitive to current and expected commodity prices. Activity for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, activity for our well site services and tubular services segments responds more rapidly 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 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. 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 OCTG inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services segment, we provide rental tools and land drilling services. Demand for our drilling services is driven by land drilling activity in our primary drilling markets in West Texas, where we primarily drill oil wells, and in the Rocky Mountains area in the U.S. where we drill both oil and natural gas wells. Our rental tools business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the rental tools business is dependant primarily upon the level and complexity of drilling, completion and workover activity throughout North America.

 

Our Business Segments

 

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 coal resources and, to a lesser extent, other mineral resources. A significant portion of our accommodations revenues 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 covering lodging and meals that is based on the duration of their needs which can range from several months to several years. In addition, we provide shorter-term remote site accommodations in smaller configurations utilizing our modular, mobile camp assets.

Generally, our customers for oil sands and mining accommodations are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 to 30 years, and consequently these investments are dependent on those customers’ longer-term view of commodity demand and prices. Oil sands development activity has increased in the past year and has had a positive impact on our accommodations segment. Recent announcements have led to extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada. In addition, several major oil companies and national oil companies have acquired oil sands leases over the past twelve months that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. Our Australian accommodations business is significantly influenced by increased metallurgical coal demand, especially from China and India. We are expanding our Australian accommodations manufacturing capacity to meet increasing demand and prospects for increased customer room demands are likely.

 

Another factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and, to a lesser extent, the exchange rate between the U.S. dollar and the Australian dollar. Our accommodations segment has derived a majority of its revenues and operating income in Canada denominated in Canadian dollars. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the first six months of 2011, the Canadian dollar was valued at an average exchange rate of U.S. $1.02 compared to U.S. $0.97 for the first six months of 2010, an increase of 5%. This strengthening of the Canadian dollar had a positive impact on the translation of earnings generated from our Canadian subsidiaries and, therefore, the financial results of our accommodations segment.

 

Our offshore products segment is also influenced significantly by our customers’ longer term outlook for energy prices and 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.

 

New order activity in our offshore products segment was limited beginning in the fourth quarter of 2008 and continued to decline throughout 2009 due to project postponements, cancellations and deferrals by customers as a result of the global economic recession and reduced oil prices. This reduction in order activity led to declines in our offshore products backlog and decreased revenues and profits in the first six months of 2010. With the improvement in oil prices over the last two years along with the improved outlook for long-term oil demand, we began experiencing increased bidding and quoting activity for our offshore products in the second half of 2010 and continuing throughout the first six months of 2011. As a result of this increased activity, our backlog in offshore products has increased from $215.7 million as of June 30, 2010 to $518.6 million as of June 30, 2011, a 140% increase.

 

Our well site services and tubular services segments are significantly influenced by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada. Over the past several years, this activity has been 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, with the rise in oil prices, the lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America is beginning to shift to a greater proportion of oil and liquids rich gas drilling. The oil rig count in the U.S. now totals approximately 1,000 rigs, the highest count in over 20 years, comprising approximately 53% of total U.S. drilling activity.

 

In our well site services segment, we provide rental tools and land drilling services. Demand for our drilling services is driven by land drilling activity in West Texas, where we primarily drill oil wells, and in the Rocky Mountains area in the U.S., where we drill both oil and natural gas wells. Our rental tools business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the rental tools business is dependant primarily upon the level and complexity of drilling, completion and workover activity throughout North America.

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 OCTG inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices.

 

Demand for our tubular services, land drilling and rental tool businesses is highly correlated to changes in the drilling rig count in the U.S. 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.

 

 

The rig count began to decline in the fourth quarter of 2008 and fell precipitously in the first half of 2009. The average North American rig count for the year ended December 31, 2010 increased by 585 rigs, or 45%, compared to the average for the year ended December 31, 2009 largely due to growth in the U.S. land rig count. The average North American rig count for the three months ended June 30, 2011 increased by 344 rigs, or 21%, compared to the three months ended June 30, 2010 largely due to growth in the U.S. land rig count.

 

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby influencing the pricing and margins of our tubular services segment. OCTG marketplace supply and demand has become more balanced recently compared to the 2008 to 2009 period. Increased supplies of OCTG have met the increased demand caused by expanded drilling activity. Recent global steel prices have increased affecting the raw material costs of our OCTG suppliers. To date, we have incurred modest OCTG price increases, which we have been able to pass through to our customers. The OCTG Situation Report indicates that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately five to six months’ supply currently, which is considered closer to a normalized level measured against historical levels.

 

During 2010, U.S. mills began increasing production and imports of steel have increased in the first part of 2011, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. We believe this increase in supply has been in response to the approximately 21% year-over-year increase in the drilling rig count in the U.S.

 

Other Factors that Influence our Business

 

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 recovery in U.S. Gulf of Mexico drilling following the government imposed drilling moratorium.

 

We have witnessed unprecedented events in the U.S. Gulf of Mexico as a result of the Macondo well incident and resultant oil spill. As a result of the incident, in May 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, of the U.S. Department of the Interior implemented a moratorium on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico that effectively shut down new deepwater drilling activities in 2010. The moratorium was lifted during October 2010. However, the BOEMRE issued Notices to Lessees and Operators (NTLs), implemented additional safety

and certification requirements applicable to plans for drilling activities in the U.S. waters, imposed additional requirements with respect to development and production activities in the U.S. waters, and delayed the approval of applications to drill in both deepwater and shallow-water areas. Despite the rescission of the moratorium, offshore drilling activity is being delayed by adjustments in operating procedures, compliance certifications, and lead times for permits and inspections, as a result of changes in the regulatory environment. In addition, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production. Uncertainties and delays caused by the new regulatory environment have and are expected to continue to have an overall negative effect on Gulf of Mexico drilling activity and, to a certain extent, the financial results of all of our business segments.

 

We continue to monitor the global economy, the demand for crude oil, coal and natural gas prices and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. We currently expect that our 2011 capital expenditures will total approximately $650 million compared to 2010 capital expenditures of $182 million. Our 2011 capital expenditures include funding to expand several of our Canadian and Australian accommodations facilities, to add incremental equipment in our rental tools segment, to increase our fleet of modular, mobile camp assets in Canada and the U.S. and to complete projects in progress at December 31, 2010, including (i) the construction of the Henday Lodge accommodations facility in the Canadian oil sands, (ii) continued expansion of our Wapasu Creek, Beaver River and Athabasca Lodge accommodations facilities in the Canadian oil sands and (iii) ongoing maintenance capital requirements. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals. In our tubular services segment, we remain focused on industry inventory levels, future drilling and completion activity and OCTG prices.

 

Consolidated Results of Operations

 

 

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

 

We reported net income attributable to Oil States International, Inc. for the quarter ended June 30, 2011 of $74.2 million, or $1.34 per diluted share. These results compare to net income of $37.5 million, or $0.71 per diluted share, reported for the quarter ended June 30, 2010.

 

Revenues.  Consolidated revenues increased $225.8 million, or 38%, in the second quarter of 2011 compared to the second quarter of 2010.

 

Our well site services segment revenues increased $40.4 million, or 36%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was primarily due to significantly increased rental tools revenues. Our rental tools revenues increased $33.6 million, or 42%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization and better pricing. Our drilling services revenues increased $6.8 million, or 20%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of increases in pricing with average day rates rising to $16.5 thousand per day in the second quarter of 2011 from $14.2 thousand per day in the second quarter of 2010.

 

Our accommodations segment reported revenues in the second quarter of 2011 that were $81.0 million, or 66%, above the second quarter of 2010. The increase in accommodations revenue resulted from the full quarter contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues from increased room capacity. Revenues and average available rooms for our oil sands lodges increased 43% and 29%, respectively, in the second quarter of 2011 compared to the second quarter of 2010.

 

Our offshore products segment revenues increased $25.7 million, or 24%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was primarily the result of higher revenues for production and subsea orders.

 

Tubular services segment revenues increased $78.7 million, or 31%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was the result of an increase in tons shipped from 134,900 in 2010 to 173,300 in 2011, an increase of 38,400 tons, or 28%, driven by increased drilling activity.

Cost of Sales and Service.  Our consolidated cost of sales increased $147.3 million, or 31%, in the second quarter of 2011 compared to the second quarter of 2010 as a result of increased cost of sales at our tubular services segment of $70.3 million, or 29%, an increase at our accommodations segment of $35.3 million, or 48%, an increase at our well site services segment of $21.2 million, or 27%, and an increase at our offshore products segment of $20.5 million, or 26%. Our consolidated gross margin as a percentage of revenues increased from 21% in the second quarter of 2010 to 25% in the second quarter of 2011 primarily due to the increased proportion of relatively higher margin accommodations segment revenues in 2011 compared to 2010 and higher margins realized in our accommodations business in Australia.

 

Our well site services segment cost of sales increased $21.2 million, or 27%, in the second quarter of 2011 compared to the second quarter of 2010 as a result of a $20.4 million, or 41%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 31% in the second quarter of 2010 to 35% in the second quarter of 2011. Our rental tool gross margin as a percentage of revenues increased from 37% in the second quarter of 2010 to 38% in the second quarter of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $0.8 million, or 3%, in the second quarter of 2011 compared to the second quarter of 2010. Our drilling services gross margin as a percentage of revenues increased from 17% in the second quarter of 2010 to 29% in the second quarter of 2011 primarily due to the increase in day rates.

 

Our accommodations segment cost of sales increased $35.3 million, or 48%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $13.1 million, or 19%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues. Our accommodations segment gross margin as a percentage of revenues increased from 40% in the second quarter of 2010 to 47% in the second quarter of 2011 primarily as a result of higher margins realized by our Australian operations.

 

Our offshore products segment cost of sales increased $20.5 million, or 26%, in the second quarter of 2011 compared to the second quarter of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased from 27% in the second quarter of 2010 to 25% in the second quarter of 2011 primarily due to product mix and lower service content in the second quarter of 2011.

 

Tubular services segment cost of sales increased by $70.3 million, or 29%, primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in the second quarter of 2010 to 6% in the second quarter of 2011 due primarily to a 2% increase in revenue per ton.

 

Selling, General and Administrative Expenses.  Selling, general and administrative expense (SG&A) increased $5.6 million, or 15%, in the second quarter of 2011 compared to the second quarter of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $2.7 million in SG&A expense in the second quarter of 2011, an increase in employee-related costs, higher ad valorem taxes and higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar. SG&A was 5.2% of revenues in the second quarter of 2011 compared to 6.3% of revenues in the second quarter of 2010.

 

Depreciation and Amortization.  Depreciation and amortization expense increased $14.6 million, or 48%, in the second quarter of 2011 compared to the same period in 2010 due primarily to $12.2 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

 

Operating Income.  Consolidated operating income increased $57.4 million, or 99%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of an increase in operating income from our well site services segment of $22.1 million, or 238%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization coupled with higher operating

income in our accommodations segment due to the addition of operating income from The MAC and an increase in operating income from our oil sands lodges due to increased room capacity.

 

Interest Expense and Interest Income.  Net interest expense increased by $8.9 million, or 262%, in the second quarter of 2011 compared to the second quarter of 2010 due to increased debt levels, including interest expense on the 61/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our $1.05 billion credit facilities. The weighted average interest rate on the Company’s revolving credit facilities was 3.0% in the second quarters of 2011 and 2010.

 

Income Tax Expense.  Our income tax provision for the three months ended June 30, 2011 totaled $28.9 million, or 27.9% of pretax income, compared to income tax expense of $16.6 million, or 30.6% of pretax income, for the three months ended June 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

 

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

 

We reported net income attributable to Oil States International, Inc. for the six months ended June 30, 2011 of $136.3 million, or $2.48 per diluted share. These results compare to net income of $77.7 million, or $1.49 per diluted share, reported for the six months ended June 30, 2010.

 

Revenues.  Consolidated revenues increased $453.9 million, or 40%, in the first half of 2011 compared to the first half of 2010.

 

Our well site services segment revenues increased $83.1 million, or 39%, in the first half of 2011 compared to the first half of 2010. This increase was primarily due to significantly increased rental tools revenues. Our rental tools revenues increased $73.6 million, or 50%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization and better pricing. Our drilling services revenues increased $9.5 million, or 15%, in the first half of 2011 compared to the first half of 2010 primarily as a result of increases in pricing with average day rates rising to $15.9 thousand per day in the first half of 2011 from $14.0 thousand per day in the first half of 2010.

 

Our accommodations segment reported revenues in the first half of 2011 that were $132.6 million, or 50%, above the first half of 2010. The increase in accommodations revenue resulted from the contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues from increased room capacity, partially offset by the Vancouver Olympics contract, which contributed $25.0 million in revenues in the first half of 2010, which was not repeated in 2011. Revenues and average available rooms for our oil sands lodges increased 39% and 27%, respectively, in the first half of 2011 compared to the first half of 2010.

 

Our offshore products segment revenues increased $51.2 million, or 24%, in the first half of 2011 compared to the first half of 2010. This increase was primarily the result of higher demand for production, subsea pipeline and elastomer products and the contribution from the acquisition of Acute.

 

Tubular services segment revenues increased $187.0 million, or 43%, in the first half of 2011 compared to the first half of 2010. This increase was a result of an increase in tons shipped from 236,100 in 2010 to 327,700 in 2011, an increase of 91,600 tons, or 39%, driven by increased drilling activity.

 

Cost of Sales and Service.  Our consolidated cost of sales increased $315.2 million, or 36%, in the first half of 2011 compared to the first half of 2010 as a result of increased cost of sales at our tubular services segment of $171.1 million, or 41%, an increase at our accommodations segment of $61.8 million, or 40%, an increase at our well site services segment of $43.4 million, or 29%, and an increase at our offshore products segment of $38.9 million, or 25%. Our consolidated gross margin as a percentage of revenues increased from 22% in the first half of 2010 to 25% in the first half of 2011 primarily due to the increased proportion of relatively higher margin accommodations segment revenues in 2011 compared to 2010 and higher margins

realized in our well site services, accommodations and tubular services segments, partially offset by the increased proportion of relatively lower margin tubular services segment revenues in 2011 compared to 2010.

 

Our well site services segment cost of sales increased $43.4 million, or 29%, in the first half of 2011 compared to the first half of 2010 as a result of a $42.4 million, or 44%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 30% in the first half of 2010 to 35% in the first half of 2011. Our rental tools gross margin as a percentage of revenues increased from 35% in the first half of 2010 to 37% in the first half of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $1.0 million, or 2%, in the first half of 2011 compared to the first half of 2010. Our drilling services gross margin as a percentage of revenues increased from 17% in the first half of 2010 to 27% in the first half of 2011 primarily due to the increase in day rates.

 

Our accommodations segment cost of sales increased $61.8 million, or 40%, in the first half of 2011 compared to the first half of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $16.7 million, or 11%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues. Our accommodations segment gross margin as a percentage of revenues increased from 42% in the first half of 2010 to 46% in the first half of 2011 primarily due to higher margins realized by our Australian operations.

 

Our offshore products segment cost of sales increased $38.9 million, or 25%, in the first half of 2011 compared to the first half of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 25% in the first half of 2010 and 2011.

 

Tubular services segment cost of sales increased by $171.1 million, or 41%, primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in the first half of 2010 to 6% in the first half of 2011 due primarily to a 3% increase in revenue per ton.

 

Selling, General and Administrative Expenses.  SG&A increased $14.1 million, or 20%, in the first half of 2011 compared to the first half of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $6.0 million in SG&A expense in the first half of 2011, increased employee-related costs and increased ad valorem taxes. SG&A was 5.5% of revenues in the first half of 2011 compared to 6.4% of revenues in the first half of 2010.

 

Depreciation and Amortization.  Depreciation and amortization expense increased $28.7 million, or 47%, in the first half of 2011 compared to the same period in 2010 due primarily to $23.0 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

 

Operating Income.  Consolidated operating income increased $92.4 million, or 79%, in the first half of 2011 compared to the first half of 2010 primarily as a result of an increase in operating income from our well site services segment of $46.4 million, or 396%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization and the addition of operating income from The MAC. Operating income in the first half of 2011 included $1.4 million in acquisition related expenses for acquisitions closed in the fourth quarter of 2010.

 

Interest Expense and Interest Income.  Net interest expense increased by $14.7 million, or 217%, in the first half of 2011 compared to the first half of 2010 due to increased debt levels, including interest expense on the 61/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our $1.05 billion credit facilities. The weighted average interest rate on the Company’s revolving credit facilities was 3.0% in the first six months of 2011 compared to 2.5% in the first six months of 2010. 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, 2011 totaled $52.3 million, or 27.6% of pretax income, compared to income tax expense of $33.4 million, or 30.0% of pretax income, for the six months ended June 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

 

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

 

We reported net income attributable to Oil States International, Inc. for the year ended December 31, 2010 of $168.0 million, or $3.19 per diluted share. These results compare to net income of $59.1 million, or $1.18 per diluted share, reported for the year ended December 31, 2009. The net income for 2009 included an after tax loss of $81.2 million, or approximately $1.62 per diluted share, on the impairment of goodwill in our rental tools reporting unit.

 

Revenues.  Consolidated revenues increased $303.7 million, or 14%, in 2010 compared to 2009.

 

Our well site services revenues increased $170.9 million, or 56%, in 2010 compared to 2009. This increase was primarily due to increased rental tool revenues and significantly increased rig utilization in our drilling services operations. Our rental tool revenues increased $108.9 million, or 47%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tool utilization and improved pricing. Our drilling services revenues increased $62.0 million, or 87%, in 2010 compared to 2009 primarily as a result of increased utilization of our rigs. Utilization of our drilling rigs increased from an average of approximately 37% in 2009 to an average of approximately 71% in 2010.

 

Our accommodations segment reported revenues in 2010 that were $56.3 million, or 12%, above 2009. The increase in accommodations revenue resulted from increased activity at our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, the expansion of two of these facilities and the strengthening of the Canadian dollar versus the U.S. dollar, partially offset by a $63 million decrease in third-party accommodations manufacturing revenues.

 

Our offshore products revenues decreased $80.5 million, or 16%, in 2010 compared to 2009. This decrease was primarily due to lower starting backlog levels, a decrease in subsea pipeline revenues and rig and vessel equipment revenues driven principally by reductions in our customers’ spending caused by deferrals and delays of deepwater development projects and capital upgrades.

 

Tubular services revenues increased $157.0 million, or 19%, in 2010 compared to 2009. This increase was a result of an increase in tons shipped from 330,800 in 2009 to 502,800 in 2010 driven by increased drilling activity, an increase of 172,000 tons, or 52%, partially offset by a 22% decrease in realized revenues per ton shipped in 2010.

 

Cost of Sales and Service.  Our consolidated cost of sales increased $234.1 million, or 14%, in 2010 compared to 2009. This increase was primarily as a result of increased cost of sales at our tubular services segment of $161.2 million, or 21%, an increase at our well site services segment of $97.8 million, or 43% and an increase at our accommodations segment of $35.7 million, or 13%, partially offset by a decrease in cost of sales at our offshore products segment of $60.6 million, or 16%. Our consolidated gross margin as a percentage of revenues was 22% in both 2010 and 2009.

 

Our well site services cost of sales increased $97.8 million, or 43%, in 2010 compared to 2009 as a result of a $50.5 million, or 30%, increase in rental tools services cost of sales and a $47.3 million, or 81%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 25% in 2009 to 32% in 2010. Our rental tool gross margin as a percentage of revenues increased from 28% in 2009 to 36% in 2010 primarily due to a more favorable mix of higher value rentals and improved pricing along with improved fixed cost absorption as a result of increased rental tool utilization. Our drilling services gross margin as a percentage of revenues increased from 18% in 2009 to 21% in 2010 primarily due to the increase in drilling activity levels.

Our accommodations cost of sales increased $35.7 million, or 13%, in 2010 compared to 2009 primarily as a result of increased activity at our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, the expansion of two of these facilities and the strengthening of the Canadian dollar versus the U.S. dollar, partially offset by a decrease in third-party accommodations manufacturing and installation costs. Our accommodations segment gross margin as a percentage of revenues was 42% in 2009 and 2010.

 

Our offshore products cost of sales decreased $60.6 million, or 16%, in 2010 compared to 2009 primarily due to a decrease in subsea pipeline and rig and vessel equipment costs. Our offshore products segment gross margin as a percentage of revenues was 26% in both 2009 and 2010.

 

Tubular services segment cost of sales increased $161.2 million, or 21%, in 2010 compared to 2009 primarily as a result of an increase in tons shipped driven by increased drilling activity, partially offset by lower priced OCTG inventory being sold. Our tubular services gross margin as a percentage of revenues decreased from 7% in 2009 to 5% in 2010 primarily due to a larger portion of service related costs expensed on certain program work.

 

Selling, General and Administrative Expenses.  SG&A expense increased $11.6 million, or 8%, in 2010 compared to 2009 due primarily to an increased accrual for incentive bonuses, increased salaries, wages and benefits and an increase in our accommodations SG&A expenses as a result of the strengthening of the Canadian dollar versus the U.S. dollar. SG&A was 6.3% of revenues in 2010 compared to 6.6% of revenues in 2009.

 

Depreciation and Amortization.  Depreciation and amortization expense increased $6.1 million, or 5%, in 2010 compared to 2009 due primarily to capital expenditures made during the previous twelve months largely related to our Canadian accommodations business, partially offset by decreased depreciation in our drilling services business where several major assets have become fully-depreciated.

 

Impairment of Goodwill.  We recorded a goodwill impairment of $94.5 million, before tax, in 2009. The impairment was the result of our assessment of several factors affecting our rental tools reporting unit. We did not record an impairment of goodwill in 2010.

 

Operating Income.  Consolidated operating income increased $136.9 million, or 115%, in 2010 compared to 2009 primarily as a result of the $94.5 million pre-tax goodwill impairment loss recognized in the second quarter of 2009, a $67.6 million increase in operating income from our well site services segment (excluding the goodwill impairment) primarily due to increased U.S. completion activity, the more favorable mix of higher value rentals, improved pricing and increased rental tool utilization in our rental tools operation and increased utilization of our rigs in our drilling services business, partially offset by a $20.4 million decrease in operating income from our offshore products segment. Operating income in 2010 included $7.0 million of transaction costs related to the three acquisitions made during the year.

 

Interest Expense and Interest Income.  Net interest expense increased $0.6 million, or 4%, in 2010 compared to 2009 due to an increase in non-cash interest expense related to the write-off of the remaining balance of debt issuance costs for our prior revolving credit facility, partially offset by reduced average debt levels in 2010. The weighted average interest rate on the company’s credit facilities was 3.6% in 2010 compared to 1.5% in 2009. Interest income increased as a result of increased cash balances in interest bearing accounts partially offset by the repayment during the first quarter of 2009 of a note receivable from Boots & Coots International Well Control, Inc. (Boots & Coots).

 

Income Tax Expense.  Our income tax provision for 2010 totaled $72.0 million, or 29.9% of pretax income, compared to $46.1 million, or 43.6% of pretax income, for 2009. The effective tax rate in 2009 was impacted by a significant portion of the goodwill impairment loss recognized during the period being nondeductible for tax purposes. Excluding the goodwill impairment, the effective tax rate for 2009 would have approximated 29.7%.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

 

We reported net income for the year ended December 31, 2009 of $59.1 million, or $1.18 per diluted share. These results compare to net income of $218.9 million, or $4.26 per diluted share, reported for the year ended December 31, 2008. The net income in 2009 included an after tax loss of $81.2 million, or approximately $1.62 per diluted share, on the impairment of goodwill in our rental tools reporting unit. Net income in 2008 included an after tax loss of $79.8 million, or approximately $1.55 per diluted share, on the impairment of goodwill in our tubular services and drilling reporting units. Net income in 2008 also included an after tax gain of $3.6 million, or approximately $0.07 per diluted share, on the sale of 11.51 million shares of common stock of Boots & Coots.

 

Revenues.  Consolidated revenues decreased $840.2 million, or 28%, in 2009 compared to 2008.

 

Our well site services revenues decreased $227.9 million, or 43%, in 2009 compared to 2008. This decrease was primarily due to reductions in both activity and pricing from the company’s North American drilling and rental tool operations as a result of the 42% year-over-year decrease in the North American rig count.

 

Our accommodations segment reported revenues in 2009 that were $54.3 million, or 13%, above 2008. The increase in the accommodations revenue resulted from the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and increased third-party accommodations manufacturing revenues, partially offset by lower accommodations activities in support of conventional oil and natural gas drilling activity in Canada and the weakening of the Canadian dollar versus the U.S. dollar.

 

Our rental tool revenues decreased $121.7 million, or 34%, in 2009 compared to 2008 primarily due to lower rental tool utilization and pricing primarily as a result of significantly reduced completion activity in the U.S. and greater competition.

 

Our drilling services revenues decreased $106.2 million, or 60%, in 2009 compared to 2008 primarily as a result of reduced utilization and pricing in all of our drilling operating regions. Our land drilling utilization averaged 36.7% during 2009 compared to 82.4% in 2008.

 

Our offshore products revenues decreased $18.8 million, or 4%, in 2009 compared to 2008. This decrease was primarily due to a decrease in bearing and connectors revenue due to deepwater development project award delays and a decrease in elastomer revenues as a result of reduced drilling and completion activity in North America. These decreases were partially offset by an increase in subsea pipeline revenues.

 

Tubular services revenues decreased $647.8 million, or 44%, in 2009 compared to 2008 as a result of a 46% decrease in tons shipped in 2009, resulting from fewer wells drilled and completed in the period, partially offset by a 2% increase in average selling prices. Although OCTG prices decreased throughout 2009, our average sales price realized increased from 2008 due to sales commitments made in 2008 that extended into 2009.

 

Cost of Sales and Service.  Our consolidated cost of sales decreased $594.8 million, or 27%, in 2009 compared to 2008 primarily as a result of decreased cost of sales at tubular services of $517.1 million, or 41%, and at well site services of $93.7 million, or 29%. Our overall gross margin as a percentage of revenues declined from 24% in 2008 to 22% in 2009 primarily due to lower margins realized in our tubular services and well site services segments during 2009.

 

Our well site services segment gross margin as a percentage of revenues declined from 40% in 2008 to 25% in 2009. Our rental tool gross margin as a percentage of revenues declined from 42% in 2008 to 28% in 2009 primarily due to significant reductions in drilling and completion activity in both the U.S. and Canada, which negatively impacted pricing and demand for our equipment and services. In addition, a portion of our rental tool costs do not change proportionately with changes in revenue, leading to reduced gross margin percentages. Our drilling services cost of sales decreased $56.0 million, or 49%, in 2009 compared to 2008 as a result of significantly reduced rig utilization and pricing in each of our drilling operating areas, which led to

significant cost reductions. This decline in drilling activity levels also resulted in our drilling services gross margin as a percentage of revenues decreasing from 36% in 2008 to 18% in 2009.

 

Our accommodations cost of sales included a $45.8 million increase in third-party accommodations manufacturing and installation costs, which were only partially offset by a reduction in costs stemming from the implementation of cost saving measures in response to the lower conventional oil and natural gas drilling activity levels in Canada and the weakening of the Canadian dollar versus the U.S. dollar. Our accommodations segment gross margin as a percentage of revenues was 42% in 2008 and 2009.

 

Our offshore products segment gross margin as a percentage of revenues was essentially flat (25% in 2008 compared to 26% in 2009).

 

Tubular services segment cost of sales decreased by $517.1 million, or 41%, as a result of lower tonnage shipped partially offset by higher priced OCTG inventory being sold. Our tubular services gross margin as a percentage of revenues decreased from 13% in 2008 to 7% in 2009 due to excess industry-wide OCTG inventory levels in 2009 resulting in lower margins.

 

Selling, General and Administrative Expenses.  SG&A expense decreased $3.8 million, or 3%, in 2009 compared to 2008 due primarily to decreases in accrued incentive bonuses. In addition, our costs decreased as a result of the implementation of cost saving measures, including headcount reductions and reductions in overhead costs such as travel and entertainment, professional fees and office expenses, in response to industry conditions. SG&A was 6.6% of revenues in 2009 compared to 4.9% of revenues in 2008 due to the significant decline in our revenues during 2009.

 

Depreciation and Amortization.  Depreciation and amortization expense increased $15.5 million, or 15%, in 2009 compared to 2008 due primarily to capital expenditures made during the previous twelve months.

 

Impairment of Goodwill.  We recorded a pre-tax goodwill impairment in the amount of $94.5 million in 2009. The impairment was the result of our assessment of several factors affecting our rental tools reporting unit. We recorded a pre-tax goodwill impairment in the amount of $85.6 million in 2008. The impairment was the result of our assessment of several factors affecting our tubular services and drilling reporting units.

 

Operating Income.  Consolidated operating income decreased $265.0 million, or 69%, in 2009 compared to 2008 primarily as a result of a decrease in operating income from our rental tool services and tubular operations.

 

Gain on Sale of Investment.  We reported a gain on the sale of investment of $6.2 million in 2008. The sale related to our investment in Boots & Coots common stock.

 

Interest Expense and Interest Income.  Net interest expense decreased by $5.1 million, or 26%, in 2009 compared to 2008 due to reduced debt levels and lower LIBOR interest rates applicable to borrowings under our revolving credit facilities. The weighted average interest rate on the company’s revolving credit facilities was 1.5% in 2009 compared to 3.9% in 2008. Interest income decreased as a result of the repayment in 2009 of a note receivable due from Boots & Coots and reduced cash balances in interest bearing accounts.

 

Equity in Earnings of Unconsolidated Affiliates.  Our equity in earnings of unconsolidated affiliates is $2.6 million, or 64%, lower in 2009 than in 2008 primarily due to the sale, in August of 2008, of our remaining investment in Boots & Coots.

 

Income Tax Expense.  Our income tax provision for the year ended December 31, 2009 totaled $46.1 million, or 43.6% of pretax income, compared to $154.2 million, or 41.3% of pretax income, for the year ended December 31, 2008. The higher effective tax rate in both years was primarily due to the impairment of goodwill, the majority of which was not deductible for tax purposes. Absent the goodwill impairment in 2009, our effective tax rate was favorably influenced by lower statutory rates applicable to our foreign sourced income.

Liquidity and Capital Resources

 

Our primary liquidity needs are to fund capital expenditures, which have in the past included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, increasing and replacing rental tools assets, adding drilling rigs, funding new product development and general working capital needs. In addition, capital has been used to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations and proceeds from borrowings.

 

Cash Provided by Operations

 

Cash totaling $96.6 million was provided by operations during the first six months of 2011 compared to cash totaling $85.9 million provided by operations during the first six months of 2010. During the first six months of 2011, $148.2 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services segment, increases in receivables in our Canadian accommodations business and increased raw materials inventory in our offshore products segment due to increased activity levels. During the first six months of 2010, $57.1 million was used to fund working capital, primarily due to increased OCTG inventory levels in our tubular services segment to meet increasing demand.

 

Cash totaling $230.9 million was provided by operations during the year ended December 31, 2010 compared to cash totaling $453.4 million provided by operations during the year ended December 31, 2009. During 2010, $100.0 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services and rental tool businesses and lower taxes payable, partially offset by a reduction in accounts receivable at our offshore products segment. In contrast, during 2009, $176.0 million was provided from net working capital reductions, primarily due to a reduction in accounts receivable and lower inventory levels, especially in our tubular services segment.

 

Cash Used in Investing Activities

 

Cash was used in investing activities during the six months ended June 30, 2011 and 2010 in the amount of $231.3 million and $74.2 million, respectively. Capital expenditures totaled $230.3 million and $76.1 million during the six months ended June 30, 2011 and 2010, respectively. Capital expenditures in both years consisted principally of purchases of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments.

 

Cash was used in investing activities during the years ended December 31, 2010 and 2009 in the amount of $889.7 million and $102.6 million, respectively. During the year ended December 31, 2010, we spent cash totaling $709.6 million, net of cash acquired, to acquire The MAC in Sydney, Australia to expand our accommodations business internationally, Mountain West Oilfield Service and Supplies, Inc. in Vernal, Utah, an accommodations business servicing the U.S. Rockies and the Bakken Shale region, and Acute in Houston, Texas, a provider of welding services to the energy industry worldwide for both onshore and offshore activities. The company funded the acquisition of The MAC with cash on hand and borrowings available under our five-year, $1.05 billion senior secured bank facilities. We funded the Acute and Mountain West acquisitions using cash on hand and our then existing credit facility. See Note 6 to the audited consolidated financial statements included in this registration statement for additional information about our senior secured bank facilities. There were no significant acquisitions made by the company during the year ended December 31, 2009.

 

Capital expenditures totaled $182.2 million and $124.5 million during the years ended December 31, 2010 and 2009, respectively. Capital expenditures in both years consisted principally of purchases of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments. In 2009, we received $21.2 million from Boots & Coots in full satisfaction of a note receivable due us.

 

We currently expect to spend a total of approximately $650 million for capital expenditures during 2011 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. We expect to

fund these capital expenditures with cash available, internally generated funds and borrowings under our revolving credit facilities or other corporate borrowings. The foregoing capital expenditure budget does not include any funds for opportunistic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed attractive to the Company.

 

Cash Provided by (Used in) Financing Activities

 

Net cash of $164.1 million was provided by financing activities during the six months ended June 30, 2011, primarily as a result of proceeds from the issuance of $600 million aggregate principal amount of 61/2% senior unsecured notes due in 2019 in the second quarter of 2011. We spent $12.6 million in financing costs in the first six months of 2011. A total of $6.7 million was provided by financing activities during the six months ended June 30, 2010, primarily as a result of the issuance of common stock as a result of stock option exercises.

 

Net cash of $649.0 million was provided by financing activities during the year ended December 31, 2010, primarily as a result of borrowings under our $1.05 billion credit facilities. Net cash of $296.8 million was used in financing activities during the year ended December 31, 2009, primarily as a result of free cash flow being used to pay off all amounts outstanding under our revolving credit facility.

 

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 economy, the 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 27, 2010, the Company announced that its Board of Directors authorized $100 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which expired on December 31, 2009. The Company presently has approximately 51.3 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2012. 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, 2011, we had not repurchased any shares pursuant to this board authorization.

 

Credit Facilities.  On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement (Credit Agreement). The Credit Agreement consists of a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The new facilities increased the total commitments available from $500 million under the previous facilities to $1.05 billion. In connection with the execution of the Credit Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $325 million to U.S. $700 million (including $200 million in term loans), and the total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $175 million to U.S. $350 million (including $100 million in term loans). The maturity date of the Credit Agreement is December 10, 2015. The aggregate principal of the term loans is repayable at a rate of 1.25% per quarter in 2011 and 2.5% per quarter thereafter. We currently have 19 lenders in our Credit Agreement with commitments ranging from $26.6 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, 2011, we had $296.5 million outstanding under the Credit Agreement and an additional $18.5 million of outstanding letters of credit, leaving $727.4 million available to be drawn under the facilities.

 

On July 13, 2011, The MAC entered into a A$150 million Facility Agreement with National Australia Bank Limited. The Facility Agreement replaces The MAC’s existing A$75 million revolving loan facility on substantially the same terms, including the maturity date of the Facility Agreement of November 30, 2013. As of June 30, 2011, there were no borrowings outstanding under this facility.

 

Our total debt represented 36.8% of our combined total debt and shareholders’ equity at June 30, 2011 compared to 35.9% at December 31, 2010 and 10.3% at June 30, 2010. As of June 30, 2011, the Company was in compliance with all of its debt covenants.

 

61/2% Notes.  On June 1, 2011, the Company sold $600 million aggregate principal amount of 61/2% Notes due 2019 through a private placement to qualified institutional buyers.

 

The 61/2% Notes are senior unsecured obligations of the Company and the Guarantors which bear interest at a rate of 61/2% 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 61/2% Notes at a redemption price of 106.500% 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 61/2% 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 61/2% Notes at redemption prices (expressed as percentages of principal amount) equal to 104.875% for the twelve-month period beginning on June 1, 2014, 103.250% for the twelve-month period beginning June 1, 2015, 101.625% for the twelve-month period beginning June 1, 2016 and 100.00% beginning on June 1, 2017, plus accrued and unpaid interest to the redemption date.

 

In connection with the note offering, the Company, the Guarantors of the 61/2% Notes and the initial purchasers entered into a registration rights agreement at the closing of the offering. Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions, use commercially reasonable efforts to file with the Commission and cause to become effective a registration statement relating to an offer to exchange the 61/2% Notes for an issue of Commission-registered 61/2% Notes with identical terms. If the exchange offer is not completed on or before the date that is 365 days after the closing date of this offering (the Target Registration Date), then the Company agreed to pay each holder of the 61/2% Notes liquidated damages in the form of additional interest in an amount equal to 0.25% per annum of the principal amount of notes held by such holder, with respect to the first 90 days after the Target Registration Date (which rate shall be increased by an additional 0.25% per annum for each subsequent 90-day period that such liquidated damages continue to accrue), in each case until the exchange offer is completed or the shelf registration statement is declared effective or is no longer required to be effective; provided, however, that at no time will the amount of liquidated damages accruing exceed in the aggregate 0.5% per annum. The maximum additional interest potentially payable pursuant to this provision would be $2.6 million.

 

The Company utilized approximately $515 million of the net proceeds of the 61/2% Note offering in June 2011 to repay borrowings under its senior secured 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 61/2% Notes, the Company entered into an Indenture (the Indenture), among the Company, 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 61/2% 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 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 Indenture contains customary events of default. As of June 30, 2011, the Company was in compliance with all covenants of the 61/2% Notes.

 

23/8% Notes.  As of June 30, 2011, we had classified the $175.0 million principal amount of our 23/8% Notes, net of unamortized discount, as a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date and, as a result, 23/8% Note holders could present their notes for conversion during the quarter following the June 30, 2011 measurement date. If a 23/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 23/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 23/8% Notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 23/8% Notes for conversion. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company common stock during the prescribed measurement periods. As of June 30, 2011, the recent trading prices of the 23/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. Based on recent trading patterns of the 23/8% Notes, we do not currently expect any significant amount of the 23/8% Notes to convert over the next twelve months. Should a holder convert their 23/8% Notes, we would utilize our existing credit facilities to fund the cash portion of the conversion value.

 

Contractual Cash Obligations

 

The following summarizes our contractual obligations at December 31, 2010 (in thousands):

 

 

 

 

Off-Balance Sheet Arrangements

 

As of June 30, 2011, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.

 

Tax Matters

 

Our primary deferred tax assets at December 31, 2010, were related to employee benefit costs for our 2001 Equity Participation Plan (Equity Participation Plan) deductible goodwill, inventory allowance for

obsolescence, foreign tax credit carryforwards and $5.6 million in available federal net operating loss carryforwards, or regular tax net operating losses (NOLs), as of that date. The regular tax NOLs will expire in varying amounts after 2011 if they are not first used to offset taxable income that we generate. Our ability to utilize a portion of the available regular tax NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. We currently believe that substantially all of our regular tax NOLs will be utilized. The company has utilized all federal alternative minimum tax net operating loss carryforwards.

 

Our income tax provision for the year ended December 31, 2010 totaled $72.0 million, or 29.9% of pretax income, compared to $46.1 million, or 43.6% of pretax income, for the year ended December 31, 2009. The effective tax rate in 2009 was impacted by a significant portion of the goodwill impairment loss recognized during the period being non-deductible for tax purposes. Excluding the goodwill impairment, the effective tax rate for 2009 would have approximated 29.7%.

 

There are a number of legislative proposals to change the U.S. tax laws related to multinational corporations. These proposals are in various stages of discussion. It is not possible at this time to predict how these proposals would impact our business or whether they could result in increased tax costs.

 

Critical Accounting Policies

 

In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.

 

There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results.

 

Accounting for Contingencies.  We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, insurance claims, warranty claims, contract claims and discontinued operations.

 

Tangible and Intangible Assets, including Goodwill.  Our goodwill totaled $475.2 million, or 15.8%, of our total assets, as of December 31, 2010. Our other intangible assets totaled $139.4 million, or 4.6%, of our total assets, as of December 31, 2010. The assessment of impairment on long-lived assets, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether a decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment losses.

 

We review each reporting unit, as defined in current accounting standards regarding goodwill and other intangible assets to assess goodwill for potential impairment. Our reporting units include rental tools, drilling, accommodations, offshore products and tubular services. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full impairment of goodwill at those reporting units as of December 31, 2008. As part of the goodwill impairment analysis, we estimate the implied fair value of each reporting unit (IFV) and compare the IFV to the carrying value of such unit (the Carrying Value). Because

none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process (a Level 3 fair value measurement). In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilize, depending on circumstances, trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is affected by future oil and natural gas prices, anticipated spending by our customers, and the cost of capital. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any. At the date of our annual goodwill impairment test, the IFV’s of our offshore products, accommodations and rental tools reporting units exceeded their Carrying Values by 240%, 231% and 158%, respectively.

 

As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the company to the sum of the IFV’s of all of our reporting units to assess the reasonableness of the IFV’s in the aggregate.

 

For our intangible assets, when facts and circumstances indicate a loss in value has occurred, we compare the Carrying Value of the intangible asset to the fair value of the intangible asset. For intangible assets that we amortize, we review the useful life of the intangible asset and evaluate each reporting period whether events and circumstances warrant a revision to the remaining useful life. We evaluate the remaining useful life of an intangible asset that is not being amortized each reporting period to determine whether events and circumstances continue to support an indefinite useful life.

 

Revenue and Cost Recognition.  We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.

 

Valuation Allowances.  Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.

 

Estimation of Useful Lives.  The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

 

Stock Based Compensation.  Since the adoption of the accounting standards regarding share-based payments, we are required to estimate the fair value of stock compensation made pursuant to awards under our Equity Participation Plan. An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the

amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.

 

Income Taxes.  In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes, to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.

 

Recent Accounting Pronouncements

 

In October 2009, the FASB issued an accounting standards update that modified the accounting and disclosures for revenue recognition in a multiple-element arrangement. These amendments, effective for fiscal years beginning on or after June 15, 2010 (early adoption was permitted), modify the criteria for recognizing revenue in multiple- element arrangements and the scope of what constitutes a non-software deliverable. The company early adopted this standard. The impact of these amendments was not material to the company’s reported results.

 

In December 2009, the FASB issued an accounting standards update which amends previously issued accounting guidance for the consolidation of variable interest entities (VIE’s). These amendments require a qualitative approach to identifying a controlling financial interest in a VIE, and requires ongoing assessment of whether an entity is a VIE and whether an interest in a VIE makes the holder the primary beneficiary of the VIE. These amendments are effective for annual reporting periods beginning after November 15, 2009. Adoption of this standard had no effect on our financial condition, results of operations or cash flows.

 

In January 2010, the FASB issued an accounting standards update which requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. These amendments were effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. The adoption of these amendments did not have a material impact on our disclosures.

 

In December 2010, the FASB issued an accounting standards update on disclosures of supplementary pro forma information for business combinations. These amendments specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. These amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. These amendments are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We early adopted the provisions of this amendment in 2010, and they are reflected in our pro forma disclosures included in Note 5 to the audited consolidated financial statements included in this registration statement.

 

In June 2011, the FASB issued amendments to disclosure requirements for the presentation of comprehensive income. This guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive

income. The amendments should be applied retrospectively. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is permitted, because compliance with the amendments is already permitted. The amendments do not require any transition disclosures. We do not expect the adoption of this amendment to have a material effect on our consolidated financial statements.

 

Quantitative and Qualitative Disclosure About Market Risk

 

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, 2011, we had floating-rate obligations totaling approximately $296.5 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 the floating interest rates increased by 1% from June 30, 2011 levels, our consolidated interest expense would increase by a total of approximately $3.0 million annually.

 

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., 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 first six months of 2011, our realized foreign exchange losses were $1.9 million and are included in other operating (income) expense in the condensed consolidated statements of income.

 

Some of our foreign operations are conducted through wholly-owned foreign subsidiaries that have functional currencies other than the United States dollar. We currently have subsidiaries whose functional currencies are the Canadian dollar and Australian dollar. Assets and liabilities from these subsidiaries are translated into United States dollars at the exchange rate in effect at each balance sheet date. The resulting translation gains or losses are reflected as accumulated other comprehensive income (loss) in the shareholders’ equity section of our consolidated balance sheets.

 

Our Company

 

Oil States, through its subsidiaries, is a leading provider of specialty products and services to natural resources companies throughout the world. We operate in a substantial number of the world’s active oil, natural gas and coal producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and Central Asia. Our customers include many national oil companies, major and independent oil and natural gas companies, onshore and offshore drilling companies, other oilfield service companies and mining companies. We operate in four principal business segments, accommodations, offshore products, well site services and tubular services, and have established a leadership position in certain of our product or service offerings in each segment.

 

Capital Spending and Acquisitions

 

Capital spending since our initial public offering in February 2001 has totaled approximately $1.4 billion and has included both growth and maintenance capital expenditures in each of our businesses as follows: accommodations, $747 million, rental tools, $304 million, drilling and other, $202 million, offshore products, $114 million, tubular services, $22 million and corporate, $4 million.

 

Since our initial public offering in February 2001, we have completed 39 acquisitions for total consideration of $1.2 billion. Acquisitions of other oilfield service businesses and, recently, in the accommodations business supporting the natural resources market in Australia, have been an important aspect of our growth strategy and plan to increase stockholder value. Our acquisition strategy has allowed us to expand our geographic locations and our product and service offerings. This growth strategy has allowed us to leverage our existing and acquired products and services into new geographic locations, and has expanded our technology and product offerings. We have made strategic acquisitions in our accommodations, offshore products, well site services and tubular services business lines.

 

On December 30, 2010, we acquired all of the ordinary shares of The MAC, through the Scheme under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the natural resources market. As of the acquisition date, The MAC had 5,210 rooms in six locations in Queensland and Western Australia. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. This price represents a total purchase price of $638 million, net of cash acquired plus debt assumed of $87 million. The company funded the acquisition with cash on hand and borrowings available under our five-year, $1.05 billion senior secured bank facilities. See Note 8 to the audited consolidated financial statements included in this registration statement for additional information on our senior secured bank facilities. The MAC’s operations are reported as part of our accommodations segment.

 

On December 20, 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 and estimated contingent consideration of $4.0 million. Headquartered in Vernal, Utah, with operations in the Rockies and the Bakken Shale region, Mountain West provides remote site workforce accommodations to the oil and gas industry. Mountain West has been included in the accommodations segment since its date of acquisition.

 

On October 5, 2010, we purchased all of the equity of Acute for total consideration of $30.2 million. Headquartered in Houston, Texas and with additional operations in Brazil, Acute provides metallurgical and welding innovations to the oil and gas industry in support of critical, complex subsea component manufacturing and deepwater riser fabrication on a global basis. Acute has been included in the offshore products segment since its date of acquisition.

 

We funded the Acute and Mountain West acquisitions using cash on hand and our then existing credit facility.

Our Industry

 

We operate principally in the oilfield services industry and provide a broad range of products and services to our customers through our accommodations, offshore products, well site services and tubular services business segments. We also own and operate accommodations in the natural resources market in Australia. 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, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services is highly sensitive to current and expected commodity prices. See Note 10 to the audited consolidated financial statements included in this registration statement for financial information by segment.

 

Our historical financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments. With the acquisition of The MAC, our results are also influenced by the level of activity in the natural resource market in Australia. For additional information about activities in each of our segments, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Our accommodations business is significantly influenced by the level of development of oil sands deposits in Alberta, Canada, activity levels in support of oil and gas development in Canada and the U.S. and, because of the acquisition of The MAC, in natural resource markets, primarily in Australia. Despite the downturn in 2009 and early 2010 as a result of the global financial crisis, activity in our accommodations business has grown significantly in the last five years.

 

Our offshore products segment, which is more influenced by deepwater development spending and rig and vessel construction and repair, experienced significantly increased backlog and revenues from 2005 to 2008, which resulted in improved operating results during 2006, 2007 and in 2008. A high level of backlog at the beginning of 2009 provided stability in offshore products revenues and profits in that year. However, due to project postponements, cancellations and deferrals that limited new order activity beginning in the fourth quarter of 2008 which continued throughout 2009 and led to backlog declines and decreased revenues and profits in 2010. Increased regulation of offshore drilling as a result of the Deepwater Horizon rig explosion and sinking in 2010 and resultant oil spill from the Macondo well blowout also delayed drilling and development operations in the U.S. offshore. However, with the improvement in oil prices over the last two years and the improved outlook for long-term oil demand, we began experiencing increased bidding and quoting activity for our offshore products beginning in the second half of 2010 and continuing throughout the first half of 2011. As a result of this increased activity, our backlog in offshore products has increased 150% since the beginning of 2010.

 

Our well site services businesses are significantly affected by movements in the North American rig count. Activity increased to peak levels during 2008, but saw material declines beginning in the fourth quarter of 2008 in most of our businesses, and continued through much of 2009. Activity levels in 2010 and the first half of 2011 improved significantly off their 2009 troughs. In particular, oil related drilling activities have recovered and are now at their highest levels in over 20 years; however, pricing for certain of our products and services has not recovered to prior peak levels.

 

Our tubular services business is influenced by the overall level of U.S. drilling activity, the types of wells being drilled, movements in global steel input prices and the overall industry level of OCTG inventory and pricing. Our tubular services business has historically been our most cyclical business segment. During 2008, this segment’s margins were positively affected in a significant manner by increasing prices for steel products, including the OCTG we sell. Declining OCTG prices in 2009 coupled with weaker demand for OCTG, caused by a decline in U.S. drilling, led to significantly lower revenues and margins for our tubular services business in 2009. The recovery in U.S. drilling activity in 2010 led to increased tubular services revenues. Although price increases were announced by the major U.S. mills during the first half of 2010, margins for our tubular services business declined in 2010 due primarily to a larger portion of service related costs expensed on certain program work.

Accommodations

 

Overview.  We are one of North America’s and Australia’s largest integrated providers of accommodations services for people working in remote locations. Our scalable modular facilities provide temporary and semi-permanent work force accommodations where traditional infrastructure is not accessible or cost effective. Once facilities are deployed in the field, we can also provide comprehensive facility management services, water and wastewater treatment, power generation, communications and redeployment logistics. Our accommodations are primarily employed to support work forces in the Canadian oil sands and in a variety of mining and related natural resource applications in Australia. We also support conventional oil and gas development efforts, forest fire fighting and disaster relief efforts, primarily in Canada, Australia and the U.S.

 

Accommodations Market.  Our accommodations business has grown in recent years due to the increasing demand for accommodations to support workers in the oil sands region of Canada. Demand for oil sands accommodations is influenced to a great extent by the longer-term outlook for energy prices rather than current energy prices, particularly crude oil prices, given the multi-year time frame to complete oil sands projects and the costs associated with development of such large scale projects. Utilization of our existing accommodations capacity and our future expansions will largely depend on continued oil sands development spending.

 

Beginning in 2011, as a result of our acquisition of The MAC, our accommodations business entered into the Australian natural resources market. The Australian natural resources market plays a vital role in the Australian economy. The growth of Australian natural resource commodity exports over the last decade has been largely driven by strong Asian demand for iron ore, coal and LNG. It is Australia’s largest contributor to exports, a major contributor to gross domestic product, a major employer and a major contributor to government revenue. The MAC’s current activities are primarily related to supplying accommodations in support of metallurgical coal mining.

 

Australia is a significant producer of most of the world’s key mineral commodities including iron ore, uranium, zinc, bauxite, lead, metallurgical and thermal coal and gold. It also has extensive oil and gas reserves with its major energy resource regions including the North West Shelf off the north coast of Western Australia and the onshore Cooper/Eromanga and Bowen/Surat Basins which straddle Queensland, New South Wales and South Australia.

 

Western Australia and Queensland are the most natural resource rich states. Western Australia produces a range of commodities including almost all of Australia’s iron ore from the Pilbara region in the northwest and gold and nickel from the Eastern Goldfields region around Kalgoorlie in the southeast. Queensland has significant deposits of metallurgical and thermal coal, lead, zinc, bauxite, gold and minerals sands. The Bowen Basin region of Queensland contains the largest metallurgical coal reserves in Australia and is becoming a major part of the rapidly developing east coast coal seam gas industry. The natural resources market is also a major contributor to economic activity in the other states of Australia (e.g. South Australia is home to the Olympic Dam mine, the fourth largest copper deposit and largest uranium deposit in the world).

 

Volumes and prices of commodities have historically varied significantly and are difficult to predict. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. Strong economic growth in emerging economies, such as China and India, with associated strong demand for mineral and natural gas resources such as coal, iron ore and LNG, has more than offset moderating growth in the U.S., Japan and Europe. This demand is expected to underpin continued investment and growth in the Australian natural resources market.

 

Products and Services.  Since mid-year 2006, we have installed over 8,000 rooms in four of our major lodge properties supporting oil sands activities in northern Alberta. Our growth plan for this area of our business includes the expansion of these properties where we believe there is durable long-term demand.

 

In December 2010, we acquired The MAC, which owns and operates six villages with over 5,200 rooms and has a significant development portfolio in Australia. The MAC provides accommodation services to mining and related service companies (including construction contractors) under medium-term contracts. The MAC villages are strategically located in proximity to long-life, low-cost mines operated by large mining

companies. The MAC’s villages are developments intended to be in operation for 15 plus years and comprise manufactured relocatable buildings, with two to six rooms per building. The accommodations are built around central facilities such as housing, kitchen, dining, retail, entertainment and fitness areas.

 

From 2007 to 2009 The MAC added 1,657 rooms (net of retirements) by expanding existing villages and opening new villages. During 2010, given the uncertain global economic outlook, it consolidated its position incurring only maintenance capital expenditure while retiring 278 rooms.

 

In addition to our large-scale lodge and village facilities, we offer a broad range of semi-permanent and mobile options to house workers in remote regions. Our fleet of temporary camps is designed to be deployed on short notice and can be relocated as a project site moves. Our camps range in size from a 25 person drilling camp to a 2,000 person camp supporting varied operations, including pipeline construction, Steam Assisted Gravity Drainage (SAGD) drilling operations and large shale oil projects.

 

We own two accommodations manufacturing plants near Edmonton, Alberta, Canada, and a manufacturing location in Adelaide, Australia, which specialize in the design, engineering, production, transportation and installation of a variety of portable modular buildings, predominately for our own use. We manufacture accommodations facilities to suit the climate, terrain and population of a specific project site.

 

Regions of Operations.  Our accommodations business is focused primarily in northern Canada and, more recently, in Queensland, Australia, but also operates in Western Australia, the U.S. Rocky Mountain corridor and the Bakken Shale region (Wyoming, Colorado, Utah and North Dakota), the Fayetteville Shale region of Arkansas and offshore locations in the Gulf of Mexico. In the past, we have also served companies operating in international markets including the Middle East, Europe, Asia and South America.

 

Customers and Competitors.  Our customers operate in a diverse mix of industries including primarily oil sands mining and development; drilling, exploration and extraction of oil and natural gas and coal and other extractive industries. To a lesser extent, we also operate in other industries, including pipeline construction, forestry, humanitarian aid and disaster relief, and support for military operations. Our primary competitors in North America include Aramark Corporation, Compass Group PLC, ATCO Structures and Logistics Ltd., Black Diamond Group Limited and Horizon North Logistics, Inc. Our primary competitors in Australia include Ausco Modular Pty Limited, Fleetwood Corporation Limited, Nomad Building Solutions Limited and Decmil Group Limited. Although not direct competitors, accommodations are sometimes owned and/or operated by our potential customers.

 

Offshore Products

 

Overview.  Through this segment, we design and manufacture a number of cost-effective, technologically advanced products for the offshore energy industry. In addition, we supply other lower margin products and services such as fabrication and inspection services. Our products and services are used mostly in deepwater producing regions and include flex-element technology, advanced connector systems, deepwater mooring systems, cranes, subsea pipeline products and installation and repair services. We have facilities in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil; England; Singapore; Thailand and India that support our offshore products segment.

 

Offshore Products Market.  The market for our offshore products and services depends primarily upon development of infrastructure for offshore production activities, drilling rig refurbishments and upgrades and new rig and vessel construction. Demand for oil and natural gas and related drilling and production in offshore areas throughout the world, particularly in deeper water, will drive spending on these activities.

 

Products and Services.  Our offshore products segment provides a broad range of products and services for use in offshore drilling and development activities. To a lesser extent, this segment provides onshore oil and natural gas, defense and general industrial products and services. Our offshore products segment is dependent in part on the industry’s continuing innovation and creative applications of existing technologies.

 

Offshore Development and Drilling Activities.  We design, manufacture, fabricate, inspect, assemble, repair, test and market subsea equipment and offshore vessel and rig equipment. Our products are components

of equipment used for the drilling and production of oil and natural gas wells on offshore fixed platforms and mobile production units, including floating platforms, such as Spars, tension leg platforms, floating production, storage and offloading (FPSO) vessels, and on other marine vessels, floating rigs, vessels and jack-up rigs. Our products and services include:

 

 

Flexible Bearings and Connector Products.  We are the principal supplier of flexible bearings, or FlexJoints^®, to the offshore oil and gas industry. We also supply weld-on connectors and fittings that join lengths of large diameter conductor or casing used in offshore drilling operations. FlexJoints^® are flexible bearings that permit the controlled movement of riser pipes or tension leg platform tethers under high tension and pressure. They are used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water areas. Drilling riser systems provide the vertical conduit between the floating drilling vessel and the subsea wellhead. Through the drilling riser, equipment is guided into the well and drilling fluids are returned to the surface. Production riser systems provide the vertical conduit for the hydrocarbons from the subsea wellhead to the floating production platform. Oil and natural gas flows to the surface for processing through the production riser. Export risers provide the vertical conduit from the floating production platform to the subsea export pipelines. FlexJoints^® are a critical element in the construction and operation of production and export risers on floating production systems in deepwater.

 

Floating production systems, including tension leg platforms, Spars and FPSO facilities, are a significant means of producing oil and gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. A tension leg platform is a floating platform that is moored by vertical pipes, or tethers, attached to both the platform and the sea floor. Our FlexJoint^® tether bearings are used at the top and bottom connections of each of the tethers, and our Merlin connectors are used to efficiently assemble the tethers during offshore installation. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. An FPSO is a floating vessel, typically ship shaped, used to produce, and process oil and gas from subsea wells. Our FlexJoints^® are also used to attach the steel catenary risers to a Spar, FPSO or tension leg platform and for use on import or export risers.

 

Subsea Pipeline Products.  We design and manufacture a variety of equipment used in the construction, maintenance, expansion and repair of offshore oil and natural gas pipelines. New construction equipment includes:

 

 

We provide diverless connection systems for subsea flowlines and pipelines. Our HydroTech^® collet connectors provide a high-integrity, proprietary metal-to-metal sealing system for the final hook-up of deep offshore pipelines and production systems. They also are used in diverless pipeline repair systems and in future pipeline tie-in systems. Our lateral tie-in sled, which is installed with the original pipeline, allows a subsea tie-in to be made quickly and efficiently using proven HydroTech^® connectors without costly offshore equipment mobilization and without shutting off product flow.

 

We provide pipeline repair hardware, including deepwater applications beyond the depth of diver intervention. Our products include:

 

 

Marine Winches, Mooring Systems, Cranes and Rig Equipment.  We design, engineer and manufacture marine winches, mooring systems, cranes and certain rig equipment. Our Skagit^® winches are specifically designed for mooring floating and semi-submersible drilling rigs and positioning pipelay and derrick barges, anchor handling boats and jack-ups, while our Nautilus^® marine cranes are used on production platforms throughout the world. We also design and fabricate rig equipment such as automatic pipe racking and blowout preventer handling equipment. Our engineering teams, manufacturing capability and service technicians who install and service our products provide our customers with a broad range of equipment and services to support their operations. Aftermarket service and support of our installed base of equipment to our customers is also an important source of revenue to us.

 

BOP Stack Assembly, Integration, Testing and Repair Services.  We design and fabricate lifting and protection frames and offer system integration of blow-out preventer stacks and subsea production trees. We can provide complete turnkey and design fabrication services. We also design and manufacture a variety of custom subsea equipment, such as riser flotation tank systems, guide bases, running tools and manifolds. In addition, we also offer blow-out preventer and drilling riser testing and repair services.

 

To a lesser extent, our offshore products segment also produces a variety of products for use in applications other than in the offshore oil and gas industry. For example, we provide:

 

 

Backlog.  Backlog in our offshore products segment $354 million at December 31, 2010, $206 million at December 31, 2009 and $362 million at December 31, 2008. Our offshore products backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. In some instances, these purchase orders are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. Our backlog is an important indicator of future offshore products shipments and revenues; however, backlog as of any particular date may not be indicative of our actual operating results for any future period. We believe that the offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. The change in backlog levels from one period to the next does not necessarily evidence a long-term trend.

 

Regions of Operations.  Our offshore products segment provides products and services to customers in the major offshore oil and gas producing regions of the world, including the Gulf of Mexico, West Africa, Azerbaijan, the North Sea, Brazil, Southeast Asia and India. We are currently expanding our capabilities in Southeast Asia by constructing a new facility in Singapore.

Customers and Competitors.  We market our products and services to a broad customer base, including direct end users, engineering and design companies, prime contractors, and at times, our competitors through outsourcing arrangements. Our largest customers in 2010 were Transocean Ltd., Halliburton Company and BP p.l.c.

 

Well Site Services

 

Overview.  Our well site services segment includes a broad range of products and services that are used to drill, and establish and maintain the flow of, oil and natural gas from a well throughout its lifecycle. In this segment, our operations include completion-focused rental tools and land drilling services. We use our fleet of drilling rigs and rental equipment to serve our customers at well sites and project development locations. Our products and services are used primarily in onshore applications throughout the exploration, development and production phases of a well’s life.

 

Well Site Services Market.  Demand for our drilling rigs and rental equipment has historically been tied to the level of oil and natural gas exploration and production activity. The primary driver for this activity is the price of oil and natural gas. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices.

 

Products and Services

 

Rental Equipment.  Our rental equipment business provides a wide range of products and services for use in the onshore and offshore oil and gas industry, including:

 

 

Our rental equipment is primarily used during the completion and production stages of a well. As of December 31, 2010, we provided rental equipment at 58 distribution points throughout the U.S., Canada, Mexico and Argentina compared to 64 distribution points at December 31, 2009. We continue to consolidate operations in areas where our product lines previously had separate facilities and close facilities in areas where operations are marginal in order to streamline operations, enhance our facilities and improve marketing efficiency. We provide rental equipment on a daily rental basis with rates varying depending on the type of equipment and the length of time rented. In certain operations, we also provide service personnel in connection with the equipment rental. We own patents covering some of our rental tools, particularly in our wellhead isolation equipment product line. Our customers in the rental equipment business include major, independent and private oil and gas companies and other large oilfield service companies. Competition in the rental tool business is widespread and includes many smaller companies, although we also compete with the larger oilfield service companies for certain products and services. The recovery in our industry during 2010 and the first half of 2011 resulted in a shortage of both equipment and personnel, contributing to both higher revenues and margins during 2010 and the first half of 2011 compared to comparable periods in the prior year.

 

Drilling Services.  Our drilling services business is located in the U.S. and provides land drilling services for shallow to medium depth wells ranging from 1,500 to 15,000 feet. Drilling services are typically used during the exploration and development stages of a field. As of June 30, 2011, we had a total of 34 semi-

automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 75,000 to 500,000 pounds. Twenty-two of these drilling rigs are based in Odessa, Texas and twelve are based in the Rocky Mountains region. Utilization of our drilling rigs increased from an average of 37% in 2009 to an average of 72% in 2010.

 

We market our drilling services directly to a diverse customer base, consisting of major, independent and private oil and gas companies. We contract on both footage and dayrate basis. Under a footage contract, we assume responsibility for certain costs (such as bits and fuel) and assume more risk (such as time necessary to drill) than we would on a daywork contract. Depending on market conditions and availability of drilling rigs, we see changes in pricing, utilization and contract terms. The land drilling business is highly fragmented, and our competition consists of a small number of larger companies and many smaller companies. Our Permian Basin drilling activities target primarily oil reservoirs while our Rocky Mountain drilling activities target both oil and natural gas reservoirs.

 

Tubular Services

 

Overview.  Through our Sooner, Inc. subsidiary, we distribute OCTG, which consists of downhole casing and production tubing. Through our tubular services segment, we:

 

 

We serve a customer base ranging from major oil and gas companies to small independents. Through our key relationships with more than 20 domestic and foreign manufacturers and related service providers and suppliers of OCTG, we deliver tubular products and ancillary services to oil and gas companies, drilling contractors and consultants predominantly in the U.S. The OCTG distribution market is highly fragmented and competitive, and is focused in the U.S. We purchase tubular goods from a variety of sources. However, during the year ended December 31, 2010, we purchased 56% of our total tubular goods from a single domestic supplier and 72% of our total OCTG purchases from three domestic suppliers.

 

OCTG Market.  Our tubular services segment primarily distributes casing and tubing. Casing forms the structural wall in oil and natural gas wells to provide support, control pressure and prevent collapse during drilling operations. Casing is also used to protect water-bearing formations during the drilling of a well. Casing is generally not removed after it has been installed in a well. Production tubing, which is used to bring oil and natural gas to the surface, may be replaced during the life of a producing well.

 

A key indicator of domestic demand for OCTG is the aggregate footage of wells drilled onshore and offshore in the U.S. The OCTG market is also affected by the level of inventories maintained by manufacturers, distributors and end users. Inventory on the ground, when at high levels, can cause tubular sales to lag a rig count increase due to inventory destocking and can put downward pressure on OCTG pricing. Demand for tubular products is positively impacted by increased drilling of deeper, horizontal and offshore wells. Deeper wells require incremental tubular footage and enhanced mechanical capabilities to ensure the integrity of the well. Premium tubulars are generally used in deeper wells and in horizontal drilling to withstand the increased bending and compression loading associated with a horizontal well. Operators typically specify premium tubulars for the completion of offshore wells.

 

Products and Services

 

Tubular Products and Services.  We distribute various types of OCTG produced by both domestic and foreign manufacturers to major and independent oil and gas exploration and production companies and other OCTG distributors. We have distribution relationships with most major domestic and certain international steel mills. We do not manufacture any of the tubular goods that we distribute. As a result, gross margins in this segment are generally lower than those reported by our other business segments. We operate our tubular services segment from a total of ten offices and facilities located near areas of oil and natural gas exploration and development activity.

In our tubular services segment, inventory management is critical to our success. We maintain on-the-ground inventory in five company-owned yards and approximately 60 third-party yards located in the U.S., giving us the flexibility to fill customer orders from our own stock or directly from the manufacturer. We have a proprietary inventory management system, designed specifically for the OCTG industry, which enables us to track our product shipments.

 

A-Z Terminal.  Our A-Z Terminal pipe maintenance and storage facility in Crosby, Texas is equipped to provide a full range of tubular services, giving us strong customer service capabilities. Our A-Z Terminal is on 109 acres, is an ISO 9001-certified facility, has a rail spur and more than 1,350 pipe racks and two double-ended thread lines. We have exclusive use of a permanent third-party inspection center within the facility. The facility also includes indoor chrome storage capability and patented pipe cleaning machines. We offer services at our A-Z Terminal facility typically outsourced by other distributors, including the following: threading, inspection, cleaning, cutting, logistics, rig returns, installation of float equipment and non-destructive testing.

 

Other Facilities.  We also offer tubular services at our facilities in Midland and Godley, Texas, Searcy, Arkansas and Montoursville, Pennsylvania. Our Midland, Texas facility covers approximately 60 acres and has more than 570 pipe racks. Our Godley, Texas facility, which services the Barnett shale area, has approximately 350 pipe racks on approximately 31 developed acres and is serviced by a rail spur. Our Searcy location has approximately 130 pipe racks on 14 acres. Our Montoursville location has approximately 150 pipe racks on 24 acres. Independent third party inspection companies operate within each of these facilities either with mobile or permanent inspection equipment.

 

Tubular Products and Services Sales Arrangements.  We provide our tubular products and logistics services through a variety of arrangements, including spot market sales and alliances. We provide some of our tubular products and services to independent and major oil and gas companies under alliance or program arrangements. Although our alliances are generally not as profitable as the spot market and can generally be cancelled by the customer, they provide us with more stable and predictable revenues and an improved ability to forecast required inventory levels, which allows us to manage our inventory more efficiently.

 

Regions of Operations.  Our tubular services segment provides tubular products and services principally to customers in the U.S. both for land and offshore applications. However, we also sell a small percentage for export worldwide.

 

Suppliers and Competitors.  Our largest supplier is U.S. Steel Group. Although we have a leading market share position in tubular services distribution, the market is highly fragmented. Our main competitors in tubular distribution are Bourland & Leverich Supply Company, L.C., McJunkin Red Man Corporation, Pipeco Services Inc. and Premier Pipe L.P.

 

Seasonality of Operations

 

Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, Australia, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian accommodations operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the second quarter and adversely affects our operations and sales of products and services. Our operations in the Gulf of Mexico are also affected by weather patterns. Weather conditions in the Gulf Coast region generally result in higher drilling activity in the spring, summer and fall months with the lowest activity in the winter months. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. In addition, summer and fall drilling activity can be restricted due to hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast. For example, during 2005, a significant disruption occurred in oil and natural gas drilling and production operations in the U.S. Gulf of Mexico due to damage inflicted by Hurricanes Katrina and Rita and, during 2008, from Hurricane Ike. Cyclones can affect our operations in Australia.

Employees

 

As of December 31, 2010, the Company had 6,904 full-time employees on a consolidated basis, 44% of whom are in our accommodations segment, 24% of whom are in our offshore products segment, 29% of whom are in our well site services segment, 2% of whom are in our tubular services segment and 1% of whom are in our corporate headquarters. We are party to collective bargaining agreements covering 1,689 employees located in Canada, Australia, the United Kingdom and Argentina as of December 31, 2010. We believe relations with our employees are good.

 

Government Regulation

 

Our business is significantly affected by foreign, federal, provincial, state and local laws and regulations relating to the oil and gas industry, worker safety and environmental protection. Changes in these laws, including more stringent regulations and increased levels of enforcement of these laws and regulations, could have a significant adverse effect on our business. We cannot predict changes in the level of enforcement of existing laws and regulations or how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our future operations or earnings. We also are not able to predict whether new laws and regulations will be adopted.

 

We depend on the demand for our products and services from oil and gas companies. This demand is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally, including those specifically directed to oilfield and offshore operations. The adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas in our areas of operation could also adversely affect our operations by limiting demand for our products and services. We cannot determine the extent to which our future operations and earnings may be adversely affected by new legislation, new regulations or changes in existing regulations or enforcement.

 

Some of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under states’ workers’ compensation laws inapplicable to these employees and permit them or their representatives generally to pursue actions against us for damages or job-related injuries with no limitations on our potential liability.

 

Our operations are subject to numerous stringent and comprehensive foreign, federal, state and local environmental laws and regulations governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with existing environmental laws and regulations and we do not anticipate that future compliance with existing environmental laws and regulations will have a material effect on our consolidated financial statements. However, there can be no assurance that substantial costs for compliance or penalties for non-compliance with these existing requirements will not be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities that we cannot currently quantify.

 

For example, in Canada, the Federal Government of Canada in September 2010 appointed an Oil Sands Advisory Panel to review and comment upon existing scientific studies and literature regarding water monitoring in the Lower Athabasca region and provide recommendations for improving such monitoring. The Oil Sands Advisory Panel presented its final report to the Minister of the Environment in December 2010. In response to the findings of the report, on March 25, 2011, the Federal Environment Minister of Canada, Peter Kent, announced the proposed launch of a new water pollution monitoring system in the oil sands that will include more frequent and widespread sampling and form part of a broader system that also will monitor air quality and the impact of development on the region’s wildlife. The development and implementation of such new monitoring system is expected to increase the level and cost of government oversight, which costs are to

be incurred by industry participants, under an industrial user pay system. Initial estimates to implement this monitoring system is $20 million (Canadian) per year.

 

Further, the Province of Alberta released a report in December 2010 regarding regulatory changes to be implemented in 2011 regarding Alberta Environment’s regulation of oil sands operations. The report suggests regulatory changes will include increased reclamation security requirements, increased monitoring requirements for water quality, and additional requirements for the management of tailings ponds. These changes, if and when they are implemented, may result in additional costs or liabilities for our customers’ operations.

 

Hazardous Wastes and Substances

 

With regard to our U.S. operations, we generate wastes, including “hazardous wastes,” which are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The EPA and analogous state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. Some wastes handled by us in our field service activities currently are exempt from treatment as hazardous wastes under RCRA because that act specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas from regulation as hazardous waste. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA requesting them to reconsider the RCRA exemption for exploration, production, and development wastes. To date, the EPA has not taken any action on the petition. Any re-designation of such currently RCRA exempt waste to hazardous waste in the future would subject us to more rigorous and costly operating and disposal requirements. In any event, such wastes currently remain subject to regulation under RCRA as solid wastes.

 

Some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM that are found on such properties.

 

The federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons in the U.S. that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that transported, disposed of, or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently have operations in the U.S. on properties that involve our handling of hazardous substances or where the activities involving the handling of hazardous substances may have been conducted prior to our operations on such properties or by third parties whose operations were not under our control. These properties may be subject to CERCLA, RCRA and analogous state laws. Under these laws and related regulations, we could be required to remove or remediate previously discarded hazardous substances and wastes or property contamination that was caused by these third parties. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.

Water Discharge

 

The Federal Water Pollution Control Act and analogous state laws impose restrictions and strict controls regarding the discharge of “pollutants” into waters of the U.S. and state waters. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Many of our domestic properties and operations require permits for discharges of wastewater and/or storm water, and we have procedures in place for securing and maintaining these permits. In addition, the Oil Pollution Act of 1990 imposes a variety of requirements on responsible parties related oil spills prevention and response planning and liability for damages, including natural resource damages, resulting from spills of oil in waters of the U.S. A responsible party includes the owner or operator of an onshore facility or a vessel, or the lessee or permittee of the area in which an offshore facility is located. The Federal Water Pollution Control Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act, impose substantial liabilities for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

 

A certain portion of our rental tools business supports other contractors actually performing hydraulic fracturing to enhance the production of natural gas from formations with low permeability, such as shales. Due to concerns raised in the U.S. concerning potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to impose new or more stringent permitting and compliance requirements for hydraulic fracturing. Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or FRAC Act, that would repeal an exemption in the federal Safe Drinking Water Act, or SWDA, for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. The EPA has already asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act, but the agency has not yet taken action to enforce or implement this recently asserted regulatory authority, and industry groups have filed suits challenging the EPA’s decision. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens on the oil and gas industry in general, and on our customers in particular, such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The Committee on Energy and Environment of the U.S. House of Representatives has been examining the practice of hydraulic fracturing in the U.S. and has gathered and reported information on its potential impacts on human health and the environment. Also, the EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health and anticipates that initial results of the study will be available in late 2012 and final results in 2014. Moreover, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult, or less economic, to complete natural gas wells in certain formations, increase our customers’ costs of compliance, and cause delays in permitting. Such regulatory and legislative efforts could have an adverse effect on oil and natural gas production activities by operators or other contractors with whom we have a business relationship, which in turn could have an adverse effect on demand for our North American completion products and services.

 

Offshore Regulation

 

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling rig resulting in an oil spill from a well known as the Macondo well and operated in the ultra deep water in the U.S. Gulf of

Mexico. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in May 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE (formerly the Minerals Management Service), of the U.S. Department of the Interior implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. In addition, while the moratorium was in place, BOEMRE issued a series of NTLS and implemented additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico. For example, before being allowed to resume drilling in deepwater, operators in the outer continental shelf waters of the U.S. Gulf of Mexico must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, blowout preventers, safety certification, emergency response and worker training. Operator must also demonstrate the availability of adequate spill response and blowout containment resources. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these various regulatory initiatives are fully implemented. In addition, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, including proposals in the previous session of Congress to significantly increase the minimum financial responsibility demonstration required under the federal Oil Pollution Act of 1990. Uncertainties and delays caused by the new regulatory environment have and will continue to have an overall negative effect on U.S. Gulf of Mexico drilling activity and, to a certain extent, the financial results of each of our business segments.

 

Air Emissions

 

Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act, or CAA, and analogous state laws require permits for facilities in the U.S. that have the potential to emit “pollutants” into the atmosphere that could adversely affect air quality. Failure to obtain a permit prior to construction of an air source or modification of an existing operation emitting pollutants or to comply with air quality permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties.

 

Past scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or GHG, and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, many foreign nations, including Canada, have agreed to limit emissions of these gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” In December 2002, Canada ratified the Kyoto Protocol, which requires Canada to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. The Canadian federal government previously released the “Regulatory Framework for Air Emissions,” updated March 10, 2008 by “Turning the Corner: Regulatory Framework for Industrial Greenhouse Emissions” (collectively, the “Regulatory Framework”) for regulating GHG emissions and in doing so proposed mandatory emissions intensity reduction obligations on a sector by sector basis. In addition, the Government of Canada has announced a number of regulatory changes to address GHG emissions from motor vehicles and coal fired electricity generation. These changes may have implications for our costs of operations.

 

On January 29, 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen. The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations is currently uncertain. Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 per cent reduction from 2005 levels by 2020, and the Canadian federal government has also indicated an objective of reducing overall Canadian GHG emissions by 60% to 70% by 2050. Additionally, in 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North America-wide cap and trade system for GHG emissions, in cooperation with the U.S. Under the system, Canada would have a

cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits. It is uncertain whether either federal GHG regulations or an integrated North American cap-and-trade system will be implemented, or what obligations might be imposed under any such systems.

 

Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets, and a company can meet the applicable emissions limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” by making payments of $15 per ton of GHG emissions to the Alberta Climate Change and Management Fund. The Alberta government recently announced its intention to raise the price of fund credits. The Specified Gas Reporting Regulation imposes GHG emissions reporting requirements if a company has GHG emissions of 100,000 tons or more from a facility in a year. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in permits and under other environmental regulations. The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. The direct and indirect costs of these regulations may adversely affect our operations and financial results as well as those of our customers.

 

Although the U.S. is not participating in the Kyoto Protocol, in December 2009, the U.S. EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production, processing, transmission, storage and distribution facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

 

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

 

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us or our customers to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas, which could reduce the demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Other Laws in Foreign Jurisdictions

 

Our operations outside of the U.S. are potentially subject to similar foreign governmental controls relating to protection of the environment. For example, our recently acquired Australian accommodations business is regulated by general statutory environmental controls at both the state and federal level. These controls include: the regulation of hard and liquid waste, including the requirement for trade waste and/or wastewater permits or licenses; the regulation of water, noise, heat, and atmospheric gases emissions; the regulation of the production, transport and storage of dangerous and hazardous materials (including asbestos); and the regulation of pollution and site contamination. Some specified activities, for example, sewage treatment works, may require regulation at a state level by way of environmental protection licenses which also impose monitoring and reporting obligations on the holder. National and state based regulations for the monitoring and reduction of GHG emissions have been proposed or commenced but no national mandatory emissions trading market has yet commenced. Federal requirements for the disclosure of energy performance under building rating regulations have been introduced and are to be expanded. These regulations require the tracking of specific environmental performance factors.

 

We believe that, to date, our operations outside of the U.S. have been in substantial compliance with existing requirements of these foreign governmental bodies and that such compliance has not had a material adverse effect on our operations. However, this trend of compliance with existing requirements may not continue in the future or the cost of such compliance may become material. For instance, any future restrictions on emissions of GHGs that are imposed in foreign countries in which we operate, such as in Canada and Australia, pursuant to the Kyoto Protocol or other locally enforceable requirements, could adversely affect demand for our services.

Properties

 

The following table presents information about our principal properties and facilities. For a discussion about how each of our business segments utilizes its respective properties, please see “Business.” Except as indicated below, we own all of these properties or facilities.