Helix Energy Solutions 10-Q 2011
Commission File Number 001-32936
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CONDENSED CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
The accompanying notes are an integral part of these condensed consolidated financial statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 – Basis of Presentation
The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "Helix" or the "Company"). Unless the context indicates otherwise, the terms "we," "us" and "our" in this report refer collectively to Helix and its majority-owned subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (“SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles.
The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our 2010 Annual Report on Form 10-K (“2010 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. The operating results for the periods ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Our balance sheet as of December 31, 2010 included herein has been derived from the audited balance sheet as of December 31, 2010 included in our 2010 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2010 Form 10-K.
Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including reclassifying the previously recorded results associated with our discontinued operations. The discontinued operations results are now reflected as a component of other income (expense) in the accompanying condensed consolidated statement of operations as such amounts are immaterial for all the periods presented in this Quarterly Report on Form 10-Q.
Note 2 – Company Overview
We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions. Our Oil and Gas segment engages in exploration, development and production activities. Our oil and gas operations are exclusively located in the Gulf of Mexico.
Contracting Services Operations
We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics. Our “life of field” services are segregated into four disciplines: subsea construction, well operations, robotics and production facilities. We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily includes subsea construction, deepwater pipelay, well operations and robotics activities. Our Production Facilities business includes our equity investment in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) as well as our majority ownership of the Helix Producer I (“HP I”) vessel. We have developed a response system that has been referenced as a designated spill response resource in Gulf of Mexico permit applications (see “Events in Gulf of Mexico” below), which is also a component of our Production Facilities segment.
Oil and Gas Operations
We began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand off-season utilization of our contracting services assets and to achieve incremental returns. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be explored and developed. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.
Events in Gulf of Mexico
In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252. The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill, the magnitude of which was unprecedented in U.S. territorial waters. In May 2010, the U.S. Department of Interior (“DOI”) announced a total moratorium on new drilling in the Gulf of Mexico. In October 2010, the DOI lifted the drilling moratorium and instructed the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) that it could resume issuing drilling permits conditioned on the requesting company’s compliance with all revised drilling, safety and environmental requirements. No post moratorium deepwater drilling permits were issued by BOEMRE until late February 2011.
We developed the Helix Fast Response System (“HFRS”) as a culmination of our experience as a responder in the Gulf oil spill response and containment efforts. The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Gulf oil spill response and containment efforts and are presently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS be deployed in connection with a well control incident. The retainer fee for the HFRS became effective April 1, 2011 and is a component of our Production Facilities business segment. A total of 38 permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME requirement to have a spill response and containment resource included in the submitted permit applications.
New Accounting Pronouncement
In June 2011, the Financial Accounting Standards Board (“FASB”) issued an update to existing guidance on the presentation of comprehensive income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. We will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012 and are currently evaluating the provisions of this updat.
Note 3 – Details of Certain Accounts
Other current assets consisted of the following as of September 30, 2011 and December 31, 2010:
Other assets, net, consisted of the following as of September 30, 2011 and December 31, 2010:
Accrued liabilities consisted of the following as of September 30, 2011 and December 31, 2010:
Note 4 – Oil and Gas Properties
We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of drilling and equipping successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are charged to expense in the period in which the drilling is determined to be unsuccessful.
Depletion expense is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves. Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field. The depletion rates are changed whenever there is an indication of the need for a revision, but at a minimum, are evaluated annually. Any such revisions are accounted for prospectively as a change in accounting estimate.
During the third quarter of 2011, we recorded a total of $2.4 million of impairment charges primarily related to revisions in cost estimates for reclamation activities ongoing at two of our Gulf of Mexico oil and gas properties. For the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for our only non-domestic oil and gas property (see “United Kingdom Property” below), and for six of our Gulf of Mexico oil and gas properties. These impairment charges primarily reflect a premature end of these fields’ production life either through actual depletion or as a result of capital allocation decisions affecting our third party operated fields. We did not have any impairment of our oil and gas properties during the three-month period ended March 31, 2011.
Following the determination of a significant reduction in our estimates of proved reserves at June 30, 2010, we recorded oil and gas property impairment charges totaling $159.9 million which affected the carrying value of 15 of our Gulf of Mexico oil and gas properties. In the first quarter of 2010, we recorded $7.0 million of impairment charges primarily resulting from natural gas price declines since year end 2009. The three properties subject to these impairment charges produce natural gas almost entirely. Separately, we also recorded a $4.1 million impairment charge for our United Kingdom oil and gas property.
Exploration and Other
As of September 30, 2011, we capitalized approximately $4.6 million of costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur.
The following table details the components of exploration expense for the three- and nine-month periods ended September 30, 2011 and 2010 (in thousands):
United Kingdom Property
Since 2006, we have maintained an ownership interest in the Camelot field, located offshore in the North Sea. In 2007, we sold half of our 100% working interest in Camelot to a third party with whom we agreed to jointly pursue future development and production of the field. In February 2010, we acquired this third party and thereby assumed the obligations, most notably the asset retirement obligation, related to its 50% working interest in the field. We recorded an approximate $6.0 million gain on the acquisition of the remaining working interest in Camelot, including the acquired entity’s $10.2 million of cash (see Note 5 of 2010 Form 10-K).
In connection with this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, we concluded that the Camelot field was impaired based on the unlikely probability of our expending the additional capital necessary to further develop the field. As a result, we recorded a $4.1 million impairment charge to fully impair the property in the first quarter of 2010. We are currently abandoning the field in accordance with applicable United Kingdom regulations. In connection with these activities, we continue to evaluate our estimated future field abandonment costs for the field. These evaluations resulted in our recording an incremental $4.1 million impairment charge in the second quarter of 2011 to increase the field’s estimated reclamation liability. Our current estimated asset retirement obligation for the Camelot field totals $11.6 million at September 30, 2011. We have incurred approximately $4.8 million of costs related to our reclamation activities at the Camelot field through September 30, 2011.
Asset retirement obligations
The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2010 (in thousands):
We carry comprehensive insurance for our operated and non-operated producing and non-producing properties. We record our hurricane-related costs as incurred. Insurance reimbursements are recorded when the realization of the claim for recovery of a loss is deemed probable. In 2011, our hurricane-related costs have been immaterial. Hurricane-related costs, net of reimbursements totaled $0.9 million and $4.6 million for the three-month and nine-month periods ended September 30, 2010. Our insurance reimbursements totaled $5.0 million for the nine-month period ended September 30, 2011. On June 30, 2011, we renewed our hurricane catastrophic bond for the period from July 1, 2011 to June 30, 2012 and made a payment of $10.6 million. We recorded a charge of approximately $8.4 million to insurance expense in the third quarter of 2011 to reduce the value of our hurricane catastrophic bond to its intrinsic value at September 30, 2011. We will record a $2.0 million charge to insurance expense in the fourth quarter of 2011.
Note 5 – Statement of Cash Flow Information
We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. We had restricted cash totaling $34.6 million at September 30, 2011 and $35.3 million at December 31, 2010, all of which was related to funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field. We have fully satisfied the escrow requirements under the escrow agreement. We have used a small portion of these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field. Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts. These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.
The following table provides supplemental cash flow information for the nine-month period ended September 30, 2011 and 2010 (in thousands):
Non-cash investing activities for the nine-month periods ended September 30, 2011 and 2010 included $34.8 million and $17.5 million, respectively, of accruals for capital expenditures. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.
Note 6 – Equity Investments
As of September 30, 2011, we have three investments that we account for using the equity method of accounting: Deepwater Gateway, Independence Hub, and Clough Helix Joint Venture Pty Ltd. (“Clough Helix JV”). Deepwater Gateway and Independence Hub are included in our Production Facilities segment while the Clough Helix JV is a component of our Contracting Services segment.
Note 7 – Long-Term Debt
Scheduled maturities of long-term debt outstanding as of September 30, 2011 were as follows (in thousands):
At September 30, 2011, unsecured letters of credit issued totaled approximately $42.6 million (see “Credit Agreement” below). These letters of credit primarily guarantee various contract bidding, contractual performance, including asset retirement obligations, and insurance activities. The following table details our interest expense and capitalized interest for the three- and nine-month periods ended September 30, 2011 and 2010:
Included below is a summary of certain components of our indebtedness. For additional information regarding our debt see Note 9 of our 2010 Form 10-K.
Senior Unsecured Notes
In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Interest on the Senior Unsecured Notes is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008. The Senior Unsecured Notes are fully and unconditionally guaranteed by substantially all of our existing restricted domestic subsidiaries, except for Cal Dive I-Title XI, Inc. In addition, any future restricted domestic subsidiaries that guarantee any of our indebtedness and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes. Our foreign subsidiaries are not guarantors.
During the three-month period ended September 30, 2011, we purchased a portion of our Senior Unsecured Notes that resulted in the early extinguishment of an aggregate $75.0 million of those notes. In these transactions we paid an aggregate amount of $77.4 million, including the $75.0 million in principal and $2.4 million in premium for the repurchased Senior Unsecured Notes. The premium is reflected as a component of “other income (expense)” in the accompanying condensed consolidated statements of operations. We also paid the accrued interest on these Senior Unsecured Notes totaling
$0.8 million and we recorded a $0.9 million charge to interest expense to accelerate a pro rata portion of the deferred financing costs associated with the issuance of the Senior Unsecured Notes in 2007.
In July 2006, we entered into a credit agreement (the “Credit Agreement”) containing both a term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”). The $835 million term loan was used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation in July 2006. The original borrowing capacity under the Revolving Credit Facility was $300 million. In June 2011, we amended our Credit Agreement as further discussed below. For additional information regarding the previous terms of our Credit Agreement see Note 9 of our 2010 Form 10-K.
The fourth amendment to our Credit Agreement, among other things:
With the closing of the fourth amendment, the Term Loan currently bears interest either at the one-, two-, three- or six-month LIBOR or Base Rates at our election plus a margin of between 3.25% and 3.5% (LIBOR margin) or 2.25% to 2.5% (Base Rate margin) depending on current leverage ratios. Our average interest rate on the Term Loan for the nine-month periods ended September 30, 2011 and 2010 was approximately 3.6% and 2.9%, respectively, including the effects of our interest rate swaps (Note 16).
As the rates for our Term Loan are subject to market influences and will vary over the term of the Credit Agreement, we may enter into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan (Note 16).
The full amount of the Revolving Credit Facility may be used for issuances of letters of credit. At September 30, 2011, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $557.4 million, net of $42.6 million of letters of credit issued.
Pursuant to the fourth amendment, the borrowings outstanding under the Revolving Credit Facility will bear interest based on one-, two-, three- or six-month LIBOR rates or on Base Rates at our election plus an applicable margin. The LIBOR margin ranges from 2.5% to 3.5% and the Base Rate margin rates from 1.5% to 2.5%, depending on our consolidated leverage ratio. In connection with the closing of the fourth amendment to our Credit Agreement (as noted above), we borrowed $109.4 million under the Revolving Credit Facility and prepaid a portion of the Term Loan. We subsequently repaid all borrowings under our Revolving Credit Facility with our available cash on hand. There were no borrowings outstanding on the Revolving Credit Facility at any time during the third quarter of 2011.
The Credit Agreement contains various covenants regarding, among other things, collateral, capital expenditures, investments, dispositions, indebtedness and financial performance that are customary for this type of financing and for companies in our industry.
Convertible Senior Notes
In March 2005, we issued $300 million of Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.
The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet. No conversion triggers were met during either the three- or nine-month periods ended September 30, 2011 and September 30, 2010. The first dates for early redemption of the Convertible Senior Notes are in December 2012, with the holders of the Convertible Senior Notes being able to put them to us on December 15, 2012 and our being able to call the Convertible Senior Notes at any time after December 20, 2012 (see Note 9 of our 2010 Form 10-K). Effective January 1, 2009, we adopted certain accounting standards that required us to discount the principal amount of our Convertible Senior Notes. Following adoption of these accounting standards, the effective interest rate for the Convertible Senior Notes is 6.6%.
Our average share price was below the $32.14 per share conversion price for all the periods presented in this Quarterly Report on Form 10-Q. As a result of our share price being lower than the $32.14 per share conversion price for these periods there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is payable in cash, and such shares would be issued on conversion. The Convertible Senior Notes are convertible into a maximum of 13,303,770 shares of our common stock.
This U.S. government guaranteed financing ("MARAD Debt") pursuant to Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. The MARAD Debt is collateralized by the Q4000 and 50% of the debt is guaranteed by us. The MARAD Debt initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same February 2027 maturity date.
In accordance with our Credit Agreement and our Senior Unsecured Notes, Convertible Senior Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness. As of September 30, 2011, we were in compliance with these covenants and restrictions.
Deferred financing costs of $28.0 million and $25.7 million are included in other assets, net as of September 30, 2011 and December 31, 2010, respectively, and are being amortized over the life of the applicable loan agreements. We incurred $9.2 million of deferred financing costs related to the fourth amendment to our Credit Agreement and charged $0.8 million of deferred financing costs to interest expense associated with the repayment of $109.4 million of our Term Loan balance in June 2011 (see “Credit Agreement” above). In the third quarter of 2011, we charged $0.9 million of deferred financing costs to interest expense associated with purchases and early extinguishment of a portion of our Senior Unsecured Notes (see “Senior Unsecured Notes” above).
Note 8 – Income Taxes
The effective tax rates for the three-month and nine-month periods ended September 30, 2011 were 33.4% and 29.9%, respectively. The effective tax rates for the three-month and nine-month periods ended September 30, 2010 reflected a provision of 40.0% and a benefit of 35.8%, respectively. The variance of the comparable year-over-year periods primarily reflect the increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions. Our effective tax rate increased in the third quarter of 2011, primarily reflecting increased profitability in our U.S. operations and certain losses associated with our Australian operations that are nondeductible for income tax purposes.
We believe our recorded assets and liabilities are reasonable. However, because tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.
Note 9 – Comprehensive Income (Loss)
The components of total comprehensive income (loss) for the three and nine-month periods ended September 30, 2011 and 2010 were as follows (in thousands):
The components of accumulated other comprehensive income (loss) were as follows (in thousands):
Note 10 – Earnings Per Share
We have shares of restricted stock issued and outstanding, some of which remain subject to certain vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings from continuing operations. For periods in which we have a net loss we do not use the two class method as holders of our restricted shares are not contractually obligated to share in such losses.
The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands):
We had a net loss from continuing operations for the nine-month period ended September 30, 2010. Accordingly, we had no dilutive securities during this reporting period as their inclusion would have had an anti-dilutive effect on our EPS calculation, meaning it would have increased our reported EPS amount. The following table provides the effect the excluded securities would have had on our diluted shares calculation for the nine-month period ended September 30, 2010 assuming we had earnings from continuing operations (in thousands):
Note 11 – Stock-Based Compensation Plans
We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”). As of September 30, 2011, there were 985,070 shares available for grant under our 2005 Incentive Plan.
There were no stock option grants in the three- and nine-month periods ended September 30, 2011 and 2010. During the nine-month period ended September 30, 2011, we made the following restricted share grants to executive officers, selected management employees and non-employee members of the board of directors under the 2005 Incentive Plan:
Compensation cost is recognized over the applicable vesting periods on a straight-line basis. For the three- and nine-month periods ended September 30, 2011, $1.9 million and $6.8 million, respectively, was recognized as compensation expense related to restricted shares as compared with $2.1 million and $6.7 million during the three- and nine-month periods ended September 30, 2010, respectively.
In January 2009, we adopted the 2009 Long-Term Incentive Cash Plan (the “2009 LTI Plan”) to provide long term cash-based compensation to eligible employees. Under the terms of the 2009 LTI Plan, the majority of the cash awards are fixed sum amounts payable annually over a five-year vesting period. Some of the cash awards, however, are indexed to the Company’s common stock price and the payment amount at each vesting date will fluctuate based on the common stock’s performance. As a result, the compensation expense associated with those awards is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.
Total compensation expense under the 2009 LTI plan totaled $0.4 million and $5.0 million for the three- and nine-month periods ended September 30, 2011, respectively. For the three- and nine-month periods ended September 30, 2010, total compensation under the 2009 LTI plan totaled $0.8 million and $3.4 million, respectively. The liability balance under the 2009 LTI Plan was $7.0 million at September 30, 2011 and $7.9 million at December 31, 2010, including $5.8 million at September 30, 2011 and $6.2 million at December 31, 2010 associated with the variable portion of the 2009 LTI plan.
For more information regarding our stock-based compensation plans, including our 2009 LTI Plan see Note 12 of our 2010 Form 10-K.
Note 12 – Business Segment Information
Our operations are conducted through two lines of business: contracting services and oil and gas. We have disaggregated our contracting services operations into two reportable segments. As a result, our reportable segments consist of the following: Contracting Services, Production Facilities and Oil and Gas. Contracting Services operations include subsea construction, deepwater pipelay, well operations and robotics. The Production Facilities segment includes our consolidated investment in the HP I and Kommandor LLC, as well as the retainer fee related to the HFRS and our equity investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method of accounting.
We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. All material intercompany transactions between the segments have been eliminated.
Intercompany segment revenues during the three- and nine-month periods ended September 30, 2011 and 2010 were as follows:
Intercompany segment gross profit (losses) during the three- and nine-month periods ended September 30, 2011 and 2010 were as follows: