Helix Energy Solutions - 10-Q quarterly report FY

Form 10-Q

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

(281) 618–0400

 

NOT APPLICABLE

 

 

 

 

 

TABLE OF CONTENTS

 

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 (in thousands)

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 (in thousands, except per share amounts)

 

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 (in thousands, except per share amounts)

 

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 (in thousands)

 

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 (in thousands)

(Continued)

 

 

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

Note 1 – Basis of Presentation

 

 

Note 2 – Company Overview

 

We are an international offshore energy company that provides development solutions and other key life of field contracting services to the energy market as well as to our own oil and gas business unit.  Our Contracting Services segment utilizes our vessels, offshore equipment and proprietary technologies 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 Gulf of Mexico, North Sea, Asia Pacific and Middle East regions. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. Our oil and gas operations are almost 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, particularly from marginal fields. By “marginal”, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our “life of field” services are segregated into four disciplines: construction, well operations, drilling, and production facilities. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”)

 

Oil and Gas Operations

In 1992 we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services business and to achieve incremental returns to our contracting services. Since 1992, we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. 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.

 

Discontinued Operations

 

Economic Outlook

The economic downturn and weakness in the equity and credit capital markets continue to lead to increased uncertainty regarding the outlook of the global economy.  This uncertainty, coupled with the negative near-term outlook for global demand for oil and natural gas, resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008. A decline in oil and gas prices negatively impacts our operating results and cash flows.   Our stock price also significantly declined over the second half of 2008.  The declines in our stock price and the prices of oil and natural gas were considered in association with our required annual impairment assessment of goodwill and properties at year end 2008, which resulted in significant impairment charges (see Note 2 of our 2008 Form 10-K).  Our stock price decreased further in the first quarter of 2009 resulting in our assessment of our goodwill amounts as of March 31, 2009; however, no further impairments were required.   Our stock price increased in the second quarter of 2009 and no assessment of goodwill was performed at June 30, 2009; however, we are required to continue to monitor our remaining $77.5 million of goodwill as of June 30, 2009, all of which is attributed to our Contracting Services segment.

 

Our Contracting Services segment may also be negatively impacted by low commodity prices as some of our customers, primarily oil and gas companies, have recently announced their intention to reduce capital spending.  We forecast weaker demand for our contracting services for the remainder of 2009.   With respect to our oil and gas operations, we hedged the price risk for a significant portion of our anticipated oil and gas production for 2009 when we entered into commodity hedges during 2008.   These hedge contracts enable us to minimize our near-term cash flow risks related to declining commodity prices.   As of August 5, 2009, the prices for these contracts are significantly higher than the forward market prices for both crude oil and natural gas over the remainder of 2009.   In March 2009, we entered into additional derivative contracts for a portion of our forecasted 2010 natural gas production.  In the

 

Note 3 – Recent Accounting Pronouncements

 

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The FASB agreed to defer the effective date of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We adopted the provisions of SFAS No. 157 on January 1, 2008 for assets and liabilities not subject to the deferral and adopted this standard for all other assets and liabilities on January 1, 2009.  The adoption of SFAS No. 157 had no material impact on our results of operations, financial condition and liquidity.

 

SFAS No. 157, among other things, defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. SFAS No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

 

 

 

 

 

 

 

In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51(“SFAS No. 160”). SFAS No. 160 improves the relevance, comparability, and transparency of financial information provided to investors by requiring all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. We adopted SFAS No. 160 on January 1, 2009, which is required to be adopted prospectively, except the following provisions must be adopted retrospectively:

 

 

In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS No. 161”).  SFAS 161 applies to all derivative instruments and related hedged items accounted for under SFAS No. 133.  SFAS No. 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions.   We adopted the provisions of SFAS No. 161 on January 1, 2009 and it had no impact on our results of operations, cash flows or financial condition.  See Note 19 below for additional disclosure regarding our derivative instruments.

 

 

 

 

 

Note 4 – Reduction in Ownership of Cal Dive

 

 

On June 10, 2009, we sold 20 million shares of Cal Dive held by us pursuant to a secondary public offering (“Offering”).  Proceeds from the Offering totaled approximately $161.9 million, net of underwriting fees.  Separately, pursuant to a Stock Repurchase Agreement with Cal Dive, simultaneously with the closing of the Offering, Cal Dive repurchased from us approximately 1.6 million shares of its common stock for net proceeds of $14 million at $8.50 per share, the Offering price. Following the closing of these two transactions, our ownership of Cal Dive common stock was reduced to approximately 28%.  On June 18, 2009, the underwriters sold an additional 2.6 million shares of Cal Dive shares held by us pursuant to their overallotment option under the terms of the Offering.  We received approximately $21.0 million of proceeds, net of underwriting fees, from such sale and our ownership of Cal Dive was reduced to our current approximate 26%.    Because these transactions reduced our ownership in Cal Dive to less than 50%, the $59.4 million gain resulting from the sale of these shares is reflected in “Gain on sale of Cal Dive common stock” in the accompanying condensed consolidated statement of operations.  The $59.4 million amount included an approximate $27.1 million gain associated with the re-measurement of our remaining 26% ownership interest in Cal Dive at its fair value on June 10, 2009, the date of deconsolidation.   Since we no longer hold a controlling interest in Cal Dive, we no longer consolidate Cal Dive effective June 10, 2009, and prospectively we will be accounting for our remaining ownership interest in Cal Dive under the equity method of accounting until we no longer have significant influence on Cal Dive’s future business decisions.

 

Note 5 – Insurance Matters

 

In September 2008, we sustained damage to certain of our facilities resulting from Hurricane Ike.  All of our segments were affected by the hurricane; however, the oil and gas segment suffered the substantial majority of our aggregate damages.   While we sustained damage to our own production facilities from Hurricane Ike, the larger issue in terms of our production recovery involved damage to third party pipelines and onshore processing facilities. The timing of the repairs of these facilities was not subject to our control and some of these third party facilities remain out of service as of August 5, 2009.  Our insurance policy, which covered all of our operated and non-operated producing and non-producing properties, was subject to an approximate $6 million of aggregate deductibles.  We met our aggregate deductible in September 2008.  We record our hurricane-related repair costs as incurred in our oil and gas cost of sales.   We record insurance reimbursements when the realization of the claim for recovery of a loss is deemed probable.

 

 

The following table summarizes the claims and reimbursements by segment that affected our costs of sales accounts under various insurance claims resulting from damages sustained by Hurricane Ike, primarily those claims and reimbursement recently settled under our energy insurance policy (in thousands):

 

 

After considerable negotiations we renewed our energy and marine insurance for the period July 1, 2009 to June 30, 2010.  However, this insurance renewal did not include wind storm coverage as the premium and deductibles would have been relatively substantial for the underlying coverage provided.   In order to mitigate potential loss to our most significant oil and gas properties from hurricanes in the Gulf of Mexico, we entered into a weather derivative (Catastrophic Bonds).   The Catastrophic Bonds provide for payments of negotiated amounts should the eye of a Category 3 or greater hurricane pass within certain pre-defined areas encompassing our more prominent oil and gas producing fields.   The cost of these Catastrophic Bonds totaled approximately $13 million and the premium will be amortized over the next twelve months.

 

Note 6 – Details of Certain Accounts (in thousands)

 

 

 

 

 

 

 

 

 

Note 7 – Convertible Preferred Stock

 

In January 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible stock (Series A-1 Cumulative Convertible Stock, par value $0.01 per share) convertible into 1,666,668 shares of our common stock at $15 per share.  The preferred stock was issued to a private investment firm, Fletcher International, Ltd. (“Fletcher”).  Subsequently on June 2004, Fletcher exercised an existing right to purchase an additional $30 million of cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27 per share.  Pursuant to the agreement governing the preferred stock (the “Fletcher Agreement”), Fletcher was entitled to convert its investment in the preferred shares at any time, or redeem its investment in the preferred shares at any time after December 31, 2004.  In January 2009, Fletcher issued a redemption notice with respect to all its shares of the Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher.  Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms of this redemption, which was recorded as a reduction to our net income applicable to common shareholders.  This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that were contractually required to be issued upon conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Convertible Preferred Stock.

 

The Fletcher Agreement provides that if the volume weighted average price of our common stock on any date is less than a certain minimum price ($2.767), then our right to pay dividends in our common stock is extinguished, and we are required to deliver a notice to Fletcher that either (1) the conversion price will be reset to such minimum price (in which case Fletcher shall have no further right to cause the redemption of the preferred stock), or (2) in the event Fletcher exercises its redemption rights, we will satisfy our redemption obligations either in cash, or a combination of cash and common stock subject to a maximum number of shares (14,973,814) that can be delivered to Fletcher under the Fletcher Agreement.  On February 25, 2009, the volume weighted average price of our common stock was below the minimum price, and on February 27, 2009 we provided notice to Fletcher that with respect to the Series A-1 Cumulative Convertible Preferred Stock the conversion price is reset to $2.767 as of that date and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock. As a result of the reset of the conversion price, Fletcher would receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Senior Credit Facilities (Note 9) we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.

 

In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms.  This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders.  Similar to the beneficial conversion charge associated with the redemption of Series A-2 Cumulative Convertible Preferred Stock, the beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock is limited to the $24.1 million of net proceeds received upon its issuance.

At June 30, 2009, we had $25 million of convertible preferred stock outstanding.   The convertible preferred stock maintains its mezzanine presentation below liabilities but is not included as component of shareholders’ equity, because we may, under certain instances, be required to settle any future conversions in cash.   On July 23, 2009, Fletcher provided a notice of conversion informing us of its election to convert 15,000 shares of the Series A-1 Cumulative Convertible Preferred Stock into 5,421,033 shares of our common stock.  We also paid the accrued and unpaid dividends associated with these shares in cash, the amount of which was immaterial at the time of the conversion notice.   On July 27, 2009, the conversion was completed.  Following the closing of this conversion, 10,000 shares of Series A-1 Cumulative Convertible Preferred Stock remain outstanding, representing $10 million of stated value, which are convertible into 3,614,023 shares of our common stock.

 

The common shares issuable in connection with this convertible preferred stock outstanding are included  in our diluted earnings per share computations using the “if converted” method based on the applicable conversion price of $2.767 per share, meaning that for almost all future reporting periods in which we have positive earnings and our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the applicable number of our shares (9,035,056 shares at June 30, 2009 and 3,614,023 shares in future periods as discussed above) will be included in our diluted shares outstanding amount.

 

Note 8 – Oil and Gas Properties

 

On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price threshold for both oil and gas was exceeded for 2004 production and that royalties were due on such production notwithstanding the provisions of the Outer Continental Shelf Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalty on certain federal leases up to certain specified production volumes. Our oil and gas leases affected by this dispute are Garden Banks Blocks 667, 668 and 669 (“Gunnison”). On May 2, 2006, the MMS issued another order that superseded the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both the December 2005 Order and the May 2006 Order. We received an additional order from the MMS dated September 30, 2008 stating that the price thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production and that royalties and interest are payable.  We appealed this order on the same basis as the previous orders.

 

Other operators in the Deep Water Gulf of Mexico who have received notices similar to ours are seeking royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico leases, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases. The government filed a notice of appeal of that decision on December 21, 2007.  On January 12, 2009, the United States Court of Appeals for the Fifth Circuit affirmed the decision of the district court in favor of Kerr-McGee, holding that the DWRRA unambiguously provides that royalty suspensions up to certain production volumes established by Congress apply to leases that qualify under the DWRRA.  The plaintiff petitioned the appellate court for rehearing; however, that petition was denied on April 14, 2009.    The plaintiff has

 

 

In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million.   We recorded an approximate $0.7 million gain from the sale of East Cameron Block 316 which was partially offset by the loss on the sale of the remaining 10% of our interest in the Bass Lite field at Atwater Block 426 in January 2009.  In the second quarter we sold three fields for gross proceeds of $0.8 million and resulting in an aggregate gain of $1.2 million, including transfer of the respective field’s asset retirement obligations.

 

In March and April 2008, we sold an aggregate 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $183.4 million (which included the purchasers’ share of incurred capital expenditures on these fields), and additional potential cash payments of up to $20 million based upon certain field production milestones.  The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields.  Decommissioning liabilities will be shared on a pro rata share basis between the new co-owners and us.  Proceeds from the sale of these properties were used to pay down our outstanding revolving loans in April 2008.  As a result of these sales, we recognized a pre-tax gain of $91.6 million (of which $30.5 million was recognized in second quarter 2008).

 

In May 2008, we sold all our interests in our onshore proved and unproved oil and gas properties located in the states of Texas, Mississippi, Louisiana, Oklahoma, New Mexico and Wyoming (“Onshore Properties”) to an unrelated investor.  We sold these Onshore Properties for cash proceeds of $47.2 million and recorded a related loss of $11.9 million in the second quarter of 2008.  Included in the cost basis of the Onshore Properties was an $8.1 million allocation of goodwill from our Oil and Gas segment.

 

 

In the second quarter of 2009, we recorded an aggregate of approximately $63.1 million of impairment charges, which are reflected as a reduction to our cost of sales. These charges primarily reflect the approximate $51.5 million of impairment-related charges recorded to properties that were severely damaged by Hurricane Ike (Note 4).  Separately, we also recorded $11.5 million of impairment charges to reduce the asset carrying value of four fields following reductions in their estimated proved reserves as evaluated at June 30, 2009.

 

In January 2008, the development well on Devil’s Island (Garden Banks Block 344) was determined to be unsuccessful and in the first half of 2008, we recorded an impairment charge of $14.6 million that is included as a component of oil and gas cost of sales in the accompanying condensed statement of operations.

 

Note 9 – Statement of Cash Flow Information

 

Note 10 – Equity Investments

 

 

Note 11 – Long-Term Debt

 

Scheduled maturities of long-term debt and capital lease obligations outstanding as of June 30, 2009 were as follows (in thousands):

 

 

 

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.   Cal Dive I -Title XI, Inc. and our foreign subsidiaries are not guarantors.  CDI and its subsidiaries were not guarantors of the Senior Unsecured Notes prior to deconsolidation of CDI in June 2009 (Note 4).  We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).

 

 

In July 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”).  The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition (see Note 4 of our 2008 Form 10-K).  This facility was subsequently amended in November 2007, and as part of that amendment, an accordion feature was added that allows for increases in the Revolving Credit Facility up to an additional $150 million, subject to availability of borrowing capacity provided by new or existing lenders.  In May 2008, we completed a $120 million increase in the Revolving Credit Facility utilizing this accordion feature.  Total borrowing capacity under the Revolving Credit Facility now totals $420 million.  The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.

 

The Term Loan matures on July 1, 2013 and is subject to quarterly scheduled principal payments.  As a result of a $400 million prepayment made in December 2007, the quarterly scheduled principal payment was reduced from $2.1 million to $1.1 million.  The Revolving Loans mature on July 1, 2011.  We had no amounts drawn on the Revolving Credit Facility at June 30, 2009 and our availability under the Facility totaled $407.8 million net of $12.2 million of unsecured letters of credit issued.

 

The Term Loan currently bears interest either at the one-, three- or six-month LIBOR at our current election plus a 2.00% margin.  Our average interest rate on the Term Loan for the six months ended June 30, 2009 and 2008 was approximately 3.1% and 5.7%, respectively, including the effects of our interest rate swaps (see below). The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our current election plus a margin ranging from 1.00% to 2.25%

 

In March 2005, we issued $300 million of our 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.

 

 

Approximately 1,199,000 shares and 965,000 shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the three month and six months ended June 30, 2008, respectively, because our average share price for the period was above the conversion price of approximately $32.14 per share.  Our average share price was below the $32.14 per share conversion price for the three and six month periods ended June 30, 2009 and as a result there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes in those respective periods.   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 paid in cash, and such shares would be issued on conversion. The Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.

 

 

 

Note 12 – Income Taxes

 

Note 13 – Comprehensive Income (Loss)

 

 

 

 

 

Note 14 – Earnings Per Share

 

 

Basic earnings per share ("EPS") 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 computation of basic and diluted EPS amounts for the three month and six month periods ended June 30, 2009 and 2008 are as follows (in thousands):

 

 

 

 

 

 

 

The following table compares EPS as originally reported and EPS under the two-class method, pursuant to FSP EITF 03-6-1, to quantify the per common share impact of the new standard on total net income applicable to Helix common shareholders’ for the three and six months ended June 30, 2008.

 

 

Note 15 – Stock-Based Compensation Plans

 

 

 

 

 

 

 

Note 16 – Business Segment Information (in thousands)

 

 

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.  The majority of our Production Facilities segment is accounted for under the equity method of accounting.  Our investment in Kommandor LLC, a Delaware limited liability company, was consolidated in accordance with FASB Interpretation No. 46,Consolidation of Variable Interest Entities (“FIN 46”) and is included in our Production Facilities segment.