UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
For the quarterly period ended March 31, 2012
OR
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
919 Milam, Suite 2100,
Houston, TX
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes x No ¨
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.
Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act). Yes ¨ No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Class A Common Units outstanding as of May 1, 2012 was 79,424,522.
FORM 10-Q
INDEX
Financial Statements
Unaudited Condensed Consolidated Balance Sheets – March 31, 2012 and December 31, 2011
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011
Unaudited Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2012 and 2011
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011
Notes to Unaudited Condensed Consolidated Financial Statements
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Controls and Procedures
Legal Proceedings
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Defaults upon Senior Securities
Mine Safety Disclosures
Other Information
Exhibits
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable - trade, net
Inventories
Other
Total current assets
FIXED ASSETS, at cost
Less: Accumulated depreciation
Net fixed assets
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
EQUITY INVESTEES
INTANGIBLE ASSETS, net of amortization
GOODWILL
OTHER ASSETS, net of amortization
TOTAL ASSETS
CURRENT LIABILITIES:
Accounts payable - trade
Accrued liabilities
Total current liabilities
SENIOR SECURED CREDIT FACILITY
SENIOR UNSECURED NOTES
DEFERRED TAX LIABILITIES
OTHER LONG-TERM LIABILITIES
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 79,465 and 71,965 units issued and outstanding at March 31, 2012 and December 31, 2011, respectively
TOTAL LIABILITIES AND PARTNERS’ CAPITAL
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
REVENUES:
Supply and logistics
Refinery services
Pipeline transportation services
Total revenues
COSTS AND EXPENSES:
Supply and logistics product costs
Supply and logistics operating costs
Refinery services operating costs
Pipeline transportation operating costs
General and administrative
Depreciation and amortization
Net gain on disposal of surplus assets
Total costs and expenses
OPERATING INCOME
Equity in earnings of equity investees
Interest expense
Income before income taxes
Income tax expense
NET INCOME
NET INCOME PER COMMON UNIT:
Basic and Diluted
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
Partners’ capital, January 1
Net income
Cash distributions
Issuance of common units for cash
Conversion of waiver units
Partners’ capital, March 31
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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Adjustments to reconcile net income to net cash provided by (used in) operating activities -
Amortization of debt issuance costs and premium
Amortization of unearned income and initial direct costs on direct financing leases
Payments received under direct financing leases
Equity in earnings of investments in equity investees
Cash distributions of earnings of equity investees
Non-cash effect of equity-based compensation plans
Deferred and other tax liabilities
Unrealized (gains) losses on derivative transactions
Other, net
Net changes in components of operating assets and liabilities (See Note 12)
Net cash provided by (used in) operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets
Cash distributions received from equity investees - return of investment
Investments in equity investees
Acquisitions
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings
Bank repayments
Proceeds from issuance of senior unsecured notes, including premium
Senior unsecured notes issuance costs
Issuance of common units for cash, net
Distributions to common unitholders
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation and Consolidation
Organization
We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, barges and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We manage our businesses through the following three divisions that constitute our reportable segments:
Pipeline transportation of interstate, intrastate and offshore crude oil, and, to a lesser extent, carbon dioxide (or CO2);
Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or “NaHS”, commonly pronounced nash); and
Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products and, on a smaller scale, CO2.
Basis of Presentation and Consolidation
The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries, including Genesis Energy, LLC, our general partner.
Our results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The Condensed Consolidated Financial Statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011.
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
2. Recent Accounting Developments
Recently Issued
In December 2011, the Financial Accounting Standards Board (“FASB”) issued guidance requiring new disclosures for financial instruments and derivative instruments that are eligible for offset in the statement of financial position or subject to a master netting arrangement. The new guidance is effective for us beginning January 1, 2013 and is not expected to have a material impact on our financial position, results of operations or cash flows.
Recently Adopted
In May 2011, the FASB issued amended guidance and disclosure requirements for fair value measurements. The new guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. The guidance became effective for us on January 1, 2012 and it did not have a material impact on our Unaudited Condensed Consolidated Financial Statements.
In June 2011, the FASB issued guidance that modified how comprehensive income is presented in an entity’s financial statements. The guidance issued requires an entity to present the total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements and eliminates the option to present the components of other comprehensive income as part of the statement of equity. The revised financial statement presentation for comprehensive income became effective for us on January 1, 2012 and its adoption did not impact our Unaudited Condensed Consolidated Financial Statements. The guidance pertaining to reclassifying items out of accumulated other comprehensive income has been deferred and will be effective for us beginning January 1, 2013. The adoption of the deferred guidance is not expected to have a material impact on our financial position, results of operations or cash flows.
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3. Acquisition
On January 3, 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility. We account for our interests in Poseidon and Odyssey under the equity method of accounting. We have recorded the assets acquired and liabilities assumed of GOPL in the Unaudited Condensed Consolidated Financial Statements at their estimated fair values on a preliminary basis. Management developed these preliminary fair values. We have reflected the financial results of the acquired pipeline interests in our pipeline transportation segment from the date of acquisition.
The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana.
Our Unaudited Condensed Consolidated Financial Statements include the results of the acquired pipeline interests since the effective closing date of the acquisition on January 1, 2012. The following table presents selected financial information included in our Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2012:
Revenues
The table below presents selected unaudited pro forma financial information for the three months ended March 31, 2011 incorporating the historical results of the acquired pipeline interests. The pro forma financial information below has been prepared as if the acquisition had been completed at the beginning of the prior year and is based upon assumptions deemed appropriate by us and may not be indicative of actual results.
Pro forma earnings data:
Basic and diluted earnings per unit:
As reported net income per unit
Pro forma net income per unit
As reported units outstanding
Pro forma units outstanding
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4. Inventories
The major components of inventories were as follows:
Crude oil
Petroleum products
Caustic soda
NaHS
Total inventories
At March 31, 2012 and December 31, 2011, market values of our inventories exceeded recorded costs.
5. Fixed Assets and Asset Retirement Obligations
Fixed Assets
Fixed assets consisted of the following:
Land, buildings and improvements
Pipelines and related assets
Machinery and equipment
Transportation equipment
Marine vessels
Office equipment, furniture and fixtures
Construction in progress
Fixed assets, at cost
Accumulated depreciation
Depreciation expense was $8.8 million and $5.8 million for the three months ended March 31, 2012 and 2011, respectively.
Asset Retirement Obligations
A reconciliation of our liability for asset retirement obligations is as follows:
Asset retirement obligations as of December 31, 2011
Liabilities incurred and assumed in the current period
Accretion expense
Asset retirement obligations as of March 31, 2012
During the three months ended March 31, 2012, we assumed asset retirement obligations of $5.9 million related to pipelines in connection with our acquisition of GOPL. See Note 3 for information related to our acquisitions.
6. Equity Investees
We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At March 31, 2012 and December 31, 2011, the unamortized excess cost amounts totaled $241.7 million and $97.8 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.
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The table below reflects information included in our Unaudited Condensed Consolidated Financial Statements related to our equity investees.
Genesis’ share of operating earnings
Amortization of excess purchase price
Net equity in earnings
Distributions received
The combined balance sheet information and results of operations data of our equity investees were as follows:
Balance Sheet Data:
Current assets
Fixed assets, net
Other assets
Total assets
Current liabilities
Other liabilities
Equity
Total liabilities and combined equity
Income Statement Data:
Operating income
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7. Intangible Assets
The following table reflects the components of intangible assets being amortized as of:
Refinery services customer relationships
Supply and logistics customer relationships
Refinery services supplier relationships
Refinery services licensing agreements
Supply and logistics trade names
Intangibles associated with supply and logistics lease
Total
Amortization expense on intangible assets was $5.5 million and $7.2 million for the three months ended March 31, 2012 and 2011, respectively. Estimated amortization for each of the next five years is as follows: remainder of 2012 – $14.6 million; 2013 – $14.5 million; 2014 –$12.2 million; 2015 – $10.4 million; and 2016 – $8.9 million.
8. Debt
At March 31, 2012 and December 31, 2011, our obligations under debt arrangements consisted of the following:
Senior secured credit facility
7.875% senior unsecured notes (including unamortized premium of $981 and $0 in 2012 and 2011, respectively)
Total long-term debt
We believe we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indenture as of March 31, 2012.
Senior Unsecured Notes Issuance
On February 1, 2012, we issued an additional $100 million of aggregate principal amount of senior unsecured notes under our existing 7.875% senior unsecured notes due 2018 indenture. The notes were issued at 101% of face value at an effective interest rate of 7.682%. The notes have the same terms and conditions as the notes previously issued under the indenture. The issuance increased the total aggregate principal amount under the indenture to $350 million. The net proceeds were used to repay borrowings under our credit facility.
Senior Secured Credit Facility
At March 31, 2012, we had $438.2 million borrowed under our $775 million senior secured credit facility, with $75.6 million of the borrowed amount designated as a loan under the inventory sublimit. The credit facility can be increased up to $1 billion, subject to lender approval. The credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $4.9 million was outstanding at March 31, 2012. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 30, 2015. The total amount available for borrowings under our credit facility at March 31, 2012 was $331.9 million.
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9. Partners’ Capital and Distributions
On March 28, 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.5 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. At March 31, 2012, our outstanding common units consisted of 79,424,522 Class A units and 39,997 Class B units.
Waiver Units
Our waiver units are non-voting securities entitled to a minimal preferential quarterly distribution. At issuance our waiver units were comprised of four classes (designated Class 1, Class 2, Class 3 and Class 4) of 1,750,000 authorized units each, of which 1,738,000 units of each class have been issued. The waiver units in each class are convertible into Class A common units in the calendar quarter at a 1:1 conversion rate during which each of our common units receives a specified minimum quarterly distribution and our distribution coverage ratio (after giving effect to the then convertible waiver units) would be at least 1.1 times. The minimum distribution per common unit required for conversion is $0.43 (Class 1), $0.46 (Class 2), $0.49 (Class 3) and $0.52 (Class 4). On February 14, 2012, our Class 1 waiver units became convertible as we paid a distribution of $0.44 per common unit and satisfied the conversion coverage ratio requirement. All Class 1 waiver units were converted into common units by March 31, 2012. At March 31, 2012, we had 5,214,099 waiver units outstanding comprised of the last three classes.
Distributions
We paid or will pay the following distributions in 2011 and 2012:
Distribution For
Date Paid
Fourth quarter 2010
First quarter 2011
Second quarter 2011
Third quarter 2011
Fourth quarter 2011
First quarter 2012
10. Business Segment Information
Our operations consist of three operating segments: (1) Pipeline Transportation – interstate, intrastate and offshore crude oil, and to a lesser extent, CO2 pipeline transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product, and (3) Supply and Logistics – purchasing, transporting, storing, blending and marketing of crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products). Substantially all of our revenues are derived from, and substantially all of our assets are located in the United States. We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant, and maintenance capital investment.
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Segment information for the periods presented below was as follows:
Three Months Ended March 31, 2012
Segment margin (a)
Capital expenditures (b)
Revenues:
External customers
Intersegment (c)
Total revenues of reportable segments
Three Months Ended March 31, 2011
Total assets by reportable segment were as follows:
Pipeline Transportation
Refinery Services
Supply & Logistics
Total consolidated assets
Segment Margin
Corporate general and administrative expenses
Distributable cash from equity investees in excess of equity in earnings
Non-cash items not included in segment margin
Cash payments from direct financing leases in excess of earnings
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11. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:
Petroleum products sales to an affiliate of the Robertson Group (1)
Marine operating fuel and expenses provided by an affiliate of the Robertson Group (1)
Sales of CO2 to Sandhill Group, LLC (2)
Petroleum products sales to Davison family businesses (1)
Amounts paid to our CEO in connection with the use of his aircraft
Amounts due to and from Related Parties
At March 31, 2012 and December 31, 2011, an affiliate of the Robertson Group owed us $3 million and $1.9 million, respectively, for petroleum product sales. We owed the affiliate $0.2 million and $0.1 million, respectively, for marine related costs. Sandhill Group, LLC owed us $0.2 million at both March 31, 2012 and December 31, 2011 for purchases of CO2.
12. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
(Increase) decrease in:
Accounts receivable
Other current assets
Increase (decrease) in:
Accounts payable
Net changes in components of operating assets and liabilities
Payments of interest and commitment fees were $5.2 million and $3.1 million for the three months ended March 31, 2012 and 2011, respectively. At March 31, 2012 and 2011, we had incurred liabilities for fixed and intangible asset additions totaling $4.1 million and $0.6 million, respectively, that had not been paid at the end of the first quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under investing activities in the Unaudited Condensed Consolidated Statements of Cash Flows.
13. Derivatives
At March 31, 2012, we had the following outstanding derivative commodity futures and options contracts that were entered into to hedge inventory or fixed price purchase commitments. We had no outstanding derivative contracts that were designated as hedges under accounting rules.
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Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)
Weighted average contract price per bbl
Heating oil futures:
Weighted average contract price per gal
RBOB gasoline futures:
#6 Fuel oil futures:
Crude oil options:
Weighted average premium received
Heating oil options:
RBOB gasoline options:
Financial Statement Impacts
The following tables reflect the estimated fair value gain (loss) position of our derivatives at March 31, 2012 and December 31, 2011:
Fair Value of Derivative Assets and Liabilities
Commodity derivatives - futures and call options:
Undesignated hedges
Total asset derivatives
Total liability derivatives
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Effect on Operating Results
Location
Contracts designated as hedges under accounting guidance
Contracts not considered hedges under accounting guidance
Total commodity derivatives
14. Fair-Value Measurements
We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value: Level 1 fair values are based on observable inputs such as quoted prices in active markets; Level 2 fair values are based on pricing inputs other than quoted prices in active markets and are either directly or indirectly observable as of the measurement date; and Level 3 fair values are based on unobservable inputs in which little or no market data exists. As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011.
Recurring Fair Value Measures
Commodity derivatives:
Assets
Liabilities
Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.
See Note 13 for additional information on our derivative instruments.
We generally apply fair value techniques on a non-recurring basis associated with (1) valuing potential impairment loss related to goodwill, (2) valuing asset retirement obligations, and (3) valuing potential impairment loss related to long-lived assets.
Other Fair Value Measurements
We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates for similar instruments with comparable maturities. At March 31, 2012, our senior unsecured notes had a carrying value of $351 million and a fair value of $358.8 million, compared to $250 million and $253.1 million, respectively, at December 31, 2011. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.
15. Contingencies
We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any material releases of crude oil from our pipelines or other facilities; however, no assurance can be made that such environmental releases may not substantially affect our business.
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We are subject to lawsuits in the normal course of business, as well as examinations by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations, or cash flows.
16. Condensed Consolidating Financial Information
Our $350 million aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. Each subsidiary guarantor and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P. See Note 8 for additional information regarding our consolidated debt obligations. The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.
Unaudited Condensed Consolidating Balance Sheet
March 31, 2012
Current assets:
Fixed Assets, at cost
Goodwill
Other assets, net
Equity investees
Investments in subsidiaries
Senior unsecured notes
Deferred tax liabilities
Total liabilities
Partners’ capital
Total liabilities and partners’ capital
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December 31, 2011
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Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2012
Supply and logistics costs
Equity in earnings of subsidiaries
Interest (expense) income, net
Income tax (expense) benefit
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For the Three Months Ended March 31, 2011
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Unaudited Condensed Consolidating Statement of Cash Flows
Net cash (used in) provided by operating activities
Repayments on loan to non-guarantor subsidiary
Net cash (used in) provided by investing activities
Issuance of ownership interests to partners for cash
Distributions to partners/owners
Net cash provided by (used in) financing activities
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Net cash provided by (used in) investing activities
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this quarterly report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K.
Included in Management’s Discussion and Analysis are the following sections:
Overview
Acquisition
Financial Measures
Results of Operations
Liquidity and Capital Resources
Commitments and Off-Balance Sheet Arrangements
Forward Looking Statements
We reported net income of $19.6 million, or $0.27 per common unit during the three months ended March 31, 2012 (“2012 Quarter”) compared to net income of $7 million or $0.11 per common unit during the three months ended March 31, 2011 (“2011 Quarter”). The significant factors affecting net income were improved operating results by our business segments partially offset by increases in general and administrative expense, depreciation and amortization expense and interest costs. A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.
Segment Margin (as described below in “Financial Measures”) increased by $11.1 million, or 23%, in the 2012 Quarter, as compared to the 2011 Quarter. This increase resulted from improvement in Segment Margin in our pipeline transportation and supply and logistics segments of 43% and 31%, respectively, partially offset by a 4% decrease in our refinery services segment. The contribution from our recently acquired interests in the Gulf of Mexico pipelines, higher crude oil tariff revenues and increased sales of pipeline loss allowances were the primary factors increasing pipeline transportation Segment Margin. Our refinery services Segment Margin decreased as a result of lower volumes partially offset by higher average product prices per dry short ton. Our supply and logistics segment benefited from acquisitions and other growth initiatives completed in the second half of 2011.
Available Cash before Reserves increased $7.8 million, or 24%, in the 2012 Quarter to $39.6 million reflecting the increase in net income described above. See “Financial Measures” below for additional information on Available Cash before Reserves.
Distribution Increase
In April 2012, we declared our twenty-seventh consecutive increase in our quarterly distribution to our common unitholders relative to the first quarter of 2012. During this period, twenty-two of those quarterly increases have been 10% or greater year-over-year. In May 2012, we will pay a distribution of $0.45 per unit representing a 10.4% increase from our distribution of $0.4075 per unit for the first quarter of 2011. During the first quarter of 2012, we paid a distribution of $0.44 per unit related to the fourth quarter of 2011.
In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or “Poseidon”), a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. (or “Odyssey”). GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility.
This acquisition complements our existing infrastructure in the Gulf of Mexico and enhances our ability to provide capacity and market optionality to producers for their existing and future developments as well as our refining customers onshore Texas and Louisiana. The Poseidon pipeline system is comprised of a 367-mile network of crude oil pipelines, varying in diameter from 16 to 24 inches, with capacity to deliver approximately 400,000 barrels per day of crude oil from
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developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of Enterprise Products serves as the operator of Poseidon. The Eugene Island pipeline system is primarily comprised of a 183-mile network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, with capacity to deliver approximately 200,000 barrels per day of crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco, ConocoPhillips and Shell. An affiliate of Shell serves as the operator of Eugene Island. The Odyssey pipeline system is comprised of a 120-mile network of crude oil pipelines, varying in diameter from 12 to 20 inches, with capacity to deliver up to 300,000 barrels per day of crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey, and an affiliate of Shell serves as the operator of Odyssey.
In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that we use to manage the business and to review the results of our operations. Those two measures are Segment Margin and Available Cash before Reserves.
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant, and maintenance capital investment. A reconciliation of Segment Margin to income before income taxes is included in our segment disclosures in Note 10 to our Unaudited Condensed Consolidated Financial Statements.
Available Cash before Reserves
This quarterly report includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP. The accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts, and other market participants.
Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies.
Available Cash before Reserves is a performance measure used by our management to compare cash flows generated by us to the cash distribution paid to our common unitholders. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
Available Cash before Reserves is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows. Available Cash before Reserves for the periods presented below was as follows:
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Cash received from direct financing leases not included in income
Effects of distributable cash generated by equity method investees not included in income
Cash effects of equity-based compensation plans
Non-cash equity-based compensation expense
Expenses related to acquiring or constructing assets that provide new sources of cash flow
Unrealized (gain) loss on derivative transactions excluding fair value hedges
Maintenance capital expenditures
Non-cash tax (benefit) expense
Other items, net
Revenues and Costs and Expenses
Our revenues for the 2012 Quarter increased $243.1 million, or 35% from the 2011 Quarter. Additionally, our costs and expenses increased $229.2 million, or 34% between the two periods. The majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs between the two first quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products, our acquisitions and increased volumes from our operations as described below. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange, as an example, increased 9.4% to $102.93 per barrel in the first quarter of 2012, as compared to $94.10 per barrel in the first quarter of 2011.
The contribution of each of our segments to total Segment Margin in the three months ended March 31, 2012 and 2011 was as follows:
Pipeline transportation
Total Segment Margin
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Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment are presented below.
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines
Segment margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
Sales of crude oil pipeline loss allowance volumes
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
Payments received under direct financing leases not included in income
Volumetric Data (Bbls per day unless otherwise noted):
Onshore crude oil pipelines:
Jay
Texas
Mississippi
Offshore crude oil pipelines:
CHOPS
Poseidon (1)
Odyssey (1)
GOPL (1)
CO2 pipeline (Mcf/day):
Free State
Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011
Pipeline transportation Segment Margin for the 2012 Quarter increased $7.7 million, or 43%. The significant components of this change were as follows:
Crude oil tariff revenues of onshore crude oil pipelines increased $1.5 million primarily due to upward tariff indexing for our FERC regulated pipelines effective in July 2011.
Segment Margin from our offshore crude oil pipelines increased $5.1 million reflecting a $7.6 million contribution from our recently acquired interests in the Gulf of Mexico pipelines. The increase was partially offset by lower volumes transported on CHOPS of approximately 69,000 barrels per day as result of ongoing improvements by producers at the connected production fields. Distributable cash generated by CHOPS declined by $2.5 million from the 2011 Quarter.
An increase in revenues from sales of pipeline loss allowance volumes improved Segment Margin by $1.7 million primarily related to the increase in crude oil prices from the 2011 Quarter.
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Refinery Services Segment
Operating results for our refinery services segment were as follows:
Volumes sold:
NaHS volumes (Dry short tons “DST”)
NaOH (caustic soda) volumes (DST)
Revenues (in thousands):
NaHS revenues
NaOH (caustic soda) revenues
Other revenues
Total external segment revenues
Average index price for NaOH per DST (1)
Raw material and processing costs as % of segment revenues
Refinery services Segment Margin for the 2012 Quarter was $17.2 million, a decrease of $0.7 million, or 4%, from the comparative period in 2011. The significant components of this fluctuation were as follows:
Revenues increased primarily as a function of the increase in the average index price for caustic soda. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations and our logistics management helped offset these costs.
NaHS sales volumes decreased 9% between the quarterly periods primarily due to lower sales to South American customers in the 2012 Quarter. In late 2011, we experienced a high volume of sales to these customers. Sales volumes between quarters to customers in South America can fluctuate due to timing.
Caustic soda sales volumes decreased 15%. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.
Average index prices for caustic soda increased to $571 per DST in the first quarter of 2012 compared to $440 per DST during the first quarter of 2011. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to mitigate the effects of changes in index prices for caustic on our operating costs.
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Supply and Logistics Segment
Operating results from our supply and logistics segment were as follows:
Supply and logistics revenue
Crude oil and products costs, excluding unrealized gainsand losses from derivative transactions
Operating costs, excluding non-cash charges forequity-based compensation and other non-cash expenses
Volumes of crude oil and petroleum products (barrels per day)
Three Months Ended March 31, 2012 as Compared to Three Months Ended March 31, 2011
The average market prices of crude oil and petroleum products increased by more than $8 per barrel, or 9.4%, between the two quarterly periods; however that price volatility had a limited impact on our Segment Margin. Segment Margin for our supply and logistics segment increased by $4.1 million, or 31% during the 2012 Quarter.
The increase in Segment Margin during the 2012 Quarter resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and increased volumes. We were also able to increase volumes by 23% quarter-over-quarter as a result of increased industry activity in the Eagle Ford Shale and Niobrara Shale.
Other Costs, Interest, and Income Taxes
General and administrative expenses
General and administrative expenses not separately identified below:
Corporate
Segment
Equity-based compensation plan expense
Third party costs related to business development activities and growth projects
Total general and administrative expenses
Total general and administrative expenses increased $1.5 million, or 19%, during the 2012 Quarter primarily due to higher corporate and segment general and administrative expenses as a result of salary and benefits expenses associated with increases in personnel to support our growth. Additionally, increases in the market price of our common units affected expense related to our equity-based compensation plans.
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Depreciation and amortization expense
Depreciation expense
Amortization of intangible assets
Amortization of CO2 volumetric production payments
Total depreciation and amortization expense
Total depreciation and amortization expense increased $1.1 million, or 8%, between the quarterly periods primarily as a result of our recent acquisitions, including the black oil barge transportation assets in August 2011. The increase in total depreciation and amortization was partially offset by lower amortization of intangible assets. We amortize our intangible assets over the period which we expect them to contribute to our future cash flows. Generally, the amortization we record on those assets is greater in the initial years following their acquisition because our intangible assets are generally more valuable in the first years after an acquisition.
Interest expense, net
Interest expense, credit facility (including commitment fees)
Interest expense, senior unsecured notes
Amortization of debt issuance costs
Interest income
Net interest expense
Net interest expense increased $1.9 million, or 22%, over the 2011 Quarter primarily as a result of increased borrowings associated with acquisitions. Interest expense on our credit facility increased between the quarterly periods as our average debt balance increased approximately $220 million primarily reflecting the capital required for our internal growth projects and our acquisitions. Interest expense on our senior unsecured notes increased during the 2012 Quarter as a result of issuing an additional $100 million of notes under the indenture in February 2012 to repay borrowings under our credit facility.
A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.
Net income for the 2012 Quarter benefited from an unrealized gain on derivative positions of $2 million. Net income for the 2011 Quarter included an unrealized loss on derivative positions of $6.5 million. Those amounts are included in Supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations, and are not a component of Segment Margin.
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General
As of March 31, 2012, we had $331.9 million of borrowing capacity available under our $775 million senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations and borrowing availability under our credit facility.
Our primary cash requirements consist of:
Working capital, primarily inventories;
Routine operating expenses;
Capital expansion and maintenance projects;
Acquisitions of assets or businesses;
Interest payments related to outstanding debt; and
Quarterly cash distributions to our unitholders.
We continue to pursue a growth strategy that requires significant capital. In January 2012, we borrowed $205.6 million under our credit facility to acquire interests in several pipeline systems. See “Capital Expenditures and Business and Asset Acquisitions” below for more information related to our capital spending and acquisitions.
Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time — including through equity and debt offerings (public and private), borrowings under our credit facility and other financing transactions—to implement our growth strategy successfully. No assurance can be made that we will be able to raise necessary funds on satisfactory terms.
Our $775 million senior secured revolving credit facility includes an accordion feature whereby the total credit available can be increased up to an aggregate $1 billion for acquisitions or internal growth projects, with lender approval. Our credit facility also includes a $125 million inventory sublimit tranche. This inventory tranche is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Thirteen lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility. Our credit facility matures on June 30, 2015.
In February 2012, we issued $100 million under our existing 7.875% senior unsecured notes indenture for which the net proceeds were used to repay borrowings under our credit facility. The notes were issued at 101% of face value at an effective interest rate of 7.682%. See Note 8 to our Unaudited Condensed Consolidated Financial Statements for more information.
In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.5 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility. See Note 9 to our Unaudited Condensed Consolidated Financial Statements for more information.
At March 31, 2012, long-term debt totaled $789.2 million, consisting of $438.2 million outstanding under our credit facility (including $75.6 million borrowed under the inventory sublimit tranche) and a $351 million carrying amount of senior unsecured notes due in 2018.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the timing of payment of accounts payable and accrued liabilities related to capital expenditures.
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We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for the crude oil. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of oil. In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility. See Note 12 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the three months ended March 31, 2012 and 2011.
Net cash flows provided by our operating activities for the three months ended March 31, 2012 were $19.9 million compared to cash used of $2.1 million for the three months ended March 31, 2011. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more cash. The increase in operating cash flow for the three months ended March 31, 2012 compared to the same period in 2011 was primarily due to higher cash earnings and lower working capital requirements.
Capital Expenditures and Distributions Paid to our Unitholders
We use cash primarily for our acquisition activities, internal growth projects and distributions we pay to our unitholders. We finance internal growth projects and distributions primarily with cash generated by our operations. Acquisition activities have historically been funded with borrowings under our credit facility, equity issuances and the issuance of senior unsecured notes.
Capital Expenditures and Business and Asset Acquisitions
A summary of our expenditures for fixed assets and other asset acquisitions for the three months ended March 31, 2012 and 2011 is as follows:
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets
Refinery services assets
Supply and logistics assets
Total maintenance capital expenditures
Growth capital expenditures:
Supply and logistics assets (1)
Information technology systems upgrade projects
Total growth capital expenditures
Total maintenance and growth capital expenditures
Capital expenditures for business combinations,net of liabilities assumed:
Offshore pipelines
Capital expenditures related to equity investees (2)
Total capital expenditures
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.
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Growth Capital Expenditures
In April 2011, we announced two projects to increase the services we provide to producers and refiners. We acquired three above-ground storage tanks, located in Texas City, Texas and an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system. We also are constructing a truck station and tankage in West Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area. Once the refurbishment, tie-in and all interconnecting pipe are completed, estimated to be early third quarter of 2012, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal. In addition, we have initiated construction of a 16-inch diameter loop of our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which will allow us to significantly expand our total service capabilities into the Texas City area by the second quarter of 2013.
During 2011, we also entered into an agreement to install a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in Tulsa, Oklahoma. The new facility, expected to be completed in the fourth quarter of 2012, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and is expected to result in potential additional capacity of 24,000 DST per year of NaHS.
We recently began construction of a new crude-by-rail unloading terminal connected to our existing crude oil pipeline at Walnut Hill, Florida. This facility will be capable of handling unit train shipments of oil for direct deliveries to one refinery customer and indirect delivery, through third-party common carriers, to potentially multiple other markets in the Southeast. We anticipate this facility to be fully operational in the third quarter of 2012.
We anticipate the costs of those projects above to be approximately $80 million in total, of which we have spent approximately $25 million since inception in 2011. We expect those remaining costs for the projects will be spent primarily in 2012.
We anticipate spending approximately $33 million to upgrade our refinery facilities in Wyoming and to bring the related pipeline back in service. We spent $0.1 million related to these projects during the first quarter of 2012.
In February 2012, we purchased seven barges from Florida Marine Transporters, which previously had been subleased to us in connection with the acquisition of the black oil barge assets in August 2011. The cost of the seven barges totaled $30.6 million, which was funded with cash available under our credit facility.
Capital Expenditures Related to Business Combinations and Equity Investees
In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The purchase price, net of post-closing adjustments, was $205.6 million. We account for our ownership interests in Poseidon and Odyssey under the equity method of accounting. We accounted for our acquisition of GOPL using the acquisition method. See Note 3 in our Unaudited Condensed Consolidated Financial Statements for more information.
In December 2011, we formed Southeast Keathley Canyon Pipeline Company, LLC (or SEKCO) with Enterprise Products to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of Mexico. The new pipeline is expected to begin service by mid-2014. We expect to spend approximately $200 million for our share of the pipeline construction through 2014 and to reimburse Enterprise Products for our portion of previously incurred costs. We expect to pay approximately $80 million in 2012, of which we paid $33.5 million during the first quarter of 2012. The anchor producers, which have executed long-term transportation agreements, are responsible for most cost overruns and other costs incurred associated with weather-related delays.
Distributions to Unitholders
On May 15, 2012, we will pay a distribution of $0.45 per common unit totaling $35.8 million with respect to the first quarter of 2012 to common unitholders of record on May 1, 2012. This is the twenty-seventh consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 9 to our Unaudited Condensed Consolidated Financial Statements.
Contractual Obligations and Commercial Commitments
There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2011.
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Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2011, nor do we have any debt or equity triggers based upon our unit or commodity prices.
The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:
demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, NaHS and caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;
throughput levels and rates;
changes in, or challenges to, our tariff rates;
our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
service interruptions in our pipeline transportation systems and processing operations;
shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum products, or CO2 or to whom we sell such products;
risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations;
the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and oil spill in the Gulf;
planned capital expenditures and availability of capital resources to fund capital expenditures;
our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indenture governing our notes, which contain various affirmative and negative covenants;
loss of key personnel;
an increase in the competition that our operations encounter;
cost and availability of insurance;
hazards and operating risks that may not be covered fully by insurance;
our financial and commodity hedging arrangements;
changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;
natural disasters, accidents or terrorism;
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changes in the financial condition of customers;
adverse rulings, judgments, or settlements in litigation or other legal or tax matters;
the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and
the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011 and any other risk factors contained in our Current Reports on Form 8-K that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our 2011 Annual Report on Form 10-K. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 13 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.
Item 4. Controls and Procedures
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.
There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no material developments in legal proceedings since the filing of such Form 10-K.
Item 1A. Risk Factors.
For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no material changes to the risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
On March 19, 2012, we issued 11,224 Common Units – Class A and 982 Waiver Units of each class in connection with the appointment of an officer of our general partner. The transaction was exempt from registration under Section 4(2) of the Securities Act of 1933.
Item 3. Defaults Upon Senior Securities.
None.
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Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
Item 6. Exhibits.
(a) Exhibits.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(A Delaware Limited Partnership)
GENESIS ENERGY, LLC,
as General Partner
/s/ ROBERT V. DEERE
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