UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
For the quarterly period ended September 30, 2011
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.)
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 þ 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 þ 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.
Large 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 þ
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 November 2, 2011: 71,925,065
INDEX
PART I. FINANCIAL INFORMATION
Financial Statements
Unaudited Condensed Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010
Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2011 and 2010
Unaudited Condensed Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2011 and 2010
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010
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
(Removed and Reserved)
Other Information
Exhibits
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Item 1. Financial Statements
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
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
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable—trade
Accrued liabilities
Total current liabilities
SENIOR SECURED CREDIT FACILITIES
SENIOR UNSECURED NOTES
DEFERRED TAX LIABILITIES
OTHER LONG-TERM LIABILITIES
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS’ CAPITAL:
Common unitholders, 71,965 and 64,615 units issued and outstanding at September 30, 2011 and December 31, 2010, 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 loss on disposal of surplus assets
Total costs and expenses
OPERATING INCOME
Equity in (losses) earnings of equity investees
Interest expense
Income before income taxes
Income tax expense
NET INCOME
Net loss attributable to noncontrolling interests
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. PER COMMON UNIT:
Basic and Diluted
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS
OF COMPREHENSIVE INCOME
Net income
Change in fair value of derivatives:
Current period reclassification to earnings—interest rate swaps
Changes in derivative financial instruments—interest rate swaps
Comprehensive income
Comprehensive loss attributable to noncontrolling interests
Comprehensive income attributable to Genesis Energy, L.P.
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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
Partners’ capital, December 31, 2010
Cash distributions
Issuance of units
Partners’ capital, September 30, 2011
Partners’ capital, December 31, 2009
Comprehensive income:
Cash contributions
Contribution for executive compensation
Unit based compensation expense
Acquisition of non-controlling interest in DG Marine
Partners’ capital, September 30, 2010
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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 operating activities—
Amortization and write-off of credit facility issuance costs
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
Non-cash compensation credit
Deferred and other tax liabilities
Unrealized (gains) losses on derivative transactions
Other, net
Net changes in components of operating assets and liabilities, net of acquisitions (See Note 11)
Net cash provided by 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
Acquisition of FMT assets
Proceeds from asset sales
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings
Bank repayments
Credit facility issuance fees
Issuance of common units for cash, net
General partner contributions
Noncontrolling interests contributions, net of distributions
Distributions to common unitholders
Distributions to general partner interest
Acquisition of non-controlling interests in DG Marine
Net cash provided by (used in) financing activities
Net 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 master limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast area of the United States. We conduct our operations through our operating subsidiaries and joint ventures. We manage our businesses through three divisions:
Pipeline transportation of crude oil and 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, petroleum products and CO2.
In February 2010, new investors, together with members of our executive management team, acquired our general partner. At that time, our general partner owned all our 2% general partner interest and all of our incentive distribution rights, or IDRs. In respect of its general partner interest and IDRs, our general partner was entitled to over 50% of any increased distributions we would pay in respect of our outstanding equity.
On December 28, 2010, we permanently eliminated our IDRs and converted our 2% general partner interest into a non-economic interest, which we refer to as our IDR Restructuring. We issued Class A Units, Class B Units and Waiver Units to the former stakeholders of our general partner in exchange for the elimination of our IDRs. See additional information on our outstanding equity in Note 8.
Basis of Presentation and Consolidation
The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries, and Genesis Energy, LLC, our general partner. The inclusion of Genesis Energy, LLC in our Consolidated Financial Statements was effective December 28, 2010 due to our IDR Restructuring.
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 financial statements prepared in accordance with generally accepted accounting principles 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, 2010.
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 September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance that simplified how an entity tests goodwill for impairment. The revised guidance provides an entity the option to make a qualitative evaluation about the likelihood of goodwill impairment. Under the revised guidance, an entity is permitted to first assess qualitative factors to determine whether goodwill impairment exists prior to performing analyses comparing the fair value of a reporting unit to its carrying amount. If, after assessing the totality of events or circumstances, an
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entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The guidance will be effective for us beginning January 1, 2012; however early adoption is permitted. We intend to adopt the FASB’s guidance early and do not believe the adoption of the guidance will have a significant impact on our financial position, results of operations or cash flows.
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 will be effective for us beginning January 1, 2012, with early adoption permitted. The adoption of this guidance is not expected to have a significant impact on our financial position, results of operations or cash flows.
Recently Adopted
In December 2010, the FASB revised its guidance for disclosure requirements of supplementary pro forma information for business combinations. The objective of the revised guidance is to address diversity in practice regarding pro forma disclosures for revenues and earnings of an acquired entity and specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments, which went into effect on January 1, 2011, will be adhered to any future material business combinations.
3. Acquisition
FMT Black Oil Barge Transportation Business
On August 9, 2011, Genesis completed the acquisition of the black oil barge transportation business of Florida Marine Transporters, Inc. and its affiliates, or FMT. The purchase price was $141 million plus customary adjustments. The acquired business is comprised of 30 barges (seven of which are being sub-leased under similar terms of an existing FMT lease) and 14 push/tow boats which transport heavy refined products, primarily serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. The barges have an average age of approximately three years with 13 having been in service three years or less.
The financial results of the acquired business will be included in the supply and logistics segment. The acquisition is intended to complement and further integrate certain existing operations, including the DG Marine inland barge business (comprised of 20 barges and 10 push/tow boats), storage and blending terminals and crude oil pipeline systems. The expanded fleet of 50 barges are capable of transporting heavy refined products, including asphalt, and with minor modifications, half of the barges (representing 750,000 barrels of capacity) will be capable of transporting crude oil as well.
The acquisition and related transaction costs were funded with a portion of the net proceeds from the July 2011 public offering of our common units. See Note 8 for additional information regarding the unit offering.
The total acquisition cost has been allocated to the assets acquired based on estimated preliminary fair values. Such preliminary fair values were developed by management. We do not expect any material adjustments to these preliminary purchase price allocations as a result of the final valuation.
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The preliminary allocation of the acquisition cost is summarized as follows:
Property and equipment:
Barges
Boats
Spare parts inventory
Other current assets:
Fuel and lube oil in vessels
Total allocated cost
4. Inventories
The major components of inventories were as follows:
Crude oil
Petroleum products
Caustic soda
NaHS
Total inventories
Inventories are valued at the lower of cost or market. The costs of inventories exceeded market values by approximately $1.6 million at September 30, 2011, and we reduced the value of inventory in our unaudited condensed consolidated financial statements for this difference. At December 31, 2010, market values of our inventories exceeded recorded costs.
5. Equity Investees
We are accounting for our 50% ownership in Cameron Highway Oil Pipeline Company (“Cameron Highway”) under the equity method of accounting.
The following table reflects summarized income statement information for Cameron Highway for only the three and nine months ended September 30, 2011 as we did not acquire our 50% equity interest in Cameron Highway until November 23, 2010.
Revenues
Operating Income
Net Income
We received cash distributions from Cameron Highway of $2.8 million and $13.8 million for the three and nine months ended September 30, 2011, respectively
Net income from Cameron Highway was reduced in the third quarter of 2011 as a result of lower throughput volumes by certain producers due to their field improvement activities.
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6. Intangible Assets and Goodwill
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 $7.7 million and $22.4 million for the three and nine months ended September 30, 2011, respectively. Amortization expense on intangible assets was $6.7 million and $20.0 million for the three and nine months ended September 30, 2010, respectively.
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
Year Ended December 31,
Remainder of 2011
2012
2013
2014
2015
In the first quarter of 2011, we adjusted the useful lives of our supply and logistics trade names. As a result of this change in the amortization period of our assets, operating income and net income attributable to us for the three and nine months ended September 30, 2011 decreased $1.4 million, or $0.02 per common unit and $4.3 million, or $0.07 per common unit, respectively. The impact of this change on net income for the remainder of 2011 and 2012 is expected to total $1.4 million and $2.3 million, respectively, and not be material in future periods. The table of estimated future amortization expense above reflects this change.
Goodwill
The carrying amount of goodwill by business segment at both September 30, 2011 and December 31, 2010 was $301.9 million to refinery services and $23.1 million to supply and logistics.
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7. Debt
On August 19, 2011, we amended our senior secured revolving credit facility to increase the committed amount from $525 million to $775 million and the accordion feature from $125 million to $225 million, giving us the ability to expand the size of the facility up to an aggregate $1 billion, subject to lenders’ consent. The amendment also increased the inventory financing sublimit tranche that we may use to finance the purchase and sale of certain petroleum products subject to sales contracts or hedging agreements and related storage and transportation costs from $75 million to $125 million. We deferred approximately $3.0 million of costs incurred in connection with this amendment and will amortize these costs over the remaining life of the credit facility.
All borrowings under our revolving credit facility bear interest, at our option, either at an alternate base rate or a Eurodollar rate. The applicable margin, which is a component of the interest on both the alternate base rate and the Eurodollar rate borrowings, previously varied from 1.5% to 2.5% per annum for alternate base rate borrowings and from 2.5% to 3.5% per annum for Eurodollar rate borrowings, depending on our leverage ratio. The amendment reduced the applicable margin to 1.0% to 2.0% per annum for alternate base rate borrowings and 2.0% to 3.0% per annum for Eurodollar borrowings, depending on our leverage ratio. In addition, the amendment changed the commitment fee on the unused commitment amount from 0.500% per annum to 0.375% to 0.500% per annum, depending on our leverage ratio.
As of September 30, 2011, we had $367.9 million borrowed under our senior secured credit facility, with $47.9 million of that amount designated as a loan under the inventory sublimit. Additionally, we had $4.3 million in letters of credit outstanding. 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 at September 30, 2011 was $402.8 million under our credit facility.
We believe the amounts included in our balance sheet for debt outstanding under our senior secured credit facility approximate fair value as interest rates reflect current market rates. At September 30, 2011, $250 million of senior unsecured notes were outstanding, which had a fair value of approximately $235.3 million.
We believe we were in compliance with the financial covenants contained in our credit facility and indenture as of September 30, 2011.
8. Partners’ Capital, Distributions and Net Income Per Common Unit
Partners’ Capital
At September 30, 2011, our outstanding equity consisted of 71,925,065 Class A Units and 39,997 Class B Units. Additionally 6,949,004 Waiver Units were outstanding. In July 2011, we issued 7,350,000 Class A Units in a public offering. We received proceeds, net of underwriting discounts and offering costs, of $185 million from the offering.
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Distributions
We paid or will pay the following distributions in 2010 and 2011:
Distribution For
Fourth quarter 2009
First quarter 2010
Second quarter 2010
Third quarter 2010
Fourth quarter 2010
First quarter 2011
Second quarter 2011
Third quarter 2011
Net Income Per Common Unit
The following table sets forth the computation of basic and diluted net income per common unit.
Numerators for basic and diluted net income per common unit:
Net income attributable to Genesis Energy, L.P.
Less: General partner's incentive distribution to be paid for the period
Add: Expense for Class B Awards
Subtotal
Less: General partner 2% ownership
Income available for common unitholders
Denominator for basic and diluted per common unit:
Basic and diluted net income per common unit
9. Business Segment Information
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. Our Segment Margin definition also excludes the non-cash effects of our stock appreciation rights compensation 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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In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO2 marketing activities and processing of syngas through a joint venture, formerly reported in the industrial gases segment, are now included in our supply and logistics segment. The change in operating segments had no impact on our reportable units for goodwill purposes. The historical segment disclosures have been recast to be consistent with the current presentation. This recast also included combining revenues and costs and expenses for our industrial gases activities shown separately in our Unaudited Condensed Consolidated Statements of Operations in the 2010 period with revenues and costs and expenses for our supply and logistics activities.
Three Months Ended September 30, 2011
Segment margin (a)
Maintenance capital expenditures
Revenues:
External customers
Intersegment (b)
Total revenues of reportable segments
Three Months Ended September 30, 2010
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Nine Months Ended September 30, 2011
Nine Months Ended September 30, 2010
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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10. 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. Affiliates of Denbury Resources, Inc. sold its interests in our general partner on February 5, 2010. Transactions with Denbury are included in the table below as related party transactions through February 5, 2010.
The transactions with related parties were as follows:
Petroleum products sales to an affiliate of the Robertson Group
Marine operating fuel and expenses provided by an affiliate of the Robertson Group
Sales of CO2 to Sandhill
Petroleum products sales to Davison family businesses
Operations, general and administrative services provided by our general partner (1)
Truck transportation services provided to Denbury
Pipeline transportation and monitoring services provided
to Denbury
Payments received under direct financing leases from
Denbury
Pipeline transportation income portion of direct financing lease fees from Denbury
CO2 transportation services provided by Denbury
Amounts due to and from Related Parties
At September 30, 2011 and December 31, 2010, an affiliate of the Robertson Group owed us $0.2 million and $1.4 million, respectively, for petroleum products purchases, and we owed the affiliate $0.1 million and $0.2 million, respectively, for marine-related costs. Sandhill owed us $0.2 million for purchases of CO2 at September 30, 2011 and December 31, 2010.
11. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
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Decrease (increase) 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 $20.3 million and $10.8 million for the nine months ended September 30, 2011 and 2010, respectively.
Cash paid for income taxes during the nine months ended September 30, 2011 and 2010 was $1.0 million and $2.2 million, respectively.
At September 30, 2011, we had incurred liabilities for fixed and intangible asset additions totaling $1.3 million that had not been paid at the end of the third quarter, and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” under investing activities on the Unaudited Condensed Consolidated Statements of Cash Flows. At September 30, 2010, we had incurred $2.0 million of such liabilities that had not been paid at that date and are not included in “Payments to acquire fixed and intangible assets” and “Other, net” under investing activities.
12. Derivatives
Commodity Derivatives
At September 30, 2011, we had the following outstanding derivative commodity futures, forwards 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 written options:
Weighted average premium received
Heating oil written options:
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Financial Statement Impacts
The following tables reflect the estimated fair value gain (loss) position of our derivatives and related inventory impact for qualifying hedges at September 30, 2011 and December 31, 2010:
Fair Value of Derivative Assets and Liabilities
Unaudited
Condensed
Consolidated
Balance Sheets
Commodity derivatives—futures and call options:
Hedges designated under accounting guidance as fair value hedges
Undesignated hedges
Total asset derivatives
Commodity derivatives—forwards futures and call options:
Total liability derivatives
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Contracts designated as hedges under accounting guidance
Contracts not considered hedges under accounting guidance
Total commodity derivatives
Interest rate swaps designated as cash flow hedges under accounting guidance
Total derivatives
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13. Fair-Value Measurements
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 September 30, 2011. 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.
Recurring Fair Value Measures
Commodity derivatives:
Assets
Liabilities
Level 1
Included in Level 1 of the fair value hierarchy as commodity derivative contracts are exchange-traded futures and exchange-traded option 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.
Level 2
At September 30, 2011 and December 31, 2010, we had no Level 2 fair value measurements.
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are: (i) observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values consist of forward commodity derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations.
Level 3
At September 30, 2011 and December 31, 2010, we had no Level 3 fair value measurements.
In 2010 and 2009, our interest rate swaps were included within Level 3 of the fair value hierarchy. These swaps were settled in July 2010 in connection with the acquisition of the 51% of DG Marine we did not own and the termination of DG Marine’s credit facility. The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as Level 3 in the fair value hierarchy:
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Balance at beginning of period
Realized and unrealized gains (losses)—
Reclassified into interest expense for settled contracts
Included in other comprehensive income
Balance at end of period
Total amount of losses included in earnings attributable to the change in unrealized losses relating to liabilities still held at
September 30, 2010
See Note 12 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.
14. 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.
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.
15. Subsequent Event – Acquisition of Interests in Gulf of Mexico Crude Oil Pipeline Systems
On October 28, 2011, we entered into definitive agreements to acquire from Marathon Oil Company, for $205.76 million, interests in several Gulf of Mexico crude oil pipeline systems, including its 28% interest in Poseidon Oil Pipeline Company, L.L.C., its 29% interest in Odyssey Pipeline L.L.C., and its 23% interest in the Eugene Island Pipeline System. The Poseidon 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 Odyssey 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. The Eugene Island Pipeline System is 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 Poseidon and Odyssey interests are subject to the expiration or waiver of rights of first refusal, and we are not obligated to consummate any transaction unless we are ultimately successful in acquiring the interest in Poseidon. Additionally, Marathon Oil has the right to dispose of certain of the other oil pipeline assets prior to any final closing of a transaction with us. The purchase consideration is subject to usual and customary adjustments (e.g., for debt, working capital, etc.) and includes an estimated $29 million valuation of crude oil line fill at current market prices owned by the interests to be acquired. We expect to finance that acquisition with funds available under our revolving credit facility. Subject to the satisfaction or waiver of the conditions to closing, we expect to close that transaction in the fourth quarter of 2011.
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16. Condensed Consolidating Financial Information
The $250 million 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. See Note 7 for additional information regarding our consolidated debt obligations.
As a result of our IDR Restructuring on December 28, 2010 (see Note 1), each guarantor subsidiary and the subsidiary co-issuer are 100% owned, directly or indirectly, by Genesis Energy, L.P.
The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries:
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Current assets:
Fixed Assets, at cost
Other assets, net
Equity investees and other investments
Investments in subsidiaries
Total assets
Current liabilities
Senior secured credit facilities
Senior unsecured notes
Deferred tax liabilities
Other liabilities
Total liabilities
Partners’ capital
Total liabilities and partners’ capital
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Supply and logistics costs
Equity in losses of joint ventures
Equity in earnings of subsidiaries
Interest (expense) income
Income tax (expense) benefit
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Equity in earnings of joint ventures
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Net cash (used in) provided by operating activities
Payments to acquire fixed and intangible assets, including the acquisition of FMT assets
Distributions from joint ventures—return of investment
Investments in joint ventures and other investments
Repayments on loan to non-guarantor subsidiary
Distributions to partners/owners
Issuance of ownership interests to partners for cash
Net increase (decrease) in cash and cash equivalents
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Net cash provided by (used) in investing activities
Transfer of senior secured credit facility to Parent
Credit facility and senior unsecured notes issuance fees
Net (decrease) increase in cash and cash equivalents
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Included in Management’s Discussion and Analysis are the following sections:
Overview
Segment Reporting Change
Available Cash before Reserves
Results of Operations
Liquidity and Capital Resources
Non-GAAP Reconciliation
Commitments and Off-Balance Sheet Arrangements
Forward Looking Statements
In the discussions that follow, we will focus on 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 9 to our Unaudited Condensed Consolidated Financial Statements.
Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation), 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 assets that provide new sources of cash flows, the elimination of earnings of DG Marine in excess of distributable cash until July 29, 2010 when DG Marine’s credit facility was repaid, 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. For additional information on Available Cash before Reserves and a reconciliation of this measure to its most directly comparable GAAP measure of cash provided by operating activities, see “Liquidity and Capital Resources—Non-GAAP Reconciliation” below.
In the third quarter of 2011, we reported net income attributable to the partnership of $19.1 million, or $0.27 per common unit. We generated $37.0 million of Available Cash before Reserves. In November 2011, we will distribute $0.4275 per common unit to our unitholders with respect to the third quarter. During the third quarter of 2011, cash provided by operating activities was $29.7 million.
Segment Margin increased by $13.6 million, or 34%, in the third quarter of 2011, as compared to the third quarter of 2010. This increase resulted from improvements in Segment Margin of approximately 34%, 11% and 68% in our pipeline transportation, refinery services and supply and logistics segments, respectively. The contribution to Segment Margin from our investment in Cameron Highway, combined with increased throughput on our onshore pipelines, were the primary factors increasing pipeline transportation Segment Margin. Our refinery services Segment Margin increased as a result of several factors, including operating efficiencies realized 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. Our supply and logistics segment, which now includes the results of our CO2 marketing and other industrial gases activities, benefited from increased volumes, operating efficiencies and modifications to our existing crude oil and petroleum products commercial arrangements. Segment Margin generated by the operations of the recently acquired black oil barge transportation business of FMT also increased the results of our supply and logistics segment.
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In the fourth quarter of 2011, we expect to complete the previously announced transaction to acquire from Marathon Oil Company, for $205.76 million, interests in several Gulf of Mexico crude oil pipeline systems, including its 28% interest in Poseidon Oil Pipeline Company, L.L.C., its 29% interest in Odyssey Pipeline L.L.C., and its 23% interest in the Eugene Island Pipeline System. The Poseidon and Odyssey interests are subject to the expiration or waiver of rights of first refusal, and we are not obligated to consummate any transaction unless we are ultimately successful in acquiring the interest in Poseidon. Additionally, Marathon Oil has the right to dispose of certain of the other oil pipeline assets prior to any final closing of a transaction with us. The purchase consideration is subject to usual and customary adjustments (e.g., for debt, working capital, etc.) and includes an estimated $29 million valuation of crude oil line fill at current market prices owned by the interests to be acquired. We expect to finance the acquisition with funds available under our revolving credit facility. See additional discussion under Liquidity and Capital Resources – Capital Resources/Sources of Cash below.
We believe this acquisition will complement our existing infrastructure in the Gulf of Mexico and enhance our ability to provide attractive capacity and market optionality to producers for their existing and future developments as well as our refining customers onshore Texas and Louisiana. The Poseidon 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. Affiliates of Enterprise Products Partners L.P. and Shell Oil Company each own a 36% interest in Poseidon. An affiliate of Enterprise will continue in its role as operator of Poseidon. The Odyssey 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 will continue to serve as the operator. The Eugene Island Pipeline System is 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 Oil Company. An affiliate of Shell will continue to serve as the operator.
On October 12, 2011, we increased our quarterly distribution rate to our common unitholders for the twenty-fifth consecutive quarter. In November of 2011, we will pay a distribution of $0.4275 per unit attributable to our third quarter of 2011, which represents an approximate 10.3% increase from our distribution of $0.3875 per unit for the third quarter of 2010. During the third quarter of 2011, we paid a distribution of $0.4150 per unit related to the second quarter of 2011.
In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates capital resources. We combined our supply and logistics segment and our industrial gases segment. Thus, the results of our CO2 marketing activities and processing of syngas through a joint venture are now included in our supply and logistics segment. Our disclosures related to prior periods have been recast to reflect our reorganized segments.
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Available Cash before Reserves was as follows:
Cash received from direct financing leases not included in income
Cash effects of sales of certain assets
Effects of available cash generated by equity method investees not included in income
Cash effects of equity-based compensation plans
Non-cash tax (benefit) expense
Loss of DG Marine in excess of distributable cash
Non-cash equity-based compensation (benefit) expense
Expenses related to acquiring or constructing assets that provide new sources of cash flow
Unrealized (gains) loss on derivative transactions excluding fair value hedges
Other items, net
We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the most comparable GAAP measure) for the three months ended September 30, 2011 and 2010 in “Liquidity and Capital Resources – Non-GAAP Reconciliation” below. For the three months ended September 30, 2011 and 2010, cash flows provided by operating activities were $29.7 million and $23.4 million, respectively.
Revenues, Costs and Expenses and Net Income
Our revenues for the three months ended September 30, 2011 increased $254.2 million, or 44% from the third quarter of 2010. Additionally, our costs and expenses increased $235.7 million, or 42% 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 third quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products. As an example, the closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $89.76 per barrel in the third quarter of 2011, as compared to $76.20 per barrel in the third quarter of 2010.
Net income (attributable to us) increased $14 million, or 277%, between the third quarter of 2010 and the same period in 2011. The significant factors affecting net income were improved operating results by our business segments and a decrease in general and administrative expenses offset partially by an increase in depreciation and amortization expense and interest costs. A more detailed discussion of our segment results and other costs is included below.
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Our revenues for the nine months ended September 30, 2011 increased $783.7 million, or 52% from the nine months ended September 30, 2010. Additionally, our costs and expenses increased $754.8 million, or 52% between the two periods. This increase in our revenues and costs between the two periods is primarily due to fluctuations in the market prices for crude oil and petroleum products. As an example, in the first nine months of 2011, average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $95.48 per barrel, as compared to $77.65 per barrel for the first nine months of 2010. Net income (attributable to us) increased $17.3 million, or 66%, between the first nine months of 2010 and the same period in 2011, with the majority of the increase attributable to improved segment results, partially offset by increases in general and administrative expenses, depreciation and amortization expense and interest costs as discussed below.
Segment Margin
The contribution of each of our segments to total Segment Margin in the three and nine months ended September 30, 2011 and 2010 was as follows:
Pipeline transportation
Total Segment Margin
Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment were as follows:
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
Sales of crude oil pipeline loss allowance volumes
Pro-rata share of distributable cash generated by Cameron Highway
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
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Pipeline System
Jay—Bbls/day
Texas—Bbls/day
Mississippi—Bbls/day
Cameron Highway—Bbls/day
Free State—Mcf/day
Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010
Pipeline transportation Segment Margin for the third quarter of 2011 increased $4.1 million. The significant components of this change were as follows:
Our share of the distributable cash generated by Cameron Highway was $2.8 million for the three months ended September 30, 2011. We acquired our 50% interest in Cameron Highway in November 2010. Revenue generating volumes on Cameron Highway were approximately 90,312 barrels per day, a 17% decrease from the average daily rate for the second quarter of 2011. Planned improvements to offshore field facilities by producers with fields connected to Cameron Highway were performed in the second and third quarters of 2011 and are expected to continue in the fourth quarter of 2011 due to weather-related and other delays. Although these field improvements by the producers are expected to increase volumes on Cameron Highway in the future, reductions in volumes while the improvements are made will likely negatively affect our share of distributable cash from the joint venture during the fourth quarter.
Crude oil tariffs and revenues from direct financing leases of onshore crude oil pipelines increased $1.3 million. Volumes transported on our onshore crude oil pipelines increased 10,977 barrels per day, with the increase in volumes attributable primarily to the Texas System where demand by the refiners connected to our system increased. Volumes on the Jay System increased 1,165 barrels per day, while volumes on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, decreased by 2,788 barrels a day, primarily as a result of fluctuations in tertiary recovery activities by producers.
Pipeline operating costs, excluding non-cash charges increased approximately $0.7 million primarily due to increased insurance costs (related to our investment in Cameron Highway) and employee salaries and benefits costs.
Nine Months Ended September 30, 2011 Compared with Nine Months Ended September 30, 2010
For the nine month periods, pipeline transportation Segment Margin increased $16.9 million. The primary factors in this increase were as follows:
Our share of the distributable cash generated by Cameron Highway was $13.8 million for the nine months ended September 30, 2011.
Crude oil tariffs and revenues from direct financing leases of onshore crude oil pipelines increased $3.1 million. Volumes transported on our crude oil pipelines increased 18,134 barrels per day, with the increase in volumes attributable primarily to the Texas System. Volumes on the Jay system increased 1,261 barrels per day, while volumes on the Mississippi System decreased 2,867 barrels per day. The fluctuations in volumes on our pipeline systems for the nine months ended 2011 as compared to the nine months ended 2010 are due to similar explanations as provided in the quarter to quarter discussion.
An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $1.2 million related to the significant increase (an average of $18 per barrel) in crude oil prices which more than offset the decrease in pipeline loss allowance volumes of approximately 2,628 barrels.
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Pipeline operating costs, excluding non-cash charges increased approximately $1.5 million, primarily due to increased insurance costs (related to our investment in Cameron Highway) and employee compensation and related benefit costs.
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 third quarter of 2011 was $18.0 million, an increase of $1.8 million, or 11%, from the comparative period in 2010. 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, as discussed below, helped offset these costs.
NaHS sales volumes decreased 5.7% between the third quarter periods. We understand that (i) difficulties in mining companies’ negotiations with their workforces led to a slowdown in mine activity and a decrease in our sales volumes to mining companies in the export market and (ii) planned maintenance at some of our pulp and paper customers’ facilities also contributed to the decline in volumes. Increased sales volumes to domestic mining customers slightly offset these decreases.
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Caustic soda sales volumes increased 9.3%. 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.
Index prices for caustic soda averaged approximately $378 per DST in the third quarter of 2010. Average index prices of caustic soda increased to approximately $540 per DST during the third 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, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we generally 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.
NaHS sales volumes for the first nine months of 2011 were consistent with the same period in 2010. Although there have been decreased levels of activity by our mining customers, as explained in the quarter to quarter comparison, the return of industrialization and urbanization in the world’s emerging economies has increased the demand for paper products and packaging materials. These trends have led to a noticeable increase in NaHS demand from our pulp and paper customers primarily in North America in 2011 as compared to 2010.
Caustic soda sales volumes increased 11.2%. 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 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.
Index prices of caustic soda increased to an average of $492 per DST during the first nine months of 2011 as compared to average index prices of caustic soda of $329 per DST in the comparable period of 2010. The pricing in our sales contracts for NaHS include 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. However, as discussed above, these changes in caustic soda prices do not materially affect Segment Margin. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although efficiencies gained from our bulk purchases, logistic and storage capabilities helped offset these 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 gains and losses from derivative transactions
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
Volumes of crude oil and petroleum products (barrels per day)
Three Months Ended September 30, 2011 as Compared to Three Months Ended September 30, 2010
The average market prices of crude oil and petroleum products increased by more than $13 per barrel, or approximately 17.8%, 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 $7.7 million, or 68%.
The increase in Segment Margin resulted primarily from increased volumes, operating efficiencies and changes we made in some of our existing crude oil and petroleum products commercial arrangements. Typically the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on price grade differentials. Increased production from new sources of crude oil, principally shale oil production, has increased demand for our services.
Segment Margin also increased approximately $2.9 million quarter to quarter due to the addition of the black oil barge transportation business acquired from FMT on August 9, 2011. See Note 3 of our Unaudited Condensed Consolidated Financial Statements for additional information regarding this acquisition.
Segment Margin for our supply and logistics segment increased $15.8 million, or 55%, between the nine month periods. Average market prices of crude oil and petroleum products increased by approximately $18 per barrel, or 23%, however, as previously discussed, price volatility has a limited impact on our Segment Margin.
Increased volumes, operating efficiencies and modifications to our existing crude oil and petroleum products commercial arrangements, were key factors resulting in increased Segment Margin. As discussed in the quarter to quarter discussion, increased production from new sources of crude oil has increased demand for our services.
Segment Margin for the nine month period also increased due to greater availability of volumes of heavy-end petroleum products resulting from increased refinery utilization in our operating area. The volumes we handled during the first nine months of 2011 increased approximately 17% as compared to the first nine months of 2010 as higher foreign demand for fuel oil and other heavy-end petroleum products helped sustain the price environment for the products we sell.
Segment Margin also increased approximately $2.9 million between the nine month periods due to the addition of the black oil barge transportation business acquired from Florida Marine on August 9, 2011. See Note 3 of our Unaudited Condensed Consolidated Financial Statements for additional information regarding this acquisition.
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Other Costs, Interest, and Income Taxes
General and administrative expenses. General and administrative expenses consisted of the following:
General and administrative expenses not separately identified below:
Corporate
Segment
Bonus plan expense
Equity-based compensation plan expense
Third party costs related to business development activities and growth projects
Expenses related to change in owner of our general partner
Non-cash compensation expense related to management team
Total general and administrative expenses
Routine corporate and segment general and administrative expenses increased between the three and nine month periods due to an increase in personnel resulting in greater salaries and benefits expenses. Our bonus plan expenses increased $0.3 million and $0.9 million for the three and nine months ended September 30, 2011, respectively, related to a higher level of bonus accrual as a result of improvements in our operating results. An increase in activities evaluating potential business and growth opportunities resulted in an increase of approximately $0.6 million and $3.0 million, for the three and nine month periods, respectively, for costs paid to third parties for their assistance in these activities. Increases in general and administrative costs for both the three and nine month periods were partially offset due to the non-cash compensation expense we recorded in the three and nine month periods of 2010 related to the arrangements between our executive management team and our former general partner. Fluctuations in the market price of our Class A Common Units also affected equity compensation expense in the comparison of the three and nine month periods.
Depreciation and amortization expense. Depreciation and amortization expense increased $1.1 million and $2.3 million between the three and nine month periods, respectively primarily as a result of an adjustment in the useful lives of certain of our intangible assets in the first quarter of 2011 and depreciation expense related to the assets related to the acquisition of the black oil barge transportation business of FMT. See Notes 3 and 6 to our Unaudited Condensed Consolidated Financial Statements for additional information regarding the FMT acquisition and the change in useful lives of our intangible assets, respectively.
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Interest expense, net.
Interest expense, net was as follows:
Genesis Facility and Notes:
Interest expense, credit facility, including commitment fees
Interest expense, senior unsecured notes
Amortization of credit facility and notes issuance fees
Write-off of facility fees
DG Marine Facility:
Interest expense and commitment fees
Interest rate swaps settlement
Interest income
Net interest expense
Interest expense on our credit facility decreased between the quarterly periods as our average debt balance decreased $61 million. In the latter part of 2010, our debt balance was higher primarily as a result of acquisitions. Cash flow from our operations as well as funds from an equity offering resulted in the decrease in our average debt balance. See Note 8 to our Unaudited Condensed Consolidated Financial Statements for additional information regarding our July 2011 equity offering. Our average interest rate for borrowed funds under our credit facility between the quarterly periods was consistent at 3.2%. A reduction in the applicable margin under our credit facility as a result of an amendment in August 2011 was offset by an increase in market interest rates.
Interest expense on our credit facility increased between the nine month periods as our average debt balance increased $12.8 million. The increase in the average outstanding balance under our credit facility over the nine-month periods is attributable primarily to acquisitions in the second half of 2010. The average interest rate for borrowed funds increased by less than 1% over the nine-month periods, from 2.6% to 3.2%. When we amended and extended our credit facility in June 2010, our average interest rate increased to reflect market conditions at that time. However, interest expense was somewhat offset when we subsequently amended our credit facility in August 2011 reducing the applicable margins on our alternate base rate and Eurodollar borrowings, as discussed in Note 7 to our Unaudited Condensed Consolidated Financial Statements.
We also incurred interest expense, including amortization of notes issuance fees, of $5.3 million and $15.6 million during the quarter and first nine months of 2011, respectively in connection with the $250 million of senior unsecured notes issued in November 2010 to partially finance our acquisition of a 50% equity interest in Cameron Highway.
Interest expense in the first nine months of 2010 was also affected by interest on the DG Marine credit facility. In July of 2010, we eliminated this facility with borrowings under our credit facility.
Income tax expense. 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.
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General
As of September 30, 2011, we had $402.8 million of borrowing capacity available under our $775 million senior secured bank 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.
We continue to pursue a growth strategy that requires significant capital. On August 9, 2011, we completed the acquisition of the black oil barge transportation business of Florida Marine for $143.5 million ($141 million plus $2.5 million for fuel inventory and other costs). The transaction added 30 barges and 14 push boats to our marine fleet, which transport heavy refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers.
As discussed above, in the fourth quarter of 2011, we expect to complete the previously announced transaction to acquire from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems, including its 28% interest in Poseidon Oil Pipeline Company, L.L.C., its 29% interest in Odyssey Pipeline L.L.C., and its 23% interest in the Eugene Island Pipeline System, for $205.76 million. We expect to finance the acquisition with the approximately $400 million of funds available under our revolving credit facility.
On April 11, 2011, we announced plans to expand our crude oil infrastructure in Texas through the acquisition and refurbishment of three crude oil tanks with barge dock access, and to increase our refinery services operating footprint to provide services to a refinery in Tulsa, Oklahoma.
Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital— including through equity and debt offerings (public and private) and other financing transactions and borrowings under our credit facility—and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms. If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.
On August 19, 2011, we amended our senior secured revolving credit facility to increase the committed amount from $525 million to $775 million and the accordion feature from $125 million to $225 million, giving us the ability to expand the size of the facility up to an aggregate $1 billion for acquisitions or internal growth projects, with lender approval. The amendment also increased the inventory sublimit tranche from $75 million to $125 million. 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. Fourteen lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility.
In July 2011, we issued 7,350,000 Class A common units at $26.30, providing total net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $185 million. We used approximately $143.5 million of the proceeds from this offering to fund the purchase price and related transaction costs for our acquisition of the black oil barge transportation business of FMT. The remaining net proceeds of the offering were used for other purposes, including the repayment of borrowings outstanding under our credit facility.
Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2011 includes total long-term debt of $617.9 million, consisting of $367.9 million outstanding under our credit facility and $250 million of senior unsecured notes due in 2018. Included in the $367.9 million outstanding under our credit facility is $47.9 million borrowed under the inventory sublimit tranche.
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.
Net cash flows provided by our operating activities for the nine months ended September 30, 2011 were approximately $39.1 million. 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. At September 30, 2011, the cost of the inventory on our balance sheet increased by $34.3 million from December 31, 2010. Sales of inventory in late September 2011 that were collected in October 2011, combined with higher market prices, increased net accounts receivable at September 30, 2011 as compared to December 31, 2010.
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 in the first nine months of 2011 and 2010 is as follows:
Capital expenditures for property, plant and equipment:
Maintenance capital expenditures:
Pipeline transportation assets
Supply and logistics assets
Refinery services assets
Other assets
Total maintenance capital expenditures
Growth capital expenditures:
Information technology systems upgrade project
Total growth capital expenditures
Capital expenditures for asset purchases:
Total capital expenditures
On August 9, 2011, we completed the acquisition of the black oil barge transportation business of FMT consisting of 30 barges (7 of which are sub-leased under similar terms of an existing FMT lease) and 14 pushboats for approximately $143.5 million ($141 million plus $2.5 million for fuel inventory and other costs).
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Maintenance capital expenditures for 2011 are anticipated to total approximately $4 million to $5 million. While our 2012 budget for maintenance capital expenditures has not yet been finalized, we would expect to spend $4 million to $5 million per year on maintenance capital projects in future years.
On April 11, 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, representing aggregate capacity of approximately 230,000 barrels that we will refurbish and convert into crude-oil-capable tanks. We also acquired 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 at West Columbia, Texas, to be able 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 as well as markets accessible via barge from the new Texas City terminal. Once the refurbishment, tie-in and all interconnecting pipe is completed, estimated to be in the first quarter of 2012, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal. In connection with our activities in Texas, we are also constructing interconnecting pipeline and other required facilities to provide transportation services for all of the crude oil production from the Hastings field, near Alvin, Texas, which is in the very early stages of a CO2 tertiary recovery program. This connection will be completed in the fourth quarter of 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 no later than the fourth quarter of 2012, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and result in potential additional capacity of 24,000 tons per year of NaHS.
We anticipate the total costs of these projects to be less than $30 million in total, which we expect will be incurred primarily in the fourth quarter of 2011 and first quarter of 2012. Through September 30, 2011, expenditures related to these projects totaled $5.7 million.
As discussed above, in the fourth quarter of 2011, we expect to complete the previously announced transaction to acquire from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems, including its 28% interest in Poseidon Oil Pipeline Company, L.L.C., its 29% interest in Odyssey Pipeline L.L.C., and its 23% interest in the Eugene Island Pipeline System, for $205.76 million.
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.
Distributions to Unitholders
On November 14, 2011, we will pay a distribution of $0.4275 per common unit with respect to the third quarter of 2011 to common unitholders of record on November 3, 2011. This is the twenty-fifth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 8 to our Unaudited Condensed Consolidated Financial Statements.
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 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 cost 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
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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. The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.
Available Cash before Reserves is a liquidity 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 (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended September 30, 2011 is as follows:
Net cash flows provided by operating activities (GAAP measure)
Adjustments to reconcile operating cash flows to Available Cash before Reserves:
Proceeds from sales of certain assets
Amortization and write-off of credit facility issuance fees
Effects of available cash generated by equity method investees not included in cash flows from operating activities
Other items affecting available cash
Net effect of changes in operating accounts not included in calculation of Available Cash
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, 2010.
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, 2010, nor do we have any debt or equity triggers based upon our unit or commodity prices.
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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, natural gas and natural gas liquids, 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, develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
the satisfaction of the closing conditions of strategic acquisitions (including obtaining third party consents and waivers of preferential rights) and unanticipated costs, liabilities or delays associated with such acquisitions;
service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;
shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, natural gas or other products 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;
capital and credit markets conditions, inflation and interest rates;
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natural disasters, accidents or terrorism;
changes in the financial condition of customers;
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, 2010 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 2010 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 12 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.
During the first and second quarters of 2011, we substantially completed a staged implementation of a Enterprise Resource Planning system. We changed systems in order to (i) establish a platform that accommodates future acquisitions and growth opportunities (ii) integrate and automate more of our functions, which will allow us to have more information in one integrated database, (iii) to provide operating efficiencies, (iv) to enable us to close our books in a more timely manner without sacrificing quality, (v) to review and improve our processes and (vi) to improve the internal control surrounding our computer systems. As a result of moving to a new system in 2011, many business processes and internal control procedures were required to be changed in order to conform to our new system.
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, 2010. 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, 2010. 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.
None.
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Item 3. Defaults Upon Senior Securities.
Item 4. [Removed and Reserved]
Item 5. Other Information.
Item 6. Exhibits
(a) Exhibits.
3.1
3.2
3.3
3.4
3.5
3.6
4.1
10.1
31.1
31.2
32
101.INS
101.SCH
101.CAL
101.LAB
101.PRE
101.DEF
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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
Date: November 8, 2011
Chief Financial Officer
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