Genesis Energy L.P. - 10-Q quarterly report FY

 In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures about our derivative and hedging activities. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009, and have included the enhanced disclosures in Note 15.

In March 2008, the FASB ratified the consensus reached by the Emerging Issues Task Force (or EITF) of the FASB in issue EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.”  Under this consensus, the computation of earnings per unit will be affected by the incentive distribution rights (“IDRs”) we are contractually obligated to distribute at the end of the current reporting period.  In periods when earnings are in excess of cash distributions, we will reduce net income or loss for the current reporting period (for purposes of calculating earnings or loss per unit) by the amount of available cash that will be distributed to our limited partners and general partner for its general partner interest and incentive distribution rights for the reporting period, and the remainder will be allocated to the limited partner and general partner in accordance with their ownership interests.  When cash distributions exceed current-period earnings, net income or loss (for purposes of calculating earnings or loss per unit) will be reduced (or increased) by cash distributions, and the resulting excess of distributions over earnings will be allocated to the general partner and limited partner based on their respective sharing of losses.  EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  We adopted EITF 07-4 on January 1, 2009 and have reflected the calculation of earnings per unit for the three months ended March 31, 2009 and 2008 in accordance with its provisions.  See Note 9.

DG Marine is a joint venture we formed with TD Marine. TD Marine owns (indirectly) a 51% economic interest in DG Marine, and we own (directly and indirectly) a 49% economic interest.  This joint venture gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.

We have entered into a subordinated loan agreement with DG Marine whereby we may (at our sole discretion) lend up to $25 million to DG Marine.  The loan agreement provides for DG Marine to pay us interest on any loans at a rate to be determined which is expected to be the prime rate plus 4%.  Those loans will mature on January 31, 2012.  Under that subordinated loan agreement, DG Marine is required to make monthly payments to us of principal and interest to the extent DG Marine has any available cash that otherwise would have been distributed to the owners of DG Marine in respect of their equity interest.  DG Marine also has a revolving credit facility with a syndicate of financial institutions that includes restrictions on DG Marine’s ability to make specified payments under our subordinated loan agreement and distributions in respect of our equity interest.  At March 31, 2009 and December 31, 2008, there were no amounts outstanding under the subordinated loan agreement. We have, however, provided a $7.5 million guaranty to the lenders under DG Marine’s credit facility.  That guaranty will be terminated on May 31, 2009, if DG Marine maintains a leverage ratio under its credit facility of less than 4.50 to 1.00 for the month ending May 31, 2009.

At March 31, 2009 and December 31, 2008, our unaudited consolidated balance sheets included the following amounts related to DG Marine:

The following table reflects the components of intangible assets being amortized at the dates indicated:

We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows.  Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made.  The favorable lease and other intangible assets are being amortized on a straight-line basis.  Amortization expense on intangible assets was $8.2 million and $11.7 million for the three months ended March 31, 2009 and 2008, respectively.

The carrying amount of goodwill by business segment at March 31, 2009 and December 31, 2008 was $302.0 million to refinery services and $23.1 million to supply and logistics.

We are accounting for our 50% ownership in T&P Syngas under the equity method of accounting.  We received distributions from T&P Syngas of $0.4 million and $0.6 million during the three months ended March 31, 2009 and 2008, respectively.  During the first quarter of 2009, “Equity in earnings of joint ventures” included $1.7 million of non-cash items related to T&P Syngas that increased earnings.

The tables below reflect summarized information for T&P Syngas:

Partner’s capital at March 31, 2009 consists of 39,456,774 common units, including 4,028,096 units owned by our general partner and its affiliates, representing a 98% aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest), and a 2% general partner interest.

Our general partner owns all of our general partner interest, our incentive distribution rights, and all of the 0.01% general partner interest in Genesis Crude Oil, L.P. (which is reflected as a non-controlling interest in our Unaudited Consolidated Balance Sheets) and operates our business.

Without obtaining unitholder approval, we may issue an unlimited number of additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs.

We will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner.  Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves.

Pursuant to our partnership agreement, our general partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds.  The allocations of distributions between our common unitholders and our general partner (including its general partner interest and the incentive distribution rights) are as follows:

We paid or will pay the following distributions in 2008 and 2009:

(1)  This distribution will be paid on May 15, 2009 to our general partner and unitholders of record as of May 4, 2009.

Our operations consist of four operating segments:  (1) Pipeline Transportation – interstate and intrastate crude oil and CO2; (2) Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and selling the related by-product; (3) Supply and Logistics – terminaling, blending, storing, marketing, gathering and transporting by truck and barge crude oil and petroleum products, and (4) Industrial Gases – the sale of CO2 acquired under volumetric production payments to industrial customers and our investment in a syngas processing facility. All of our revenues are derived from, and all of our assets are located in the United States.

During the fourth quarter of 2008, we revised the manner in which we internally evaluate our segment performance.  As a result, we changed our definition of segment margin to include within segment margin all costs that are directly associated with the business segment.  Segment margin now includes costs such as general and administrative expenses that are directly incurred by the business segment.  Segment margin also includes all payments received under direct financing leases.  In order to improve comparability between periods, we exclude from segment margin the non-cash effects of our stock-based compensation plans which are impacted by changes in the market price for our common units.  Segment information for the three months ended March 31, 2008 has been retrospectively revised to conform to this segment presentation.  We now define segment margin as revenues less cost of sales, 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 joint ventures.  Our segment margin definition also excludes the non-cash effects of our stock-based compensation plans, 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.

We provide truck transportation services to Denbury to move its crude oil from the wellhead to our Mississippi pipeline.  Denbury pays us a fee for that trucking service which varies with the distance we haul its crude oil.  Those fees are reflected in the Unaudited Consolidated Statements of Operations as supply and logistics revenues.

Denbury is the only shipper (other than us) on our Mississippi pipeline, and we earn tariffs for transporting its oil.  We earned fees from Denbury for the transportation of its CO2 on our Free State pipeline.  We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven and NEJD CO2 pipelines and recorded pipeline transportation income from those arrangements.

We also provide pipeline monitoring services to Denbury.  That revenue is included in pipeline revenues in our Unaudited Consolidated Statements of Operations.

We paid Denbury for the services of each of four of Denbury’s officers who serve as directors of our general partner.  The annual rate and rate for attendance at meetings are the same as the rates at which our other directors were paid.

Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver CO2 for us to our customers.   In the first three months of 2009, the inflation-adjusted transportation fee averaged $0.1978 per Mcf.

We do not directly employ any persons to manage or operate our business.  Those functions and personnel are provided by our general partner.  We reimburse our general partner for all direct and indirect costs of those services, excluding any payments to our management team pursuant to their Class B Membership Interests.  See Note 12.

At March 31, 2009 and December 31, 2008, we owed Denbury $2.6 million and $1.0 million, respectively, for CO2 transportation charges and purchases of crude oil.  Denbury owed us $1.6 million and $2.0 million for transportation services at March 31, 2009 and December 31, 2008, respectively.  We owed our general partner $0.8 million and $2.1 million for administrative services at March 31, 2009 and December 31, 2008, respectively.  At both March 31, 2009 and December 31, 2008, Sandhill owed us $0.7 million for purchases of CO2.

Our partner in the DG Marine joint venture is TD Marine, a joint venture consisting of three members of the Davison family.

Our credit facility is non-recourse to our general partner, except to the extent of its pledge of its 0.01% general partner interest in Genesis Crude Oil, L.P.  Our general partner’s principal assets are its general and limited partnership interests in us.  Our credit agreement obligations are not guaranteed by Denbury or any of its other subsidiaries.  

We guarantee 50% of the obligation of Sandhill to a bank.  At March 31, 2009, the total amount of Sandhill’s obligation to the bank was $3.0 million; therefore, our guarantee was for $1.5 million.

Approximately 14% of the outstanding common shares of Community Trust Bank are held by Davison family members.  Community Trust Bank is a 17% participant in the DG Marine credit facility.  James E. Davison, Jr., a member of our board of directors, also serves on the board of the holding company that owns Community Trust Bank.

As discussed in Note 12, we recorded a non-cash capital contribution from our general partner of $2.1 million for the three months ended March 31, 2009 related to the Class B Membership Awards for our executive management team.

As part of finalizing the compensation arrangements for our Senior Executives on December 31, 2008, our general partner awarded them an equity interest in our general partner as long-term incentive compensation. Those Class B Membership Interests compensate the holders thereof by providing rewards based on increased shares of the cash distributions attributable to our incentive distribution rights (or IDRs) (See Note 9) to the extent we increase Cash Available Before Reserves, or CABR (defined below) (from which we pay distributions on our common units) above specified targets.   CABR generally means Available Cash before Reserves, less Available Cash before Reserves generated from specific transactions with our general partner and its affiliates (including Denbury Resources Inc.) The Class B Membership Interests do not provide any Senior Executive with a direct interest in any assets (including our IDRs) owned by our general partner.

Our general partner has agreed that it will not seek reimbursement (on behalf of itself or its affiliates) under our partnership agreement for the costs of these Senior Executive compensation arrangements to the extent relating to their ownership of Class B Membership Interests (including current cash distributions made by the general partner out of its IDRs and payment of redemption amounts for those IDRs) and the deferred compensation amounts.  Although our general partner will not seek reimbursement for the costs of the Class B Membership Interests and deferred compensation plan arrangements, we will record non-cash compensation expense.   The Class B Membership Interests awarded to our senior executives are accounted for as liability awards under the provisions of SFAS 123(R).  As such, the fair value of the compensation cost we record for these awards is recomputed at each measurement date and the expense to be recorded is adjusted based on that fair value.  Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates.  Additionally the determination of fair value is affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control.  Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period.  These assumptions were used to estimate the total amount that would be paid under the Class B Membership awards through the final vesting date and do not represent the contractual amounts payable under these awards at the reporting date.

At March 31, 2009, we computed the fair value of the awards utilizing a discount rate of 15%, representing the risks inherent in the assumptions we used and the time until final vesting.  Due to the limited number of participants in the Class B Membership awards, we assumed a forfeiture rate of zero.  At March 31, 2009, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $19.9 million.  Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at March 31, 2009.

The fair value of these incentive awards will be recomputed each quarter through the final settlement of the awards.  The fair value to be recorded by us as compensation expense in each quarterly period will be the excess of the recomputed estimated fair value over the previously recorded amounts, and will consider the vesting conditions for the awards.  This expense will be recorded on an accelerated basis to align with the requisite service period of the award.  Changes in our assumptions will change the amount of compensation cost we record.  For the three months ended March 31, 2009, we recorded expense of $2.1 million.

We guaranteed $1.2 million of residual value related to the leases of trailers from a lessor.  We believe the likelihood that we would be required to perform or otherwise incur any significant losses associated with this guarantee is remote.

We guaranteed 50% of the obligations of Sandhill under a credit facility with a bank.  At March 31, 2009, Sandhill owed $3.0 million; therefore our guaranty was $1.5 million.  Sandhill makes principal payments for this obligation totaling $0.6 million per year.

We are subject to various environmental laws and regulations.  Policies and procedures are in place to monitor compliance and to detect and address any 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.

Our facilities and operations may experience damage as a result of an accident or natural disaster.  Such hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.  We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable.  Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues.  The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations.

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 cash generated by our joint ventures in lieu of our equity income attributable to such joint ventures, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) 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 cash flows from operations, see “Liquidity and Capital Resources - Non-GAAP Reconciliation” below.

In the first quarter of 2009, we reported net income of $5.3 million, or $0.16 per common unit.  Non-cash expense related to our senior executive compensation arrangements totaling $2.1 million reduced net income during the first quarter.  See additional discussion of our senior executive compensation expense in “Results of Operations – Other Costs, Interest and Income Taxes” below.

During the first quarter of 2009, we generated $21.3 million of Available Cash before Reserves, and we will distribute $14.7 million to holders of our common units and general partner for the first quarter.  During the first quarter of 2009, cash provided by operating activities was $3.2 million.

Segment margin for most of our segments increased in the first quarter 2009 as compared to the first quarter of 2008.  A significant portion of the increase was attributable to acquisitions during 2008, specifically the two drop down transactions with Denbury in May 2008 and the acquisition of our interest in DG Marine in July 2008.

On April 7, 2009, we announced that our distribution to our common unitholders relative to the first quarter of 2009 will be $0.3375 per unit (to be paid in May 2009).   This distribution amount represents a 12.5% increase from our distribution of $0.30 per unit for the first quarter of 2008.  During the first quarter of 2009, we paid a distribution of $0.33 per unit related to the fourth quarter of 2008.

The current economic crisis has restricted the availability of credit and access to capital in our business environment.  Despite efforts by U.S. Treasury and banking regulators to provide liquidity to the financial sector, capital markets continue to remain constrained.  While we anticipate that the challenging economic environment will continue for the foreseeable future, we believe that our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital needs.  The financial performance of our existing businesses, $177.0 million in cash and existing debt commitments and no need, other than opportunistically, to access the capital markets, may allow us to take advantage of acquisition and/or growth opportunities that may develop.

Our ability to fund large new projects or make large acquisitions in the near term may be limited by the current conditions in the credit and equity markets which may impact our ability to issue new debt or equity financing.  We may consider other arrangements to fund large growth projects and acquisitions such as private equity and joint venture arrangements.

Available Cash before Reserves was as follows (in thousands):

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2009 in “Liquidity and Capital Resources – Non-GAAP Reconciliation” below.  For the three months ended March 31, 2009 and 2008, cash flows provided by operating activities were $3.2 million and 17.4 million, respectively.

The contribution of each of our segments to total segment margin in the first quarters of 2009 and 2008 was as follows:

Operating results for our pipeline transportation segment were as follows:

Three Months Ended March 31, 2009 Compared with Three Months Ended March 31, 2008

Pipeline segment margin for the first quarter of 2009 increased $5.6 million as compared to the first quarter of 2008.  The significant component of this change is an increase in revenues from CO2 financing leases and tariffs of $6.7 million and a related increase in non-income payments from the same financing leases of $0.8 million.  Reducing the impact of this increase were decreases in revenues from sales of pipeline loss allowance volumes of $1.7 million and revenues from crude oil tariffs and related sources of $0.2 million.

Tariff and direct financing lease revenues from our crude oil pipelines decreased $0.2 million primarily due to volume decreases on our Jay pipeline system totaling 5,183 barrels per day as compared to the first quarter of 2008. The decreased volumes were principally due to a producer connected to our Jay System shutting in production in the first quarter of 2009.  Volumes on the Mississippi and Texas systems increased in the 2009 first quarter slightly offsetting the impact on tariff revenue of the Jay System decline.

The decline in market prices for crude oil reduced pipeline loss allowance revenues.  Average crude oil market prices decreased approximately $54 per barrel between the two quarters.  Additionally, pipeline loss allowance volumes combined with net volumetric measurement gains were 10,700 barrels greater in the first quarter of 2008 than the first quarter of 2009.  The combination of these two declines resulted in a decrease of $1.7 million in pipeline loss allowance revenues.

Revenues and payments related to CO2 pipelines increased by a total of $7.5 million between the two quarters, with $5.2 million attributable to the NEJD pipeline and $2.3 million to the Free State pipeline.  The average volume transported on the Free State pipeline for the first quarter of 2009 was 171 MMcf per day, with the transportation fees and the minimum payments totaling $2.0 million and $0.3 million, respectively.

Segment margin from our refinery services for the first quarter of 2009 was $12.8 million.  Segment margin from our refinery services for the same period in 2008 was $12.4 million.  The increase in segment margin is primarily related to the decline in sales volumes of NaHS being substantially offset by increased sales of caustic soda and by cost management and logistics optimization.  The current macroeconomic conditions have negatively impacted the short-term demand for NaHS, primarily in mining and industrial activities.  To help mitigate the financial effects of the decline in NaHS sales, we have been successful in selling caustic soda not needed in our operations and using our existing logistical assets to support such marketing to third parties.  The key cost components of the provision of the refinery sulfur removal service continued to be volatile in the first quarter of 2009.  Market prices for caustic soda, as published by the Chemical Market Associates, Inc. (CMAI) ranged from $400 to $500 per dry short ton (DST) during the first quarter of 2008 compared to a range of $580 to $750 per DST in the first quarter of 2009.   Our freight costs during the first quarter periods fluctuated with freight demand and fuel prices, both of which were significantly higher in the 2008 period.  We believe that we were successful in mitigating some of the impact on segment margin of the volatility of these costs through our management of caustic acquisition and freight costs and by indexing our sales prices for NaHS to caustic market prices.

The table below reflects information about NaHS sales for first quarters of 2009 and 2008 volumes and sales prices.

NaHS sales prices per DST increased as we adjusted these prices throughout 2008 for fluctuations in the cost components of our services.  As discussed above, market prices for caustic were volatile in both periods.  Additionally, freight costs for delivering NaHS to our customers fluctuated in both periods in a manner similar to the freight costs associated with our caustic supply as discussed above.  We were generally successful in increasing our sales prices for NaHS to compensate for these cost fluctuations by indexing approximately 60% of our NaHS sales volumes to market prices for caustic soda and by adjusting sales prices for NaHS as fuel surcharges billed to us increased.

In the first quarter of 2009, the contribution to segment margin of the other activities of our refinery services segment was $2.1 million more than in the first quarter of 2008, primarily resulting from selling caustic soda not needed in our operations.

Operating results from our supply and logistics segment were as follows: