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| GEL > SEC Filings for GEL > Form 10-Q on 9-Nov-2009 | All Recent SEC Filings |
9-Nov-2009
Quarterly Report
Included in Management's Discussion and Analysis are the following sections:
· Overview
· Available Cash before Reserves
· Results of Operations
· Liquidity and Capital Resources
· Commitments and Off-Balance Sheet Arrangements
· New Accounting Pronouncements
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. 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 a business segment. Segment margin now includes costs such as general and administrative expenses that are directly incurred by a 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. Previous periods have 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. In addition, our segment margin definition 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. A reconciliation of segment margin to income before income taxes is included in our segment disclosures in Note 10 to the 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 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.
Overview
In the third quarter of 2009, we reported net income attributable to the partnership of $4.3 million, or $0.14 per common unit. Non-cash expense related to our senior executive compensation arrangements totaling $3.1 million reduced net income during the third quarter. See additional discussion of our senior executive compensation expense in "Results of Operations - Other Costs, Interest and Income Taxes" below.
During the third quarter of 2009, we generated $23.7 million of Available Cash before Reserves, and we will distribute $15.9 million to holders of our common units and general partner for the third quarter. During the third quarter of 2009, cash provided by operating activities was $36.8 million.
Macroeconomic conditions have adversely affected business conditions in several of the industries that we service, and, consequently, us. Segment margin as compared to the third quarter of 2008, after consideration of the effects of acquisitions in 2008, declined for three of our segments. However, total segment margin increased from the first quarter to second quarter of 2009 and further increased $2.3 million in the third quarter when compared to the second quarter of 2009.
On October 13, 2009, we announced that our distribution to our common unitholders relative to the third quarter of 2009 will be $0.3525 per unit (to be paid in November 2009). This distribution amount represents a 9.3% increase from our distribution of $0.3225 per unit for the third quarter of 2008. During the third quarter of 2009, we paid a distribution of $0.3450 per unit related to the second quarter of 2009.
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, certain components of the 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 and the fact that we do not need to access the capital markets (other than opportunistically), 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
Available Cash before Reserves was as follows (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
Net income attributable to Genesis
Energy, L.P. $ 4,299 $ 10,763 $ 14,045 $ 19,736
Depreciation and amortization 15,806 18,100 47,358 51,610
Cash received from direct financing
leases not included in income 951 893 2,787 1,437
Cash effects of sales of certain assets 156 147 613 573
Effects of available cash generated by
equity method investees not included in
income 787 401 (332 ) 1,467
Cash effects of stock-based compensation
plans (77 ) (113 ) (84 ) (384 )
Non-cash tax (benefit) expense (3 ) (2,462 ) 1,084 (3,388 )
Earnings of DG Marine in excess of
distributable cash (1,108 ) (428 ) (3,982 ) (428 )
Non-cash equity-based compensation
expense (benefit) 4,454 (610 ) 10,448 (958 )
Other non-cash items, net (214 ) (1,156 ) (914 ) (1,174 )
Maintenance capital expenditures (1,336 ) (1,983 ) (3,758 ) (2,967 )
Available Cash before Reserves $ 23,715 $ 23,552 $ 67,265 $ 65,524
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We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the three and nine months ended September 30, 2009 and 2008 in "Liquidity and Capital Resources - Non-GAAP Reconciliation" below. For the three and nine months ended September 30, 2009, cash flows provided by operating activities were $36.8 million and $55.8 million, respectively. For the three and nine months ended September 30, 2008, cash flows provided by operating activities were $33.5 million and $56.2 million, respectively.
Results of Operations
The contribution of each of our segments to total segment margin in the three
and nine month periods ended September 30, 2009 and 2008 was as follows:
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in thousands) (in thousands)
Pipeline transportation $ 10,269 $ 11,474 $ 30,841 $ 23,396
Refinery services 12,694 11,486 38,643 40,195
Supply and logistics 9,423 9,754 21,979 21,595
Industrial gases 2,893 3,906 8,785 10,791
Total segment margin $ 35,279 $ 36,620 $ 100,248 $ 95,977
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Pipeline Transportation Segment
Operating results for our pipeline transportation segment were as follows:
Three Months Ended
September 30 Nine Months Ended September 30
Pipeline System 2009 2008 2009 2008
Mississippi-Bbls/day 22,643 25,232 24,046 24,323
Jay - Bbls/day 10,550 13,817 9,767 13,422
Texas - Bbls/day 24,593 25,627 26,477 28,298
Free State - Mcf/day 133,038 155,131 146,160 154,408 (1)
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(1) Represents the volume per day for the four months we owned the pipeline in the 2008 period.
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in thousands) (in thousands)
Crude oil tariffs and revenues from
direct financing leases of crude oil
pipelines $ 4,511 $ 4,228 $ 12,461 $ 12,333
Non-income payments under direct
financing leases 951 893 2,787 1,437
Sales of crude oil pipeline loss
allowance volumes 922 2,333 3,127 7,659
CO2 tariffs and revenues from direct
financing leases of CO2 pipelines 6,361 6,647 19,481 8,971
Tank rental reimbursements and other
miscellaneous revenues 171 35 488 468
Revenues from natural gas tariffs and
sales 456 1,182 1,727 4,165
Natural gas purchases (395 ) (1,136 ) (1,519 ) (3,990 )
Pipeline operating costs, excluding
non-cash charges for our equity-based
compensation plans and other non-cash
charges (2,708 ) (2,708 ) (7,711 ) (7,647 )
Segment margin $ 10,269 $ 11,474 $ 30,841 $ 23,396
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Three Months Ended September 30, 2009 Compared with Three Months Ended September 30, 2008
Pipeline segment margin for the third quarter of 2009 decreased $1.2 million as compared to the third quarter of 2008. The significant components of this change were as follows:
· A decrease in revenues from sales of pipeline loss allowance volumes reduced segment margin by $1.4 million. The decline in market prices for crude oil reduced the value of our pipeline loss allowance volumes and, accordingly, our loss allowance revenues. Average crude oil market prices decreased approximately $50 per barrel between the two quarters. In addition, pipeline loss allowance volumes decreased approximately 5,600 barrels between the periods.
· A decline in volumes transported on our crude oil pipelines between the two periods decreased segment margin by $0.4 million. The decreased volumes were principally due to a producer connected to our Jay System shutting in production in 2009 due to the decline in crude oil prices in the latter half of 2008. Volume fluctuations on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, are primarily a result of Denbury's crude oil production activities. The impact of volume decreases on the Texas System on revenues is not very significant due to the relatively low tariffs on that system. Approximately 77% of the volume on that system in the third quarter was shipped on a tariff of $0.31 per barrel.
· A decrease in revenues and payments related to CO2 pipelines of $0.3 million between the two quarters, although an increase of $0.1 million in payments under direct financing leases not affecting income partially offset this decrease. The remaining $0.2 million decrease was related to the Free State pipeline. The average volume transported on the Free State pipeline for the third quarter of 2009 was 133 MMcf per day, with the transportation fees and the minimum payments totaling $1.6 million and $0.3 million, respectively. Transportation fees and the minimum payments for the 2008 third quarter were $1.9 million and $0.3 million, respectively, with the average transportation volume at 155 MMcf per day. Denbury has exclusive use of this pipeline and variations in its CO2 tertiary oil recovery activities create the fluctuations in the volumes transported on the Free State pipeline.
· Tariff rate increases of approximately 7.6% on our Jay and Mississippi pipelines went into effect July 1, 2009, partially mitigating the effects of lower crude oil pipeline volumes. The rate increases increased segment margin between the two periods by approximately $0.7 million.
Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008
Pipeline segment margin between the nine month periods increased $7.4 million. The significant component of this change was an increase in revenues from CO2 financing leases and tariffs of $10.5 million and a related increase in non-income payments from the same financing leases of $1.4 million. The nine-month period in 2008 only included results from the NEJD and Free State CO2 pipelines for a four-month period while the 2009 period included nine months of results.
Partially offsetting these increases was a decrease in revenues from sales of pipeline loss allowance volumes of $4.5 million related almost exclusively to the significant decline (an average of $56 per barrel) in crude oil prices between the two periods.
Refinery Services Segment
Operating results for our refinery services segment were as follows:
Nine Months Ended
Three Months Ended September 30, September 30,
2009 2008 2009 2008
Volumes sold:
NaHS volumes (Dry short tons "DST") 28,207 38,319 75,344 126,716
NaOH volumes (DST) 26,898 18,404 63,561 51,066
Total 55,105 56,723 138,905 177,782
NaHS revenues $ 22,654 $ 43,926 $ 74,754 $ 121,738
NaOH revenues 6,455 13,439 33,534 38,892
Other revenues 2,256 6,127 8,905 7,194
Total external segment revenues $ 31,365 $ 63,492 $ 117,193 $ 167,824
Segment margin $ 12,694 $ 11,486 $ 38,643 $ 40,195
Average index price for NaOH per DST (1) $ 198 $ 845 $ 493 $ 616
Raw material and processing costs as %
of segment revenues 33 % 66 % 47 % 62 %
Delivery costs as a % of segment
revenues 14 % 13 % 11 % 14 %
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(1) Source: Harriman Chemsult Ltd.
Three Months Ended September 30, 2009 Compared with Three Months Ended September 30, 2008
Refinery services segment margin for the third quarter of 2009 was $12.7 million, an increase of $1.2 million, or 10.5%, from the comparative period in 2008. The significant components of this fluctuation were as follows:
· A decline in NaHS volumes of 26%. Macroeconomic conditions have negatively impacted the demand for NaHS, primarily in mining and industrial activities. As market prices and demand for copper and molybdenum improve, we would expect demand for NaHS to increase. Similarly, improvements in industrial activities including the paper and pulp and tanning industries would likely improve NaHS demand.
· An increase in NaOH sales volumes of 46%. NaOH (or caustic soda) is a key component in the provision of our services for which we receive the by-product NaHS. We are a very large consumer of caustic soda, and our economies of scale and logistics capabilities allow us to effectively market caustic soda to third parties.
· Volatile caustic soda prices. Average index prices for caustic soda increased throughout 2008 to a high of approximately $950 per DST in the fourth quarter of 2008. Since that time market prices of caustic soda have decreased to approximately $200 per DST. This volatility affects both the cost of caustic soda used to provide our services as well as the price at which we sell NaHS.
· Aggressive management of production costs. Raw material and processing costs related to providing our refinery services and supplying caustic soda as a percentage of our segment revenues declined 33% between the periods. The key component in the provision of our refinery services is caustic soda. In addition, as discussed above, we also market caustic soda. As the market price of caustic soda has fluctuated in 2008 and 2009, we have managed our acquisition costs through the timing of our purchases and our logistics costs related to our caustic soda purchases. We have also taken steps to reduce processing costs.
· Slightly higher delivery logistics costs. The costs of delivering NaHS and caustic soda to our customers increased slightly as a percentage of segment revenues by 1% between the two quarterly periods. We experienced this slight increase in logistics costs as a percentage of revenues primarily due to the change in revenues. Freight demand and fuel prices declined in the 2009 period as economic conditions reduced demand for transportation services and the decline in crude oil prices reduced the cost of fuel used in transporting these products. In 2009, we have also adjusted the modes of transportation being used to transport NaHS and caustic soda between rail, barge and truck to improve total logistics costs.
Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008
Segment margin for our refinery services decreased $1.6 million between the nine months ended September 30, 2009 and the same period in 2008. The reasons for this decline were similar to the quarterly comparison as follows:
· NaHS volumes declined 41%, as a result of macroeconomic conditions.
· Caustic soda sales volumes increased 24% partly offsetting the impact of the decline in NaHS activity.
· Revenues decreased 30% as average index prices for caustic soda in the nine months ended September 30, 2009 ranged from approximately $900 per DST in January to $200 per DST in September as compared to an increasing range of approximately $450 to $950 per DST in the 2008 period. As the majority of our NaHS sales prices fluctuate with the market price of caustic soda, variations in market prices affect our revenues. Raw material and processing costs as a percentage of segment revenues declined 15% between periods due to us managing the timing of our purchases and the influences of our ability to purchase in bulk at favorable prices.
· Delivery costs declined due to freight demand in the market and fuel prices.
Supply and Logistics Segment
Operating results from our supply and logistics segment were as follows:
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in thousands) (in thousands)
Supply and logistics revenue $ 356,450 $ 556,396 $ 836,876 $ 1,555,991
Crude oil and products costs, excluding
unrealized gains and losses from
derivative transactions (323,951 ) (521,779 ) (753,217 ) (1,471,254 )
Operating and segment general and
administrative costs, excluding non-cash
charges for stock-based compensation and
other non-cash expenses (23,076 ) (24,863 ) (61,680 ) (63,142 )
Segment margin $ 9,423 $ 9,754 $ 21,979 $ 21,595
Volumes of crude oil and petroleum
products -average barrels per day 51,260 47,342 47,280 47,694
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Three Months Ended September 30, 2009 as Compared to Three Months Ended September 30, 2008
The average market prices of crude oil and petroleum products declined by more than $50 per barrel, or approximately 45%, although our segment margin declined by only $0.3 million, or 3.4%, comparatively between the third quarters of 2009 and 2008. The price volatility had a limited impact on our segment margin.
The key factors affecting the two quarters were as follows:
· Segment margin generated by DG Marine's inland marine barge operations (increased segment margin by $1.7 million);
· Crude oil contango market conditions (increased segment margin by $0.9 million); and
· Reduction in opportunities to purchase and blend crude oil and products (reduced segment margin by $2.9 million).
The inland marine transportation operations of Grifco Transportation, acquired by DG Marine in mid-July of 2008, contributed $1.7 million more to segment margin in the third quarter of 2009 as compared to the third quarter of 2008. These operations provided us with an additional capability to provide transportation services of petroleum products by barge. As part of the acquisition, DG Marine acquired six tows (a tow consists of a push boat and two barges.) A total of four additional tows added during the fourth quarter of 2008 and first half of 2009 generated the segment margin increase despite declines in average charter rates for the tows over the same period.
During the third quarter of 2009, crude oil markets were in contango (oil prices for future deliveries are higher than for current deliveries), providing an opportunity for us to purchase and store crude oil as inventory for delivery in future months. The crude oil markets were not in contango in the third quarter of 2008 sufficiently to support the costs associated with storing inventory. During the third quarter of 2009, we held an average of approximately 220,000 barrels of crude oil in our storage tanks and hedged this volume with futures contracts on the NYMEX. We are accounting for the effects of this inventory position and related derivative contracts as a fair value hedge under accounting guidance. The effect on segment margin for the amount excluded from effectiveness testing related to this fair value hedge was a $0.9 million gain in the third quarter of 2009.
Offsetting these improvements in segment margin was a decrease in the margins from our crude oil gathering and petroleum products marketing operations. In 2009, we experienced some reductions in volumes as a result of crude oil producers' choices to reduce operating expenses or postpone development expenditures that could have maintained or enhanced their existing production levels. As a consequence of the reductions in volumes, our segment margin from crude oil gathering declined between the quarterly periods by $1.0 million. Volatile price changes in the petroleum products markets and robust refinery utilization in the third quarter of 2008 created blending and sales opportunities with expanded margins in comparison to historical rates. Relatively flat petroleum prices and reduced refinery utilization in the third quarter of 2009 narrowed the economics of our blending opportunities and reduced sales margins to more historical rates. Somewhat offsetting these margin declines were the additional opportunities to handle volumes from the heavy end of the refined barrel due to our access to additional leased heavy products storage capacity and to barge transportation capabilities through DG Marine. However, the net result of these factors was a reduction of our segment margin of $1.9 million from petroleum products and related activities.
Nine Months Ended September 30, 2009 as Compared to Nine Months Ended September 30, 2008
Segment margin for the nine month period in 2009 was affected by the same factors as in the third quarter, although the result was a slight increase in segment margin of $0.4 million. For the nine-month periods, the key factors described above had an impact as follows:
· Acquisition of inland marine transportation operations of Grifco in mid-July of 2008 (increased segment margin by $7.3 million);
· Reduction in opportunities to purchase and blend crude oil and petroleum products (reduced segment margin by $9.2 million); and
· Crude oil contango market conditions (increased segment margin by $2.3 million). . . .
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