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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0513049
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--- ---
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large accelerated filer Accelerated filer X Non-accelerated filer
--- --- ---
Indicate by check mark whether the registrant is a shell company (as defined by
Rule 12b-2 of the Exchange Act.)
Yes No X
--- ---
Indicate number of outstanding shares of each of the issuer's classes of common
stock, as of the latest practicable date. Limited Partner Units outstanding as
of August 4, 2006: 13,784,441
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This report contains 44 pages
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GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - June 30, 2006 and
December 31, 2005............................................ 4
Consolidated Statements of Operations for the Three and Six
Months Ended June 30, 2006 and 2005.......................... 5
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 2006 and 2005....................................... 6
Consolidated Statement of Partners' Capital for the Six Months
Ended June 30, 2006.......................................... 7
Notes to Consolidated Financial Statements...................... 8
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................ 23
Item 3. Quantitative and Qualitative Disclosures about Market Risk...... 42
Item 4. Controls and Procedures......................................... 42
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................... 43
Item 1A. Risk Factors.................................................... 43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds..... 43
Item 3. Defaults upon Senior Securities................................. 43
Item 4. Submission of Matters to a Vote of Security Holders............. 43
Item 5. Other Information............................................... 43
Item 6. Exhibits........................................................ 43
SIGNATURES............................................................... 44
-3-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
June 30, December 31,
2006 2005
-------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ....................................... $ 1,716 $ 3,099
Accounts receivable:
Trade ........................................................ 100,079 82,119
Related party ................................................ 966 515
Inventories ..................................................... 8,861 498
Net investment in direct financing leases, net of unearned
income - current portion ..................................... 549 531
Insurance receivable ............................................ 995 2,042
Other ........................................................... 1,496 1,645
-------- --------
Total current assets ......................................... 114,662 90,449
FIXED ASSETS, at cost .............................................. 69,962 69,708
Less: Accumulated depreciation .................................. (37,489) (35,939)
-------- --------
Net fixed assets ............................................. 32,473 33,769
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income .. 5,662 5,941
CO2 ASSETS, net of amortization .................................... 35,612 37,648
JOINT VENTURES AND OTHER INVESTMENTS ............................... 18,489 13,042
OTHER ASSETS, net of amortization .................................. 755 928
-------- --------
TOTAL ASSETS ....................................................... $207,653 $181,777
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable:
Trade ........................................................ $ 95,675 $ 82,369
Related party ................................................ 1,986 2,917
Accrued liabilities ............................................. 8,143 7,325
-------- --------
Total current liabilities .................................... 105,804 92,611
LONG-TERM DEBT ..................................................... 11,500 --
OTHER LONG-TERM LIABILITIES ........................................ 1,026 955
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS ................................................. 522 522
PARTNERS' CAPITAL
Common unitholders, 13,784 units issued and outstanding ......... 86,959 85,870
General partner ................................................. 1,842 1,819
-------- --------
Total partners' capital ...................................... 88,801 87,689
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL ............................ $207,653 $181,777
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Six Months
Ended June 30, Ended June 30,
------------------- -------------------
2006 2005 2006 2005
-------- -------- -------- --------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from buy/sell arrangements
of $69,772 in the six months of 2006 and $90,550 and $176,392
in the three and six months of 2005, respectively) ............... $220,633 $247,450 $472,894 $494,274
Related parties ..................................................... 195 242 379 426
Pipeline transportation, including natural gas sales:
Unrelated parties ................................................... 7,404 5,726 13,994 11,927
Related parties ..................................................... 1,217 1,158 2,397 2,269
CO2 revenues:
Unrelated parties ................................................... 3,239 2,568 6,626 4,848
Related party ....................................................... 655 -- 655 --
-------- -------- -------- --------
Total revenues ...................................................... 233,343 257,144 496,945 513,744
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from buy/sell
arrangements of $68,899 in the six months of 2006 and $90,254
and $176,399 in the three and six months of 2005, respectively) .. 214,737 241,535 460,649 483,346
Related parties ..................................................... 24 1,524 1,484 2,001
Field operating ..................................................... 3,720 4,183 7,065 8,015
Pipeline transportation costs:
Pipeline operating costs ............................................ 2,477 2,300 4,746 4,533
Natural gas purchases ............................................... 2,542 1,776 5,241 4,412
CO2 distribution costs:
Transportation costs - related party ................................ 1,153 773 2,174 1,490
Other costs ......................................................... 54 38 106 76
General and administrative ............................................. 3,249 2,468 5,909 3,326
Depreciation and amortization .......................................... 2,029 1,568 3,893 3,094
Net loss (gain) on disposal of surplus assets .......................... 1 (27) (49) (398)
-------- -------- -------- --------
OPERATING INCOME ....................................................... 3,357 1,006 5,727 3,849
OTHER INCOME (EXPENSE):
Equity in earnings of joint ventures ................................... 339 252 652 252
Interest income ........................................................ 30 22 108 28
Interest expense ....................................................... (293) (528) (493) (889)
-------- -------- -------- --------
Income from continuing operations before income taxes .................. 3,433 752 5,994 3,240
Income tax benefit ..................................................... 11 -- 11 --
-------- -------- -------- --------
INCOME FROM CONTINUING OPERATIONS ...................................... 3,444 752 6,005 3,240
(Loss) income from operations of discontinued Texas System ............. -- (9) -- 273
Cumulative effect adjustment of adoption of new accounting principle ... -- -- 30 --
-------- -------- -------- --------
NET INCOME ............................................................. $ 3,444 $ 743 $ 6,035 $ 3,513
======== ======== ======== ========
NET INCOME PER COMMON UNIT - BASIC AND DILUTED:
Income from continuing operations ................................... $ 0.24 $ 0.08 $ 0.43 $ 0.34
Income from discontinued operations ................................. -- -- -- 0.03
Cumulative effect adjustment ........................................ -- -- -- --
-------- -------- -------- --------
NET INCOME ............................................................. $ 0.24 $ 0.08 $ 0.43 $ 0.37
======== ======== ======== ========
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING .................... 13,784 9,314 13,784 9,314
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
-5-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six months
Ended June 30,
-------------------
2006 2005
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..................................................... $ 6,035 $ 3,513
Adjustments to reconcile net income to net cash (used in)
provided by operating activities -
Depreciation ................................................ 1,857 1,773
Amortization of CO2 contracts ............................... 2,036 1,321
Amortization of credit facility issuance costs .............. 186 187
Amortization of unearned income on direct financing leases .. (333) (349)
Payments received under direct financing leases ............. 594 593
Equity in earnings of joint ventures ........................ (652) (252)
Distributions from joint ventures - return on investment .... 677 --
Gain on asset disposals ..................................... (49) (671)
Cumulative effect adjustment for new accounting principle ... (30) --
Other non-cash charges (credits) ............................ 110 (942)
Changes in components of working capital -
Accounts receivable ...................................... (18,411) (20,910)
Inventories .............................................. (8,363) (3,163)
Other current assets ..................................... 1,196 267
Accounts payable ......................................... 12,856 15,395
Accrued liabilities ...................................... 747 2,383
-------- --------
Net cash used in operating activities ............................. (1,544) (855)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment ............................ (480) (4,394)
Investment in T&P Syngas Supply Company ........................ -- (13,505)
Distributions from joint ventures - return of investment ....... 153 --
Investment in Sandhill Group, LLC .............................. (5,037) --
Investments, other ............................................. (513) --
Proceeds from sale of assets ................................... 67 1,360
Other, net ..................................................... (26) (53)
-------- --------
Net cash used in investing activities ............................. (5,836) (16,592)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings of debt, net ................................... 11,500 19,100
Other, net ..................................................... (580) 748
Distributions to common unitholders ............................ (4,825) (2,794)
Distributions to General Partner ............................... (98) (57)
-------- --------
Net cash provided by financing activities ......................... 5,997 16,997
-------- --------
Net decrease in cash and cash equivalents ......................... (1,383) (450)
Cash and cash equivalents at beginning of year .................... 3,099 2,078
-------- --------
Cash and cash equivalents at end of period ........................ $ 1,716 $ 1,628
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
-6-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
-------------------------------------------
Number of
Common Common General
Units Unitholders Partner Total
--------- ----------- ------- -------
Partners' capital at January 1, 2006 ............... 13,784 $85,870 $1,819 $87,689
Net income for the six months ended June 30, 2006 .. -- 5,914 121 6,035
Distributions to partners during the six months
ended June 30, 2006 ............................. -- (4,825) (98) (4,923)
------ ------- ------ -------
Partners' capital at June 30, 2006 ................. 13,784 $86,959 $1,842 $88,801
====== ======= ====== =======
The accompanying notes are an integral part of these consolidated financial
statements.
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
We are a midstream partnership that was formed in 1996 as a master limited
partnership, or MLP. We have a diverse portfolio of customers and assets,
including pipeline transportation of primarily crude oil and, to a lesser
extent, natural gas and carbon dioxide (CO(2)) in the Gulf Coast region of the
United States. In conjunction with our crude oil pipeline transportation
operations, we operate a crude oil gathering and marketing business, which helps
ensure a base supply of crude oil for our pipelines. We participate in
industrial gas activities, including a CO(2) supply business, which is
associated with the CO(2) tertiary oil recovery process being used in
Mississippi by an affiliate of our general partner. During 2005, we also
acquired a 50% interest in a joint venture that processes natural gas to produce
syngas and high-pressure steam. During 2006, we acquired a 50% interest in a
joint venture that processes CO(2) for use in the food, beverage, chemical and
oil industries. Our operations are conducted through our operating subsidiary,
Genesis Crude Oil, L.P., and its subsidiary partnerships.
Our 2% general partner interest is held by Genesis Energy, Inc., a Delaware
corporation and indirect wholly-owned subsidiary of Denbury Resources Inc.
Denbury and its subsidiaries are hereafter referred to as Denbury. Our general
partner also owns a 7.25% interest in us through limited partner interests.
Our general partner manages our operations and activities and employs our
officers and personnel, who devote 100% of their efforts to our management.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our
consolidated financial position as of June 30, 2006 and December 31, 2005 and
our results of operations for the three and six months ended June 30, 2006 and
2005, our cash flows for the six months ended June 30, 2006 and 2005, and our
changes in partners' capital for the six months ended June 30, 2006. All
significant intercompany transactions have been eliminated. The accompanying
consolidated financial statements include Genesis Energy, L.P., its operating
subsidiary and its subsidiary partnerships. Our general partner owns a 0.01%
general partner interest in Genesis Crude Oil, L.P., which is reflected in our
financial statements as a minority interest.
In 2005, we acquired a 50% interest in T&P Syngas Supply Company. In 2006,
we acquired a 50% interest in Sandhill Group, LLC. We account for these
investments using the equity method, as we exercise significant influence over
their operating and financial policies. See Note 3.
No provision for federal or state income taxes related to our operations is
included in the accompanying consolidated financial statements; as such income
will be taxable directly to the partners holding partnership interests. The
State of Texas enacted a margin tax in May 2006 that we will be required to pay
beginning in 2008. The method of calculation for this margin tax is similar to
an income tax, requiring us to recognize currently the impact of this new tax on
the future tax effects of temporary differences between the financial statement
carrying amounts and the tax basis of existing assets and liabilities. See Note
13.
The 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) which 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. These
financial statements should be read in conjunction with the financial statements
and notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2005 filed with the SEC.
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. NEW ACCOUNTING PRONOUNCEMENTS
Adoption of SFAS 123(R) on January 1, 2006
On January 1, 2006, we adopted the provisions of SFAS No. 123(R). In
December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payments". The adoption of this statement requires that the
compensation cost associated with our stock appreciation rights plan, which upon
exercise will result in the payment of cash to the employee, be re-measured each
reporting period based on the fair value of the rights. Before the adoption of
SFAS 123(R), we accounted for the stock appreciation rights in accordance with
FASB Interpretation No. 28, "Accounting for Stock Appreciation Rights and Other
Variable Stock Option or Award Plans" which required that the liability under
the plan be measured at each balance sheet date based on the market price of our
common units on that date. Under SFAS 123(R), the liability is calculated using
a fair value method that takes into consideration the expected future value of
the rights at their expected exercise dates. See Note 12.
EITF 04-13
We enter into buy/sell transactions that are contractual arrangements
that establish the terms of the purchase of a particular grade of crude oil at a
specified location and the sale of a particular grade of crude oil at a
different location at the same or at another specified date. These arrangements
are detailed jointly, in a single contract, or separately, in individual
contracts that are entered into concurrently or in contemplation of one another
with a single counterparty. Both transactions require physical delivery of the
crude oil and the risk and reward of ownership are evidenced by title transfer,
assumption of environmental risk, transportation scheduling, credit risk and
counterparty nonperformance risk. In accordance with the provision of Emerging
Issues Task Force Issue No. 04-13, "Accounting for Purchases and Sales of
Inventory with the Same Counterparty," we have reflected the amounts of revenues
and purchases for these transactions as a net amount in our consolidated
statements of operations beginning with April 2006. Transactions for periods
prior to April 2006 are not reflected as a net amount, however the amounts are
disclosed parenthetically on the consolidated statements of operations. This
change had no effect on operating income, net income or cash flows, however it
did reduce both crude oil gathering and marketing revenues and crude oil costs
by $66.3 million for the three and six months ended June 30, 2006.
SFAS 154
In May 2005, the FASB issued Statement of Financial Standards No. 154,
"Accounting Changes and Error Corrections" (SFAS 154). This statement
established new standards on the accounting for and reporting of changes in
accounting principles and error corrections. SFAS 154 requires retrospective
application to the financial statements of prior periods for all such changes,
unless it is impracticable to do so. SFAS 154 was effective for us in the first
quarter of 2006.
3. JOINT VENTURES AND OTHER INVESTMENTS
T&P Syngas Supply Company
On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply
Company, a Delaware general partnership, for $13.4 million in cash from a
subsidiary of ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. owns the
remaining 50% partnership interest in T&P Syngas. We paid for our interest in
T&P Syngas with proceeds from our credit facilities.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. That facility processes natural gas to produce
syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.
Praxair provides the raw materials to be processed and receives the syngas and
steam produced by the facility under a long-term processing agreement. T&P
Syngas receives a processing fee for its services. Praxair operates the
facility.
We are accounting for our 50% ownership in T&P Syngas under the equity
method of accounting. We reflect in our consolidated statements of operations
our equity in T&P Syngas' net income, net of the amortization of the excess of
our investment over our share of partners' capital of T&P Syngas. We paid $4.0
million more for our interest in T&P Syngas than our share of partners' capital
on the balance sheet of T&P Syngas at the date of the
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
acquisition. This excess amount of the purchase price over the equity in T&P
Syngas is being amortized using the straight-line method over the remaining
useful life of the assets of T&P Syngas of eleven years. Our consolidated
statements of operations for the three and six months ended June 30, 2006
included $410,000 and $811,000, respectively, as our share of the operating
earnings of T&P Syngas, reduced by amortization of the excess purchase price of
$88,000 and $176,000, respectively.
The table below reflects summarized financial information for T&P
Syngas at June 30, 2006.
Six Months Ended
June 30, 2006
----------------
(in thousands)
Revenues .............................. $2,510
Operating expenses and depreciation ... (896)
Other income .......................... 7
------
Net income ............................ $1,621
======
June 30, 2006
--------------
(in thousands)
Current assets ............................ $ 1,382
Non-current assets ........................ 16,206
--------
Total assets .............................. $ 17,588
========
Current liabilities ....................... $ 329
Partners' capital ......................... 17,259
--------
Total liabilities and partners' capital ... $ 17,588
========
Sandhill Group, LLC
On April 1, 2006, we acquired a 50% interest in Sandhill Group, LLC,
for $5 million in cash, from Magna Carta Group, LLC. Magna Carta holds the other
50% interest in Sandhill. Sandhill is a limited liability company that owns a
CO(2) processing facility located in Brandon, Mississippi. Sandhill is engaged
in the production and distribution of liquid carbon dioxide for use in the food,
beverage, chemical and oil industries. The facility acquires CO(2) from us under
a long-term supply contract that we acquired in 2005 from Denbury.
We paid for our interest in Sandhill with cash on hand. The terms of
the acquisition include earnout provisions such that we could pay up to an
additional $2 million to Magna Carta for our interest in Sandhill, based on the
distributable cash generated by Sandhill during the period 2006 through no later
than 2012. Should the cumulative distributable cash of Sandhill in the period
beginning with 2006 average at least $1.5 million per year, and distributions to
the members average at least $1.2 million per year, we will owe Magna Carta $1.0
million at the end of the year when the target is exceeded. If the distributable
cash averages $2.0 million per year and distributions average $1.6 million per
year in the period beginning with 2006, we will owe Magna Carta an additional
$1.0 million.
During 2003, Sandhill was authorized to issue a series of "Issuer
Floating Rate Option Notes" in an amount not to exceed $15,000,000. In 2003,
Sandhill issued notes in the amount of $5,900,000 which are backed by a letter
of credit from a bank and have a maturity date of December 1, 2013. At June 30,
2006, the outstanding balance of these notes was $4.7 million. We provide a
guarantee of 50% of the letter of credit to Sandhill's bank; therefore, our
guaranty represents $2.35 million. Sandhill makes principal payments totaling
$0.6 million annually. We have recorded the estimated fair value of this
guarantee of $0.1 million as a long-term liability in our consolidated balance
sheet, with a corresponding increase to our investment in Sandhill.
We are accounting for our 50% ownership in Sandhill under the equity
method of accounting as both partners have substantive participating rights. We
reflect in our consolidated statements of operations our equity in Sandhill's
net income, net of the amortization of the excess of our investment over our
share of partners' capital of Sandhill that is not considered goodwill. We paid
$3.8 million more for our interest in Sandhill than our share of partners'
capital on the balance sheet of Sandhill at the date of the acquisition. This
excess amount of the purchase
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
price over the equity in Sandhill has been allocated to the property and
equipment of Sandhill and certain intangible assets based on the fair value of
those assets, with the remainder of the excess purchase price of $0.5 million
allocated to goodwill. The amount allocated to property and equipment and
intangible assets is being amortized using the straight-line method over the
remaining useful lives of those assets. Our consolidated statements of
operations for the three and six months ended June 30, 2006 included $90,000, as
our share of the operating earnings of Sandhill, reduced by amortization of the
excess purchase price of $73,000.
The table below reflects summarized financial information for Sandhill
at June 30, 2006, for the period since we acquired our interest in Sandhill.
Three Months Ended
June 30, 2006
------------------
(in thousands)
Revenues.............................. $ 2,693
Operating expenses and depreciation... (2,513)
Other income.......................... 1
-------
Net income............................ $ 181
=======
June 30, 2006
--------------
(in thousands)
Current assets........................... $1,923
Non-current assets....................... 6,869
------
Total assets............................. $8,792
======
Current liabilities...................... $1,731
Non-current liabilities.................. 4,355
Members' capital......................... 2,706
------
Total liabilities and members' capital... $8,792
======
Other Projects
As is typical with most businesses in our sector, we are continuously
searching for and evaluating potential investment opportunities, which involves
committing personnel, money and other resources. In connection with those
activities, we capitalized $0.5 million during the second quarter and we expect
to capitalize another $0.5 million during calendar 2006. If we proceed with the
projects associated with those expenditures, we will transfer the costs to those
projects to which the costs are attributable. If we do not proceed with those
projects, we expect to recover at least our initial investment, although that
will depend on the facts and circumstances relating to each investment.
4. DEBT
We have a $100 million credit facility comprised of a $50 million revolving
line of credit for acquisitions and a $50 million working capital revolving
facility. The working capital portion of the credit facility has a $15 million
sublimit for loans with the remainder of the $50 million available for letters
of credit. In total we may have up to $65 million in loans under our credit
facility. At June 30, 2006, we had $11.5 million in loans and $11.8 million in
letters of credit (primarily for crude oil purchases in June and July 2006)
outstanding under the working capital portion and no balance outstanding under
the acquisition portion of our credit facility. At June 30, 2006, the weighted
average interest rate on the debt was 8.5%. 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 1, 2008.
The aggregate amount that we may have outstanding at any time under the
working capital portion of our credit facility is subject to a borrowing base
calculation. The borrowing base is limited to $50 million and is calculated
monthly. At June 30, 2006, the borrowing base was $50 million. The remaining
amount available for borrowings
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
at June 30, 2006 was $3.5 million under the working capital portion and $50.0
million under the acquisition portion of the credit facility.
Certain restrictive covenants in the credit facility limit our ability to
make distributions to our unitholders and the general partner. The credit
facility requires we maintain a cash flow coverage ratio of 1.1 to 1.0. In
general, this calculation compares operating cash inflows (as adjusted in
accordance with the credit facility), less maintenance capital expenditures, to
the sum of interest expense and distributions. At June 30, 2006, the calculation
resulted in a ratio of 1.5 to 1.0. The credit facility also requires that the
level of operating cash inflows during the prior twelve months, as adjusted in
accordance with the credit facility, be at least $8.5 million. At June 30, 2006,
the result of this calculation was $17.8 million. Our credit facility also
requires that we meet certain other financial ratios, such as a current ratio,
leverage ratio and funded indebtedness to capitalization ratio. If we meet these
covenants, we are otherwise not limited in making distributions.
5. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Partners' capital at June 30, 2006 and December 31, 2005 consists of
13,784,441 common units, including 1,019,441 units owned by our general partner,
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, all of
the 0.01% general partner interest in our operating partnership (which is
reflected as a minority interest in the consolidated balance sheet) and operates
our business.
Our partnership agreement authorizes our general partner to cause us
to issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other needs.
Distributions
Generally, 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. We paid distributions as follows in 2005 and 2006:
Date Per Unit Total
Distribution For Paid or to be Paid Amount Amount (000's)
- ------------------- ------------------ -------- --------------
Fourth quarter 2004 February 2005 $0.15 $1,426
First quarter 2005 May 2005 $0.15 $1,426
Second quarter 2005 August 2005 $0.15 $1,426
Third quarter 2005 November 2005 $0.16 $1,521
Fourth quarter 2005 February 2006 $0.17 $2,391
First quarter 2006 May 2006 $0.18 $2,532
Second quarter 2006 August 2006 $0.19 $2,672
The total amounts in the table above increased with the distribution
for the fourth quarter of 2005 due to the issuance of 4,470,630 new common units
in December 2005.
Our general partner is entitled to receive incentive distributions if
the amount we distribute with respect to any quarter exceeds levels specified in
our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through June
30, 2006.
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income per
common unit (in thousands, except per unit amounts).
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
------- ------ ------- ------
(in thousands, except per unit amounts)
Numerators for basic and diluted net income per
common unit:
Income from continuing operations .............. $ 3,444 $ 752 $ 6,005 $3,240
Less general partner 2% ownership .............. 69 15 120 65
------- ------ ------- ------
Income from continuing operations available for
common unitholders .......................... $ 3,375 $ 737 $ 5,885 $3,175
======= ====== ======= ======
Income (loss) from discontinued operations ..... $ -- $ (9) $ -- $ 273
Less general partner 2% ownership .............. -- -- -- 5
------- ------ ------- ------
Income (loss) from discontinued operations
available for common unitholders ............ $ -- $ (9) $ -- $ 268
======= ====== ======= ======
Income from cumulative effect adjustment ....... $ -- -- 30 --
Less general partner 2% ownership .............. -- -- 1 --
------- ------ ------- ------
Income from cumulative effect adjustment
available for common unitholders ............ $ -- $ -- $ 29 $ --
======= ====== ======= ======
Denominator for basic and diluted per Common Unit -
weighted average number of Common Units
outstanding .................................... 13,784 9,314 13,784 9,314
======= ====== ======= ======
Basic and diluted net income per Common Unit:
Income from continuing operations .............. $ 0.24 $ 0.08 $ 0.43 $ 0.34
Income from discontinued operations ............ -- -- -- 0.03
Income from cumulative effect adjustment ....... -- -- -- --
------- ------ ------- ------
Net income ..................................... $ 0.24 $ 0.08 $ 0.43 $ 0.37
======= ====== ======= ======
6. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Pipeline
Transportation - interstate and intrastate crude oil, natural gas and CO(2)
pipeline transportation; (2) Industrial Gases - the sale of CO(2) acquired under
volumetric production payments to industrial customers and our investments in
joint ventures with a syngas processing facility and a CO(2) processing
facility, and (3) Crude Oil Gathering and Marketing - the purchase and sale of
crude oil at various points along the distribution chain. In prior periods, our
Industrial Gases segment was called CO(2) Marketing. The tables below reflect
all periods presented as though the current segment designations had existed,
and include only continuing operations data.
We evaluate segment performance based on segment margin. We calculate
segment margin as revenues less costs of sales and operations expenses, and we
include income from investments in joint ventures. We do not deduct depreciation
and amortization. All of our revenues are derived from, and all of our assets
are located in the United States. The pipeline transportation segment
information includes the revenue, segment margin and assets of the direct
financing leases.
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
Pipeline Industrial Gathering and
Transportation Gases (a) Marketing Total
-------------- ---------- ------------- --------
(in thousands)
Three Months Ended June 30, 2006
Segment margin excluding depreciation
and amortization (b) ................... $ 3,602 $ 3,026 $ 2,347 $ 8,975
Capital expenditures ...................... $ 257 $ 5,550 $ 35 $ 5,842
Maintenance capital expenditures .......... $ 126 $ -- $ 35 $ 161
Revenues:
External Customers ........................ $ 6,828 $ 3,894 $220,828 $231,550
Intersegment (d) .......................... 1,793 -- -- 1,793
------- ------- -------- --------
Total revenues of reportable segments ..... $ 8,621 $ 3,894 $220,828 $233,343
======= ======= ======== ========
Three Months Ended June 30, 2005
Segment margin excluding depreciation
and amortization (b) ................... $ 2,808 $ 2,009 $ 450 $ 5,267
Capital expenditures ...................... $ 926 $13,418 $ 254 $ 14,598
Maintenance capital expenditures .......... $ 175 $ -- $ 25 $ 200
Revenues:
External Customers ........................ $ 5,957 $ 2,568 $247,692 $256,217
Intersegment (d) .......................... 927 -- -- 927
------- ------- -------- --------
Total revenues of reportable segments ..... $ 6,884 $ 2,568 $247,692 $257,144
======= ======= ======== ========
Six months Ended June 30, 2006
Segment margin excluding depreciation
and amortization (b) ................... $ 6,404 $ 5,653 $ 4,075 $ 16,132
Capital expenditures ...................... $ 423 $ 5,550 $ 156 $ 6,129
Maintenance capital expenditures .......... $ 224 $ -- $ 156 $ 380
Net fixed and other long-term assets (c) .. $33,251 $54,101 $ 5,639 $ 92,991
Revenues:
External Customers ........................ $13,926 $ 7,281 $473,273 $494,480
Intersegment (d) .......................... 2,465 -- -- 2,465
------- ------- -------- --------
Total revenues of reportable segments ..... $16,391 $ 7,281 $473,273 $496,945
======= ======= ======== ========
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Six months Ended June 30, 2005
Segment margin excluding
depreciation and amortization (b) ...... $ 5,251 $ 3,534 $ 1,338 $ 10,123
Capital expenditures ...................... $ 4,602 $13,418 $ 276 $ 18,296
Maintenance capital expenditures .......... $ 664 $ -- $ 47 $ 711
Net fixed and other long-term
assets (c) ............................. $35,651 $38,780 $ 6,438 $ 80,869
Revenues:
External Customers ........................ $12,590 $ 4,848 $494,700 $512,138
Intersegment (d) .......................... 1,606 -- -- 1,606
------- ------- -------- --------
Total revenues of reportable
segments ............................... $14,196 $ 4,848 $494,700 $513,744
======= ======= ======== ========
a) Industrial gases segment margin includes our CO(2) marketing operations and
the income from our investments in T&P Syngas Supply Company and Sandhill
Group, LLC.
b) Segment margin was calculated as revenues less cost of sales and operations
expense. It includes our share of the operating income of equity joint
ventures. A reconciliation of segment margin to income from continuing
operations for the periods presented is as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -----------------
2006 2005 2006 2005
------- ------- ------- -------
(in thousands)
Segment margin excluding depreciation and
amortization ................................. $ 8,975 $ 5,267 $16,132 $10,123
General and administrative expenses ............. (3,249) (2,468) (5,909) (3,326)
Depreciation, amortization and impairment ....... (2,029) (1,568) (3,893) (3,094)
Net (loss) gain on disposal of surplus assets ... (1) 27 49 398
Interest expense, net ........................... (263) (506) (385) (861)
Income tax credit ............................... 11 -- 11 --
------- ------- ------- -------
Income from continuing operations ............... $ 3,444 $ 752 $ 6,005 $ 3,240
======= ======= ======= =======
c) Net fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment basis. Current assets
are not allocated to segments as the amounts are shared by the segments or
are not meaningful in evaluating the success of the segment's operations.
d) Intersegment sales were conducted on an arm's length basis.
7. 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.
Transactions with Denbury, our General Partner and Sandhill
Six months Ended
June 30,
----------------
2006 2005
------ ------
(in thousands)
Crude oil purchases from Denbury ............................... $1,484 $2,001
Crude oil sales to Denbury ..................................... $ -- $ 22
Truck transportation services provided to Denbury .............. $ 379 $ 404
Pipeline transportation services provided to Denbury ........... $2,034 $1,904
Payments received under direct financing leases from Denbury ... $ 594 $ 593
Pipeline transportation income portion of direct financing
lease fees .................................................. $ 333 $ 365
Pipeline monitoring services provided to Denbury ............... $ 30 $ 15
Directors' fees paid to Denbury ................................ $ 60 $ 60
CO(2) transportation services provided by Denbury .............. $2,174 $1,490
Operations, general and administrative services provided by
our general partner ......................................... $8,541 $7,682
Distributions to our general partner on its limited partner
units and general partner interest .......................... $ 455 $ 264
Sales of CO(2) to Sandhill (for the period since Sandhill
became a related party - See Note 3 ......................... $ 655 $ --
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transportation Services
We provide truck transportation services to Denbury to move their
crude oil from the wellhead to our Mississippi pipeline. Denbury pays us a fee
for this trucking service that varies with the distance the crude oil is
trucked. These fees are reflected in the statement of operations as gathering
and marketing revenues.
Denbury is a shipper on our Mississippi pipeline. We also earned fees
from Denbury under the direct financing lease arrangements for the Olive and
Brookhaven crude oil pipelines and the Brookhaven CO(2) pipeline and recorded
pipeline transportation income from these arrangements.
We also provide pipeline monitoring services to Denbury. This revenue
is included in pipeline revenues in the statement of operations.
Directors' Fees
We pay Denbury for the services of four Denbury officers who serve as
directors of our general partner at the same rate at which our independent
directors are paid.
CO(2) Operations and Transportation
We acquired contracts, along with volumetric production payments, from
Denbury in 2005 and prior years. Denbury charges us a transportation fee of
$0.16 per Mcf (adjusted for inflation) to deliver the CO(2) for us to our
customers.
Operations, General and Administrative Services
We do not directly employ any persons to manage or operate our
business. Those functions are provided by our general partner. We reimburse the
general partner for all direct and indirect costs of these services.
Amounts due to and from Related Parties
At June 30, 2006 and December 31, 2005, we owed Denbury $0.8 million
and $1.9 million, respectively, for purchases of crude oil and CO(2)
transportation charges. Denbury owed us $0.5 million and $0.5 million for
transportation services at June 30, 2006 and December 31, 2005, respectively. We
owed our general partner $1.2 million and $1.1 million at June 30, 2006 and
December 31, 2005, respectively, for administrative services.
At June 30, 2006, Sandhill owed us $0.5 million for purchases of
CO(2).
Financing
Our general partner, a wholly owned subsidiary of Denbury, guarantees
our obligations under our credit facility. Our general partner's principal
assets are its general and limited partnership interests in us. Those
obligations are not guaranteed by Denbury or any of its other subsidiaries.
We guarantee 50% of the obligation of Sandhill to a bank. At June 30,
2006, the total amount of Sandhill's obligation to the bank was $4.7 million;
therefore, our guarantee was for $2.35 million. See Note 3.
8. MAJOR CUSTOMERS AND CREDIT RISK
Due to the nature of our crude oil operations, a disproportionate
percentage of our trade receivables constitute obligations of oil companies.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic,
-16-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
industry or other conditions. However, we believe that the credit risk posed by
this industry concentration is offset by the creditworthiness of our customer
base. Our portfolio of accounts receivable is comprised in large part of
integrated and large independent energy companies with stable payment
experience. The credit risk related to contracts which are traded on the NYMEX
is limited due to the daily cash settlement procedures and other NYMEX
requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Occidental Energy Marketing, Inc., Shell Oil Company and Calumet Specialty
Products Partners, L.P. accounted for 21%, 17% and 11% of total revenues in the
first half of 2006, respectively. Occidental Energy Marketing, Inc., Shell Oil
Company and Plains All American, L.P. accounted for 27%, 12% and 11% of total
revenues for the first half of 2005, respectively. The majority of the revenues
from these three customers in both periods relate to our gathering and marketing
operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
We received interest payments of $124,000 and $28,000 for the six months
ended June 30, 2006 and 2005, respectively. Payments of interest and commitment
fees were $218,000 and $596,000 for the six months ended June 30, 2006 and 2005,
respectively.
At June 30, 2006, we had incurred liabilities for fixed asset additions
totaling $0.1 million that had not been paid at the end of the quarter, and,
therefore, are not included in the caption "Additions to property and equipment"
on the Consolidated Statements of Cash Flows.
10. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration, although we have the flexibility to enter into
arrangements with a longer term.
We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.
We mark to fair value our derivative instruments at each period end, with
changes in the fair value of derivatives that are not designated as hedges being
recorded as unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. The effective portion of
unrealized gains or losses on derivative transactions qualifying as cash flow
hedges are reflected in other comprehensive income. Derivative transactions
qualifying as fair value hedges are evaluated for hedge effectiveness and the
resulting hedge ineffectiveness is recorded as a gain or loss in the
consolidated statements of operations.
We review our contracts to determine if the contracts meet the definition
of derivatives pursuant to SFAS 133. At June 30, 2006, we had futures contracts
that were considered free-standing derivatives that are accounted for at fair
value. The fair value of these contracts was determined based on the closing
price for such contracts on June 30, 2006. We marked these contracts to fair
value at June 30, 2006. During the six months ended June 30, 2006, we recorded
losses of $177,000 related to derivative transactions, which is included in the
consolidated statements of operations under the caption "Crude Oil Costs".
-17-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At June 30, 2006, we had futures contracts that qualified as derivatives
and were formally documented and designated as fair value hedges of inventory.
During the six months ended June 30, 2006, we recognized gains, due to hedge
ineffectiveness, on the fair value hedge of inventory of approximately $57,000.
These gains are included in the caption "Crude Oil Costs" in the consolidated
statements of operations. The time value component of the derivative gain or
loss excluded from the assessment of hedge effectiveness was not material.
The consolidated balance sheet at June 30, 2006 includes a reduction in
other current assets of $351,000 as a result of these derivative transactions.
The consolidated balance sheet at December 31, 2005 included an increase in
other current assets of $6,000 as a result of derivative transactions.
At June 30, 2005, we had futures contracts on the NYMEX that were
considered free-standing derivatives that are accounted for at fair value. The
fair value of these contracts was determined based on the closing price for such
contracts on the NYMEX on June 30, 2005. We marked these contracts to fair value
at June 30, 2005. During the three months and six months ended June 30, 2005, we
recorded gains of $84,000 and $8,000, respectively, related to derivative
transactions, which are included in the consolidated statements of operations
under the caption "Crude Oil Costs".
At June 30, 2005, we had futures contracts on the NYMEX that qualified as
derivatives and were formally documented and designated as fair value hedges of
inventory. During the three and six months ended June 30, 2005, we recognized a
loss, due to hedge ineffectiveness, on the fair value hedge of inventory
totaling $9,000. This loss is included in the caption "Crude Oil Costs" in the
consolidated statements of operations. The time value component of the
derivative gain or loss excluded from the assessment of hedge effectiveness was
not material.
We determined that the remainder of our derivative contracts qualified for
the normal purchase and sale exemption and were designated and documented as
such at June 30, 2006 and December 31, 2005.
11. CONTINGENCIES
Guarantees
We guaranteed $1.4 million of residual value related to the leases of
tractors and trailers from Ryder. We believe the likelihood we would be required
to perform or otherwise incur any significant losses associated with this
guaranty is remote.
Along with our general partner, we have guaranteed the payments by our
operating partnership to the banks under the terms of our credit facility
related to borrowings and letters of credit. To the extent liabilities exist
under the letters of credit, such liabilities are included in the consolidated
balance sheet. Borrowings at June 30, 2006 were $11.5 million and are reflected
in the consolidated balance sheet.
We guaranty 50% of the obligations of Sandhill under a credit facility
with a bank. At June 30, 2006, Sandhill owed $4.7 million; therefore our
guarantee was $2.35 million. Sandhill makes principal payments for this
obligation totaling $0.6 million per year.
In general, we expect to incur expenditures in the future to comply
with increasing levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we
anticipate that we will expend a total of approximately $0.7 million in 2006 and
2007 for testing, repairs and improvements under regulations requiring
assessment of the integrity of crude oil pipelines. After 2007 we expect that
our annual expenditures for integrity testing, repairs and improvements to
average from $1.0 million to $1.5 million.
Pennzoil Litigation
We were named a defendant in a complaint filed on January 11, 2001, in
the 125th District Court of Harris County, Texas, Cause No. 2001-01176.
Pennzoil-Quaker State Company (PQS) was seeking from us property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion
-18-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
were caused, in part, by crude oil we sold to PQS that was contaminated with
organic chlorides. In December 2003, our insurance carriers settled this
litigation for $12.8 million.
PQS is also a defendant in five consolidated class action/mass tort
actions brought by neighbors living in the vicinity of the PQS Shreveport,
Louisiana refinery in the First Judicial District Court, Caddo Parish,
Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C.
PQS has brought third party claims against us and others for indemnity with
respect to the fire and explosion of January 18, 2000. We believe that the
demand against us is without merit and intend to vigorously defend ourselves in
this matter. We currently believe that this matter will not have a material
financial effect on our financial position, results of operations, or cash
flows.
Environmental
In 1992, Howell Crude Oil Company entered into a sublease with Koch
Industries, Inc., covering a one acre tract of land located in Santa Rosa
County, Florida to operate a crude oil trucking station, known as Jay Station.
The sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated the
Jay Station from 1992 until December of 1996 when this operation was sold to us
by Howell. We operated the Jay Station as a crude oil trucking station until
2003. Koch has indicated that it has incurred certain investigative and/or other
costs, for which Koch alleges some or all should be reimbursed by us, under the
indemnification provisions of the sublease for environmental contamination on
the site and surrounding areas. Koch has also alleged that we are responsible
for future environmental obligations relating to the Jay Station.
Howell was acquired by Anadarko Petroleum Corporation in 2002. In
2005, we entered into a joint defense and cost allocation agreement with
Anadarko. Under the terms of the joint allocation agreement, we agreed to
reasonably cooperate with each other to address any liabilities or defense costs
with respect to the Jay Station. Additionally under the joint allocation
agreement, Anadarko will be responsible for sixty percent of the costs related
to any liabilities or defense costs incurred with respect to contamination at
the Jay Station.
We were formed in 1996 by the sale and contribution of assets from
Howell and Basis Petroleum, Inc. Anadarko's liability with respect to the Jay
Station is derived largely from contractual obligations entered into upon our
formation. We believe that Basis has contractual obligations under the same
formation agreements. We intend to seek recovery of Basis' share of potential
liabilities and defense costs with respect to Jay Station.
We have contacted the appropriate state regulatory agencies regarding
developing a plan of remediation for certain affected soils and affected
groundwater at the Jay Station. We have accrued an estimate of our share of
liability for this matter in the amount of $0.5 million. The time period over
which our liability would be paid is uncertain and could be several years. This
liability may decrease if indemnification and/or cost reimbursement is obtained
by us for Basis' potential liabilities with respect to this matter. At this
time, our estimate of potential obligations does not assume any specific amount
contributed on behalf of the Basis obligations, although we believe that Basis
is responsible for a significant part of these potential obligations.
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.
Other Matters
We have taken additional security measures since the terrorist attacks
of September 11, 2001 in accordance with guidance provided by the Department of
Transportation and other government agencies. We cannot assure you that these
security measures would prevent our facilities from a concentrated attack. Any
future attacks on us or our customers or competitors could have a material
effect on our business, whether insured or not. We believe we are adequately
insured for public liability and property damage to others and that our coverage
is similar to other companies with operations similar to ours. No assurance can
be made that we will be able to maintain adequate insurance in the future at
premium rates that we consider reasonable.
-19-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As discussed in Note 3, we have committed to invest an additional $0.5
million in a potential investment project.
We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. We do not expect such
matters presently pending to have a material adverse effect on our financial
position, results of operations or cash flows.
12. STOCK APPRECIATION RIGHTS PLAN
Under the terms of our stock appreciation rights plan, all regular,
full-time active employees and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation Committee
of the Board, who shall determine, in its full discretion, the number of rights
to award, the grant date of the units and the formula for allocating rights to
the participants and the strike price of the rights awarded. Each right is
equivalent to one common unit.
The rights have a term of 10 years from the date of grant. The initial
award to a participant will vest one-fourth each year beginning with the first
anniversary of the grant date of the award. Subsequent awards to participants
will vest on the fourth anniversary of the grant date. If the right has not been
exercised at the end of the ten year term and the participant has not terminated
his employment with us, the right will be deemed exercised as of the date of the
right's expiration and a cash payment will be made as described below.
Upon vesting, the participant may exercise his rights and receive a
cash payment calculated as the difference between the average of the closing
market price of our common units for the ten days preceding the date of exercise
over the strike price of the right being exercised. The cash payment to the
participant will be net of any applicable withholding taxes required by law. If
the Committee determines, in its full discretion, that it would cause
significant financial harm to the Partnership to make cash payments to
participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal
retirement (as these terms are defined in the plan) will result in the
forfeiture of any non-vested rights. Upon death, disability or normal
retirement, all rights will become fully vested. If a participant is terminated
for any reason within one year after the effective date of a change in control
(as defined in the plan) all rights will become fully vested.
Prior to January 1, 2006, we had accounted for this plan under the
provisions of FASB Interpretation No. 28, "Accounting for Stock Appreciation
Rights and Other Variable Stock Option or Award Plans", which required that the
liability under the plan be measured at each balance sheet date based on the
market price of our common units on that date. On January 1, 2006, we adopted
SFAS No. 123 (revised December 2004), "Share-Based Payments". The adoption of
this statement requires that the compensation cost associated with our stock
appreciation rights plan, which upon exercise will result in the payment of cash
to the employee, be re-measured each reporting period based on the fair value of
the rights. Under SFAS 123(R), the liability will be calculated using a fair
value method that will take into consideration the expected future value of the
rights at their expected exercise dates.
We have elected to calculate the fair value of the rights under the
plan using the Black-Scholes valuation model. This model requires that we
include the expected volatility of the market price for our common units, the
current price of our common units, the exercise price of the rights, the
expected life of the rights, the current risk free interest rate, and our
expected annual distribution yield. This valuation is then applied to the vested
rights outstanding and to the non-vested rights based on the percentage of the
service period that has elapsed. The valuation is adjusted for expected
forfeitures of rights (due to terminations before vesting, or expirations after
vesting). The liability amount accrued on the balance sheet is adjusted to this
amount at each balance sheet date with the adjustment reflected in the statement
of operations.
The estimates that we made upon the adoption of this standard included
the following:
- In determining the expected life of the rights, we used the
simplified method allowed by the Securities and Exchange
Commission. As our stock appreciation rights plan was not put in
place until December
-20-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
31, 2003, we have very limited experience with employee exercise
patterns. The simplified method produces an initial expected life
of 6.25 years for those rights we issued that vest 25% per year
for four years, and an initial expected life of 7 years for those
rights we issued that fully vest at the end of a four-year
period.
- The expected volatility of our units was computed using the
historical period we believe is representative of future
expectations. We determined what period to use in the historical
period by considering whether we were paying distributions to our
unitholders, and at what rate. The expected volatility used in
the fair value calculations was approximately 33% and 32% at
January 1, 2006 and June 30, 2006, respectively.
- The risk-free interest rate was determined from current yields
for U.S. Treasury zero-coupon bonds with a term similar to the
remaining expected life of the rights. At January 1, 2006, the
risk-free interest rate ranged from 4.39% to 4.41%. At June 30,
2006, the risk-free interest rate ranged from 5.07% to 5.08%.
- In determining our expected future distribution yield, we
considered our history of distribution payments, our expectations
for future payments, and the distribution yields of entities
similar to us. At January 1, 2006 and June 30, 2006, we used an
expected future distribution yield of 6%.
- The final estimate we were required to make is the expected
forfeitures of non-vested rights and expirations of vested
rights. We have very limited experience with employee forfeiture
and expiration patterns, as our plan was not initiated until
December 31, 2003. We reviewed the history available to us as
well as employee turnover patterns in determining the rates to
use. We also used different estimates for different groups of
employees.
At December 31, 2005, we had a recorded liability of $0.8 million,
computed under the provisions of FASB Interpretation No. 28. We calculated the
effect of adoption of SFAS 123(R) at January 1, 2006, and determined that our
recorded liability at December 31, 2005 should be reduced by $30,000. This
reduction is reflected as income from the cumulative effect of the adoption of a
new accounting principle on our statement of operations. We do not believe the
effect of adoption of this accounting principle at January 1, 2005 would have
been material. The adjustment of the liability to its fair value of $1.3 million
at June 30, 2006, resulted in general and administrative expense of $0.3 million
and $0.5 million for the three and six month periods ended June 30, 2006,
respectively.
The following table reflects rights activity under our plan as of
December 31, 2005, and changes during the six months ended June 30, 2006:
Weighted
Weighted Average Aggregate
Average Remaining Intrinsic
Exercise Contractual Value
Stock Appreciation Rights Rights Price Term (Yrs) (in thousands)
- ------------------------- ------- -------- ----------- --------------
Outstanding at January 1, 2006 596,128 $10.39
Granted 12,833 $13.04
Exercised (10,165) $ 9.26
Forfeited or expired (35,291) $11.09
-------
Outstanding at June 30, 2006 563,505 $10.42 8.2 $1,300
=======
Exercisable at June 30, 2006 156,606 $ 9.48 7.4 $ 705
=======
The weighted-average fair value at June 30, 2006 of rights granted
during the six months of 2006 was $3.06 per right. The total intrinsic value of
rights exercised during the first two quarters of 2006 was $28,000, which was
paid in cash to the participants.
At June 30, 2006, there was $0.7 million of total unrecognized
compensation cost related to rights that we expect will vest under the plan.
This amount was calculated as the fair value at June 30, 2006 multiplied by
those
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GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
rights for which compensation cost has not been recognized, adjusted for
estimated forfeitures. This unrecognized cost will be recalculated at each
balance sheet until the rights are exercised, forfeited or expire. For the
awards outstanding at June 30, 2006, the remaining cost will be recognized over
a weighted average period of 1 year.
13. INCOME TAXES
In May 2006, the State of Texas enacted a margin tax that will become
effective in 2008. This margin tax will require us to pay a tax of 0.5% on our
"margin," as defined in the law, beginning in 2008 based on our 2007 results.
The margin to which the tax rate will be applied generally will be calculated as
our revenues for federal income tax purposes less the cost of the products sold
for federal income tax purposes, in the State of Texas. Under the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes", we are required to record the effects on deferred taxes for a change in
tax rates or tax law in the period that includes the enactment date.
Under FAS 109, taxes based on income like the Texas margin tax are
accounted for using the liability method under which deferred income taxes are
recognized for the future tax effects of temporary differences between the
financial statement carrying amounts and the tax basis of existing assets and
liabilities using the enacted statutory tax rates in effect at the end of the
period. A valuation allowance for deferred tax assets is recorded when it is
more likely than not that the benefit from the deferred tax asset will not be
realized.
Temporary differences related to our inventory will affect the Texas
margin tax, so we have recorded a deferred tax asset in the amount of $11,000.
We believe that we will be able to utilize this deferred tax asset at June 30,
2006, and therefore have provided no valuation allowance against this deferred
tax asset.
14. SUBSEQUENT EVENTS
Distribution
On July 18, 2006, the Board of Directors of the general partner
declared a cash distribution of $0.19 per unit for the quarter ended June 30,
2006. The distribution will be paid August 14, 2006 to our general partner and
all common unitholders of record as of the close of business on July 31, 2006.
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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
- Acquisitions in 2006
- Results of Operations
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- 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. Our
profitability depends to a significant extent upon our ability to maximize
segment margin. Segment margin is calculated as revenues less cost of sales and
operating expense, and does not include depreciation and amortization. Segment
margin also includes our equity in the operating income of joint ventures. A
reconciliation of segment margin to income from continuing operations is
included in our segment disclosures in Note 6 to the consolidated financial
statements. Available Cash before Reserves is a non-GAAP liquidity measure
calculated as net income with several adjustments, the most significant of which
are the elimination of gains and losses on asset sales, except those from the
sale of surplus assets, the addition of non-cash expenses such as depreciation,
the replacement with the amount recognized as our equity in the income of joint
ventures with the available cash generated from those ventures, and the
subtraction of maintenance capital expenditures, which are expenditures to
sustain existing cash flows but not to provide new sources of revenues. 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 Financial Measure" below.
OVERVIEW
We conduct our business through three segments - pipeline
transportation, industrial gases and crude oil gathering and marketing. We have
a diverse portfolio of customers and assets, including pipeline transportation
of primarily crude oil and, to a lesser extent, natural gas and CO(2) in the
Gulf Coast region of the United Sates. In conjunction with our crude oil
pipeline transportation operations, we operate a crude oil gathering and
marketing business, which helps ensure a base supply of crude oil for our
pipelines. We also participate in industrial gas activities, including a CO(2)
supply business, which is associated with the CO(2) tertiary oil recovery
process being used in Mississippi by an affiliate of our general partner. We
generate revenues by selling crude oil and industrial gases, by charging fees
for the transportation of crude oil, natural gas and CO(2) on our pipelines,
and, through our joint venture in T&P Syngas Supply Company, by charging fees
for services to produce syngas for our customer from the customer's raw
materials. Our focus is on the margin we earn on these revenues, which is
calculated by subtracting the costs of the crude oil and natural gas; the costs
of transporting the crude oil, natural gas and CO(2) to the customer; and the
costs of operating our assets. We also report our share of the earnings of our
joint ventures, T&P Syngas, in which we acquired a 50% interest on April 1,
2005, and Sandhill Group, LLC, in which we acquired a 50% interest on April 1,
2006.
Our objective is to operate as a growth-oriented midstream MLP with a
focus on increasing cash flow, earnings and return to our unitholders by
becoming one of the leading providers of pipeline transportation, crude oil
gathering and marketing and industrial gas services in the regions in which we
operate. Increases in cash flow generally result in increases in Available Cash,
which we distribute quarterly to our unitholders and general partner. During the
second quarter of 2006, we generated $6.1 million of Available Cash before
Reserves, and distributed $2.5 million to our unitholders and general partner.
During the second quarter of 2006, cash provided by operations was $0.8 million.
In the second quarter of 2006, we generated net income of $3.4
million, or $0.24 per common unit. For the six month period ended June 30, 2006,
net income totaled $6.0 million, or $0.43 per common unit. The results for
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
2006 include increased segment margin from our pipeline transportation and crude
oil gathering and marketing segments and significant contributions from asset
acquisitions in the industrial gases segment. We also adopted a new accounting
pronouncement affecting the manner in which we value and account for our stock
appreciation rights plan.
We increased our cash distribution by $0.01 to $0.18 per unit for the first
quarter of 2006 (which was paid in May 2006) and increased our cash distribution
again to $0.19 per unit for the second quarter of 2006. This distribution will
be paid in August 2006. This distribution represented a 27% increase from our
distribution of $0.15 per unit for the second quarter of 2005.
ACQUISITIONS IN 2006
SANDHILL INVESTMENT
On April 1, 2006, we acquired a 50% partnership interest in Sandhill
Group, LLC for $5 million from Magna Carta Group, LLC. Magna Carta holds the
other 50% interest in Sandhill. Sandhill is a limited liability company that
owns a CO(2) processing facility located in Brandon, Mississippi. Sandhill is
engaged in the production and distribution of liquid carbon dioxide for use in
the food, beverage, chemical and oil industries. The facility acquires CO(2)
from us under a long-term supply contract that we acquired in 2005 from Denbury.
The acquisition was financed with cash on hand. The terms of the
acquisition include earnout provisions such that additional payments of up to
$2.0 million would be paid by us to Magna Carta if Sandhill achieves targeted
performance levels during the seven years between 2006 and 2012 inclusive. We
have also guaranteed to Sandhill's lender 50% of the outstanding debt of $4.7
million, or $2.35 million.
Sandhill is managed by a management committee consisting of two
representatives each from Magna Carta and us. Our equity in the earnings of
Sandhill is included in our industrial gases segment. Additional discussion of
the earnout provisions and guaranty of Sandhill's debt is included in Note 3 to
the financial statements and in "Commitments and Off-Balance Sheet Arrangements"
below.
RESULTS OF OPERATIONS
PIPELINE TRANSPORTATION OPERATIONS
We operate three crude oil common carrier pipeline systems in a four
state area. We refer to these pipelines as our Texas System, Mississippi System
and Jay System. Volumes shipped on these systems are as follows:
Three Months Six Months
Ended June 30, Ended June 30,
--------------- ---------------
2006 2005 2006 2005
------ ------ ------ ------
(barrels per day)
Mississippi... 16,990 15,655 16,701 15,896
Jay........... 13,727 15,204 12,577 15,030
Texas......... 32,061 33,234 33,142 31,540
The Mississippi System begins in Soso, Mississippi and extends to
Liberty, Mississippi. At Liberty, shippers can transfer the crude oil to
Capline, a pipeline system that moves crude oil from the Gulf Coast to
refineries in the Midwest. The system has been improved to handle the increased
volumes produced by Denbury and transported on the pipeline. In order to handle
future increases in production volumes in the areas that are expected, we have
made capital expenditures for tank, station and pipeline improvements and we
intend to make further improvements. See Capital Expenditures under "Liquidity
and Capital Resources" below.
Denbury is the largest producer (based on average barrels produced per
day) of crude oil in the State of Mississippi. Our Mississippi System is
adjacent to several of Denbury's existing and prospective oil fields. As Denbury
continues to acquire and develop old oil fields using CO(2) based tertiary
recovery operations, additional
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
crude oil gathering and CO(2) supply infrastructure will be needed, although we
can provide no assurance that we will be involved in any such projects.
The Jay pipeline system in Florida/Alabama ships crude oil from fields
with relatively short remaining production lives. While new production in the
area surrounding the Jay System has offset some of the declining production
curves of the older producing fields in the area, we do not know if this new
production will be sufficient to continue to offset declining production from
existing wells in the area. One of the larger older fields has been unable to
return to its production levels before the hurricanes of 2005. Another producing
field reduced production during part of the first quarter of 2006 for
maintenance. We do not know if these producers will be successful in returning
to production levels before the hurricanes, however we have seen an increase in
volume in the second quarter of 2006 as compared to the first quarter.
Should the production surrounding the Jay System decline such that it
becomes uneconomical to continue to operate the pipeline in crude oil service,
we believe that the best use of the Jay System may be to convert it to natural
gas service. We continue to review opportunities to effect such a conversion.
Part of the process will involve finding alternative methods for us to continue
to provide crude oil transportation services in the area. While we believe this
initiative has long-term potential, it is not expected to have a substantial
impact on us during 2006 or 2007.
Volumes on our Texas System averaged 33,142 barrels per day during the
first half of 2006. The crude oil that enters our system comes to us at West
Columbia where we have a connection to TEPPCO's South Texas System and at
Webster where we have connections to two other pipelines. One of these
connections at Webster is with ExxonMobil Pipeline and is used to receive
volumes that originate from TEPPCO's pipelines. We have a joint tariff with
TEPPCO under which we earn approximately $0.22 per barrel on the majority of the
barrels we deliver to the shipper's facilities. Substantially all of the volume
being shipped on our Texas System goes to two refineries on the Texas Gulf
Coast.
Our Texas System is dependent on the connecting carriers for supply,
and on the two refineries for demand for our services. Volumes on the Texas
System fluctuate as a result of changes in the supply available for the two
refineries to acquire and ship on our pipeline. We lease tankage in Webster on
the Texas System of approximately 165,000 barrels. We have a tank rental
reimbursement agreement with the primary shipper on our Texas System to
reimburse us for leasing that storage capacity. Volumes on the Texas System may
continue to fluctuate as refiners on the Texas Gulf Coast compete for crude oil
with other markets connected to TEPPCO's pipeline systems.
We operate a CO(2) pipeline in Mississippi to transport CO(2) from
Denbury's main CO(2) pipeline to Brookhaven oil field. Denbury has the exclusive
right to use this CO(2) pipeline. This arrangement has been accounted for as a
direct financing lease.
Historically, the largest operating costs in our crude oil pipeline
segment have consisted of personnel costs, power costs, maintenance costs and
costs of compliance with regulations. Some of these costs are not predictable,
such as equipment failure or power cost increases. We perform regular
maintenance on our assets to keep them in good operational condition and to
minimize cost increases.
Operating results from continuing operations for our pipeline
transportation segment were as follows:
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
------- ------- ------- -------
(in thousands)
Crude oil tariffs and revenues from direct financing
leases of crude oil pipelines.................................. $ 3,534 $ 3,517 $ 6,867 $ 6,781
Sales of crude oil pipeline loss allowance volumes................ 2,077 1,219 3,395 2,298
Revenues from direct financing leases of CO2 pipelines............ 86 91 173 183
Tank rental reimbursements and other miscellaneous revenues....... 164 166 308 299
------- ------- ------- -------
Revenues from crude oil and CO2 tariffs and related sources.... 5,861 4,993 $10,743 $ 9,561
Revenues from natural gas tariffs and sales....................... 2,760 1,891 5,648 4,635
Natural gas purchases............................................. (2,542) (1,776) (5,241) (4,412)
Pipeline operating costs.......................................... (2,477) (2,300) (4,746) (4,533)
------- ------- ------- -------
Segment margin................................................. $ 3,602 $ 2,808 $ 6,404 $ 5,251
======= ======= ======= =======
Crude oil pipeline volumes per day-barrels........................ 62,778 64,093 62,420 62,466
Three Months Ended June 30, 2006 Compared with Three Months Ended June
30, 2005
Pipeline segment margin increased $0.8 million or 28% to $3.6 million
for the three months ended June 30, 2006, as compared to $2.8 million for the
three months ended June 30, 2005. Revenues from crude oil and CO(2) tariffs and
related sources added the majority of the increase for the period. Higher market
prices for crude oil added $0.9 million to pipeline loss allowance revenues.
Overall volumes on the pipelines declined; however, we actually had declines on
some lower tariff pipeline segments and volume increases on higher tariff
segments such that the overall effect was lower volumes with little variation in
crude oil tariff revenues.
Segment margin from our natural gas pipelines also increased by $0.1
million, primarily as a result of improved volumes.
Partially offsetting the improved revenues was an increase of $0.2
million in the costs of operating our pipelines. Most of this increase was due
to maintenance of tanks and other repairs.
Six Months Ended June 30, 2006 Compared with Six Months Ended June 30,
2005
Pipeline segment margin increased $1.2 million or 22% to $6.4 million
for the six months ended June 30, 2006, as compared to the six months ended June
30, 2005. Revenues from crude oil and CO(2) tariffs and related sources
increased by $1.2 million with the majority of that increase resulting from the
effects of higher market prices for crude oil on pipeline loss allowance
revenues.
Increased pipeline operating costs of $0.2 million were offset by
increased margin from natural gas pipeline activities. The higher costs resulted
from increases in a variety of costs including electricity, insurance, and
right-of-way maintenance.
INDUSTRIAL GASES SEGMENT
Our industrial gases segment includes the results of our CO(2) sales
to industrial customers and our share of the operating income of our 50%
interests in T&P Syngas and Sandhill.
CO(2)
We supply CO(2) to industrial customers under seven long-term CO(2)
sales contracts. We acquired those contracts, as well as the CO(2) necessary to
satisfy substantially all of our expected obligations under those contracts, in
three separate transactions with Denbury. We sell our CO(2) to customers who
treat the CO(2) and sell it to end users for use for beverage carbonation and
food chilling and freezing. Our compensation for supplying CO(2) to our
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
industrial customers is the difference between the price at which we sell our
CO(2) under each contract and the price at which we acquired our CO(2) pursuant
to our volumetric production payments (VPPs), minus transportation costs. We
expect our CO(2) contracts to provide stable cash flows until they expire, at
which time we will attempt to extend or replace those contracts, including
acquiring the necessary CO(2) supply from wholesalers. At June 30, 2006, we have
224.3 Bcf of CO(2) remaining under the VPPs.
The terms of our contracts with the industrial CO(2) customers include
minimum take-or-pay and maximum delivery volumes. The maximum daily contract
quantity per year in the contracts totals 98,000 Mcf. Under the minimum
take-or-pay volumes, the customers must purchase a total of 51,000 Mcf per day
whether received or not. Any volume purchased under the take-or-pay provision in
any year can then be recovered in a future year as long as the minimum
requirement is met in that year. In the three years ended December 31, 2005, all
of our customers purchased more than their minimum take-or-pay quantities.
Our seven industrial contracts expire at various dates beginning in
2010 and extending through 2023. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price. One of the seven contracts is with Sandhill in which we
hold a 50% ownership interest. The contract with Sandhill expires in 2023.
Our industrial customers treat the CO(2) and transport it to their own
customers. The primary industrial applications of CO(2) by these customers
include beverage carbonation and food chilling and freezing. Based on historical
data for 2004 through 2006, we can expect some seasonality in our sales of
CO(2). The dominant months for beverage carbonation and freezing food are from
April to October, when warm weather increases demand for beverages and the
approaching holidays increase demand for frozen foods. The table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of CO(2) for each
quarter in 2006, 2005 and 2004 under these contracts (including volumes sold by
Denbury on the contracts we acquired in the third quarter of 2004 and fourth
quarter of 2005) were as follows:
Quarter 2006 2005 2004
- ------- ------ ------ ------
First 66,565 67,434 63,953
Second 73,495 73,307 73,734
Third 77,264 78,097
Fourth 77,089 70,696
Syngas
On April 1, 2005, we acquired from TCHI Inc., a wholly owned
subsidiary of ChevronTexaco Global Energy Inc., a 50% partnership interest in
T&P Syngas for $13.4 million in cash, which we funded with proceeds from our
credit facility. T&P Syngas is a partnership which owns a facility located in
Texas City, Texas that manufactures syngas (a combination of carbon monoxide and
hydrogen) and high-pressure steam. Under that processing agreement, Praxair
provides the raw materials to be processed and receives the syngas and steam
produced by the facility. T&P Syngas receives a processing fee for its services.
Praxair has the exclusive right to use the facility through at least 2016 (term
extendable at Praxair's option for two additional five year terms). Praxair also
is our partner in the joint venture and owns the remaining 50% interest. We
recognize our share of the earnings of T&P Syngas in each period. We are
amortizing the excess of the price we paid for our interest in T&P Syngas over
our share of the equity of T&P Syngas over the remaining useful life of the
assets of T&P Syngas. This excess of $4.0 million is being amortized over eleven
years. We receive cash distributions from T&P Syngas quarterly.
Sandhill
On April 1, 2006, we acquired from Magna Carta Group, LLC a 50%
partnership interest in Sandhill for $5.0 million in cash, which we funded with
cash on hand. Magna Carta owns the remaining 50% of Sandhill. Sandhill is a
limited liability company that owns a CO(2) processing facility located in
Brandon, Mississippi. Sandhill
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
is engaged in the production and distribution of liquid carbon dioxide for use
in the food, beverage, chemicals and oil industries. The facility acquires CO(2)
from us under a long-term supply contract that we acquired in 2005 from Denbury.
This contract expires in 2023, and provides for a daily contract quantity of
16,000 Mcf per day with a take-or-pay minimum quantity of 2,500,000 Mcf.
We recognize our share of the earnings of Sandhill in each period. We
paid $3.8 million more for our interest in Sandhill than our share of the equity
on the balance sheet of Sandhill at the date of acquisition. This excess of the
purchase price over our share of the equity of Sandhill has been allocated to
the property and equipment and intangible assets based on the fair value of
those assets, with the remaining $0.5 million allocated to goodwill. We are
amortizing the amount allocated to property, equipment and intangibles over the
remaining useful lives of those assets. The amount allocated to goodwill will be
reviewed for impairment periodically.
Segment margin
Operating results from operations for our industrial gases segment
were as follows:
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
------- ------- ------- -------
(in thousands, except volumes per day)
Revenues from CO(2) .......................... $ 3,894 $ 2,568 $ 7,281 $ 4,848
CO(2) transportation and other costs ......... (1,207) (811) (2,280) (1,566)
Equity in earnings of joint ventures ......... 339 252 652 252
------- ------- ------- -------
Segment margin ............................ $ 3,026 $ 2,009 $ 5,653 $ 3,534
======= ======= ======= =======
Volumes per day from continuing operations:
CO(2) Sales - Mcf ......................... 73,495 51,049 70,049 49,437
Three Months Ended June 30, 2006 Compared with Three Months Ended June
30, 2005
The increasing margins from the industrial gases segment between the
second quarter of 2005 and 2006 are primarily attributable to the acquisition we
made in the fourth quarter of 2005 in this segment. The average revenue per Mcf
sold increased 5% between the periods, due to inflation adjustments in the
contracts and variations in the volumes sold under each contract.
Transportation costs for the CO(2) on Denbury's pipeline have
increased due to the increased volume and the effect of the annual inflation
factor in the rate paid to Denbury. The rate per Mcf in 2006 increased 2% over
the 2005 second quarter rate.
Our share of the operating income of T&P Syngas for the second quarter
of 2006 was $410,000. We reduced the amount we recorded as our equity in T&P
Syngas by $88,000 as amortization of the excess purchase price of T&P Syngas.
During the second quarter of 2006, T&P Syngas paid us a distribution totaling
$0.6 million attributable to the first quarter of 2006.
Our share of the operating income of Sandhill for the second quarter
of 2006 was $90,000. We reduced the amount we recorded as our equity in Sandhill
by $73,000 as amortization of the excess purchase price of Sandhill.
Six Months Ended June 30, 2006 Compared with Six Months Ended June 30,
2005
The six month period in 2006 includes the margins from CO2 sales under
industrial contracts acquired in 2005, providing approximately $1.8 million of
the $2.1 million improvement in segment margin. Variations in the volumes sold
under each of the existing group of contracts, combined with inflation
adjustments in the contracts, added additional revenues. The effect of the
annual inflation factor in the rate paid to Denbury increased transportation
costs.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
T&P Syngas provided $635,000 of the equity from joint ventures for the
six-month period. Our share of T&P Syngas' earnings was $811,000, and we
recorded $176,000 of amortization of the excess purchase price. In 2006, T&P has
paid $830,000 in cumulative distributions to us.
Sandhill was not acquired until the second quarter of 2006, so its
contribution for the six month period was the same as the second quarter.
CRUDE OIL GATHERING AND MARKETING OPERATIONS
We conduct certain crude oil aggregating operations, which involve
purchasing, gathering, transporting by trucks and pipelines owned by us and
trucks, pipelines and barges operated by others, and reselling, that (among
other things) help ensure supply for our crude oil pipeline systems. Our profit
for those services is derived from the difference between the price at which we
re-sell crude oil less the price at which we purchase that crude oil, minus the
associated costs of aggregation and any cost of supplying credit. The most
substantial component of our aggregating costs relates to operating our fleet of
leased trucks. Our crude oil gathering and marketing activities provide us with
extensive expertise, knowledge base and skill sets that facilitate our ability
to capitalize on regional opportunities which arise from time to time in our
market areas. Usually this segment experiences limited commodity price risk
because we generally make back-to-back purchases and sales, matching our sale
and purchase volumes on a monthly basis.
The commodity price (for purchases and sales) of crude oil do not
necessarily bear a relationship to segment margin as those prices normally
impact revenues and costs of sales by approximately equivalent amounts. Because
period-to-period variations in revenues and costs of sales are not generally
meaningful in analyzing the variation in segment margin for our gathering and
marketing operations, these changes are not addressed in the following
discussion.
Generally, as we purchase crude oil, we simultaneously establish a
margin by selling crude oil for physical delivery to third party users, such as
independent refiners or major oil companies. Through these transactions, we seek
to maintain a position that is substantially balanced between crude oil
purchases, on the one hand, and sales or future delivery obligations, on the
other hand. We do not hold crude oil, futures contracts or other derivative
products to speculate on crude oil price changes. When our positions become
unbalanced such that we have inventory, we will use derivative instruments to
hedge that inventory until such time as we can sell it into the market. From
time to time, when market conditions are favorable, we will purchase crude oil
and hold it in our storage facilities as inventory. We purchase inventory only
when we both have adequate capacity in our storage tanks and can
contemporaneously enter into a hedge contract that assures us a minimum profit
on that purchase. If commodity prices increase enough to justify it, in future
periods we may pay the costs to close out our hedge and replace it with another
hedge that assures us of a higher profit. Our storage capacity limits the amount
of inventory we can profitably purchase and hedge at anytime using this
strategy. The maximum storage available to us is approximately 120,000 barrels,
although it could be less for short periods of time due to maintenance, repairs
or similar activities. We generally will account for this inventory and the
related derivative hedge as a fair value hedge in accordance with Statement of
Financial Accounting Standards No. 133. See Note 10 to the Consolidated
Financial Statements.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil. The pricing in the
majority of our purchase contracts contain the market price component, a bonus
that is not fixed, but instead is based on another market factor and a deduction
to cover the cost of transporting the crude oil and to provide us with a margin.
Contracts will sometimes also contain a grade differential which considers the
chemical composition of the crude oil and its appeal to different customers.
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 grade differentials.
Field operating costs consist of the costs to operate our fleet of
leased trucks used to transport crude oil, and the costs to maintain the trucks
and assets used in the crude oil gathering operation. More than 60% of these
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
costs are variable and increase or decrease with volumetric changes. These costs
include payroll and benefits (as drivers are paid on a commission basis based on
volumes), maintenance costs for the trucks (as we lease the trucks under full
service maintenance contracts under which we pay a maintenance fee per mile
driven), and fuel costs. Fuel costs also fluctuate based on changes in the
market price of diesel fuel. Fixed costs include the base lease payment for the
vehicle, insurance costs and costs for environmental and safety related
operations.
Operating results from continuing operations for our crude oil
gathering and marketing segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
-------- -------- -------- --------
(in thousands, except volumes per day)
Revenues ..................................... $220,828 $247,692 $473,273 $494,700
Crude oil costs .............................. 214,761 243,059 462,133 485,347
Field operating costs ........................ 3,720 4,183 7,065 8,015
-------- -------- -------- --------
Segment margin ............................ $ 2,347 $ 450 $ 4,075 $ 1,338
======== ======== ======== ========
Volumes per day from continuing operations:
Crude oil wellhead - barrels (1) .......... 33,832 40,323 35,220 41,142
Crude oil total - barrels (1) ............. 35,372 55,722 40,303 57,027
Crude oil transported only - barrels ...... 4,258 2,702 3,517 3,905
(1) Excludes buy/sell volumes beginning April 1, 2006
Three Months Ended June 30, 2006 as Compared to Three Months Ended
June 30, 2005
Gathering and marketing segment margins increased $1.9 million to $2.3
million for the three months ended June 30, 2006, as compared to $0.4 million
for the three months ended June 30, 2005.
The primary reasons for this increase in segment margin were an
improvement in marketing margins and a decrease in field costs. An increase in
the average difference between the sales price and the purchase price of crude
oil increased segment margin by $1.3 million, despite a decrease in purchased
volumes. Marketing margins have improved between the periods as we have focused
on eliminating volumes providing insufficient contribution to our segment
margin.
In the 2005 quarter, field costs included a reserve we recorded of
$0.4 million for 40% of the expected costs to remediate Jay Station. (See
additional discussion at Note 11 to the Consolidated Financial Statements.) The
$0.1 million remainder of the decrease in field costs in 2006 is attributable to
a reduction in the size of our fleet. When we leased new trucks late in 2005, we
reduced the size of the fleet to better match the volumes being purchased. This
reduction in fleet size reduced personnel and truck lease costs. Higher fuel
costs offset part of the reduction. Fuel costs increased more than $0.50 per
gallon over the 2005 quarter.
Adding to the improved segment margin was a $0.1 million increase in
revenues from volumes that we transported for a fee but did not purchase.
Six Months Ended June 30, 2006 as Compared to Six Months Ended June
30, 2005
For the six month periods, gathering and marketing segment margins
increased $2.7 million, to three times the result for the 2005 period. Reduced
field operating costs added $1.0 million to margin. The remaining increase of
$1.7 million resulted again from a focus on eliminating less profitable volumes,
and increasing profitability on the volumes retained.
The majority of the decrease in field operating costs of $1.0 million
is attributable to a reduction in the size of our fleet, combined with the $0.4
million reserve recorded in 2005 for Jay Station. The fleet size reduction
reduced personnel and lease costs for the tractor/trailers by a total of $0.5
million. Insurance costs were also
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
reduced by $0.2 million due to the decreased activity level. These reductions
were partially offset by increased fuel costs, which added $0.1 million to field
costs despite the smaller fleet size. Prices for diesel fuel were approximately
$0.50 per gallon greater than in the 2005 period.
OTHER COSTS AND INTEREST
General and administrative expenses. General and administrative
expenses consisted of the following:
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
------ ------ ------ -------
(in thousands)
Expenses excluding effect of stock appreciation rights plan .. $2,929 $2,425 $5,467 $ 4,612
Stock appreciation rights plan expense (credit) .............. 320 43 442 (1,286)
------ ------ ------ -------
Total general and administrative expenses ................. $3,249 $2,468 $5,909 $ 3,326
====== ====== ====== =======
Three Months Ended June 30, 2006 Compared with Three Months Ended June
30, 2005
General and administrative expenses increased by $0.8 million, with
$0.3 million of the increase attributable to our employee stock appreciation
rights plan.
This plan is a long-term incentive plan whereby rights are granted for
the grantee to receive cash equal to the difference between the grant price and
common unit price at date of exercise. The rights vest over several years. In
2005 we accounted for these rights under the provisions of FASB Interpretation
No. 28, which provided that we calculate the difference between the current
market price for our common units and the strike price of the rights. On January
1, 2006, we adopted the provisions of a new accounting pronouncement for
accounting for stock-based compensation. Under this pronouncement, we determine
the fair value of the rights at each balance sheet date, and record the change
in fair value over the service period required from our employees before the
rights vest. See additional discussion below under "Cumulative Effect Adjustment
of Adoption of New Accounting Principle" and in Note 12 to the financial
statements.
The remaining increase in general and administrative expenses is
attributable to employee costs. As a result of our improved results, the accrual
for bonus compensation for our employees is $0.4 million greater than for the
2005 three-month period. Additionally, salary increases and higher benefit costs
added $0.2 million to expenses. Reduced office space costs from a rent
renegotiation offset $0.1 million of the higher personnel costs.
Six Months Ended June 30, 2006 Compared with Six Months Ended June 30,
2005
Between the two six month periods, general and administrative expenses
were $2.6 million greater. $1.7 million of this increase is attributable to the
accounting for the stock appreciation rights plan. At June 30, 2005, our unit
price was $9.39 per unit, a decline from $12.60 per unit at December 31, 2004.
As a result, a reduction of $1.3 million in the accrual was recorded. In 2006,
with the adoption of the new accounting pronouncement, we recorded expense of
$0.4 million for our plan, resulting in a fluctuation between the six-month
periods of a total of $1.7 million.
The remaining $0.9 million increase in general and administrative
expenses was attributable to increases in employee costs, including benefits and
bonus accruals, offset slightly by a reduction in office rent.
Depreciation, amortization and impairment expense increased $0.5
million between 2005 and 2006 second quarters, and $0.8 million between the
six-month periods. The majority of these increases related to amortization of
our CO(2) assets. Amortization of the CO(2) assets increased due to the
additional CO(2) contracts acquired in the fourth quarter of 2005.
Interest expense, net.
Interest expense, net was as follows:
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2006 2005 2006 2005
---- ---- ----- ----
(in thousands)
Interest expense, including commitment fees .. $216 $440 $ 331 $713
Amortization of facility fees ................ 77 88 162 176
Interest income .............................. (30) (22) (108) (28)
---- ---- ----- ----
Net interest expense ...................... $263 $506 $ 385 $861
==== ==== ===== ====
In the 2006 second quarter, our net interest expense decreased by $0.2
million compared to the 2005 period. In the 2006 period, our average outstanding
balance of bank debt was $14.6 million lower than in the 2005 second quarter and
our average interest rate was 0.9% greater than in the 2005 period. For the
six-month periods, interest expense was $0.5 million lower due to average
outstanding bank debt that was $12.5 million lower and an interest rate that was
0.9% greater. Our equity offering in December 2005 was used to repay outstanding
debt from acquisitions in 2005 and prior years, resulting in the lower average
debt balance in 2006.
Gain on disposal of surplus assets. In the 2006 second quarter and
first half, we disposed of a minimal amount of surplus assets. In the 2005 first
half, we sold the Liberty to Maryland segment of our Mississippi pipeline and
two idle segments of pipeline in Texas. The Mississippi segment had been
out-of-service since February 2002. The Texas segments were idle as a result of
our sale of part of our Texas System to TEPPCO in 2003. Additionally we sold an
idle site in Houma, Louisiana. We received $1.4 million from the sales of these
assets and realized gains totaling $0.7 million, of which $0.3 million was
recorded as discontinued operations.
CUMULATIVE EFFECT ADJUSTMENT - ADOPTION OF NEW ACCOUNTING PRINCIPLE
On January 1, 2006, we adopted the provisions of SFAS No. 123(R). In
December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payments". The adoption of this statement requires that the
compensation cost associated with our stock appreciation rights plan, which upon
exercise will result in the payment of cash to the employee, be re-measured each
reporting period based on the fair value of the rights. Before the adoption of
SFAS 123(R), we accounted for the stock appreciation rights in accordance with
FASB Interpretation No. 28, "Accounting for Stock Appreciation Rights and Other
Variable Stock Option or Award Plans" which required that the liability under
the plan be measured at each balance sheet date based on the market price of our
common units on that date. Under SFAS 123(R), the liability will be calculated
using a fair value method that will take into consideration the expected future
value of the rights at their expected exercise dates.
We have elected to calculate the fair value of the rights under the
plan using the Black-Scholes valuation model. This model requires that we
consider the expected volatility of the market price for our common units, the
current price of our common units, the exercise price of the rights, the
expected life of the rights, the current risk free interest rate, and our
expected annual distribution yield. This valuation is then applied to the vested
rights outstanding and to the non-vested rights based on the percentage of the
service period that has elapsed. The valuation is adjusted for expected
forfeitures of rights (due to terminations before vesting, or expirations after
vesting). The liability amount accrued on the balance sheet is adjusted to this
amount with the adjustment reflected in the statement of operations.
The estimates that we made upon the adoption of this standard at
January 1, 2006 included the following:
- In determining the expected life of the rights, we used the
simplified method allowed by the Securities and Exchange
Commission. We have very limited experience with employee
exercise patterns, as our plan was initiated on December 31,
2003. The simplified method produces an initial expected life of
6.25 years for those rights we issued that vest 25% per year for
four years, and an initial expected life of 7 years for those
rights we issued that fully vest at the end of a four-year
period.
- The expected volatility of our units was computed using the
historical period we believe is representative of future
expectations. We determined what period to use in the historical
period by considering whether we were paying distributions to our
unitholders, and at what rate. The expected
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
volatility used in the fair value calculations was approximately
33% at January 1, 2006 and 32% at June 30, 2006.
- The risk-free interest rate was determined from current yields
for U.S. Treasury zero-coupon bonds with a term similar to the
remaining expected life of the rights.
- In determining our expected future distribution yield, we
considered our history of distribution payments, our expectations
for future payments, and the distribution yields of entities
similar to us.
- The final estimate we were required to make is the expected
forfeitures of non-vested rights and expirations of vested
rights. As our stock appreciation rights plan was not put in
place until December 31, 2003, we have very limited experience
with employee forfeiture and expiration patterns. We reviewed the
history available to us as well as employee turnover patterns in
determining the rates to use. We also decided to use different
estimates for different groups of employees.
At December 31, 2005, we had a recorded liability of $0.8 million,
computed under the provisions of FASB Interpretation No. 28. We calculated the
effect of adoption of SFAS 123(R) at January 1, 2006, and determined that our
recorded liability at December 31, 2005 should be reduced by $30,000. This
reduction is reflected as income from the cumulative effect of the adoption of a
new accounting principle on our statement of operations. We do not believe the
effect of adoption of this accounting principle at January 1, 2005 would have
been material. The adjustment of the liability to its fair value at June 30,
2006, resulted in the expense of $0.5 million that is included in general and
administrative expenses for the six months ended June 30, 2006.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
We have a $100 million credit facility comprised of a $50 million
revolving line of credit for acquisitions and a $50 million working capital
revolving facility. The working capital portion of the credit facility is
composed of two components - up to $15 million for loans and up to $35 million
for letters of credit. In total we may borrow up to $65 million in loans under
our credit facility. At June 30, 2006, we had $11.8 million in letters of credit
and $11.5 million of debt outstanding under the working capital portion. 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 1, 2008.
Interest on amounts borrowed under the credit facility is equal to (x)
either the applicable Eurodollar settlement rate or the higher of the Federal
funds rate plus 1/2 of 1% or Bank of America's prime rate for the relevant
period, at our option, plus (y) the applicable margin rate. We are required to
pay our credit facility lenders a fee based upon amounts available but not
borrowed under each of the acquisition and working capital facilities, as well
as certain other fees.
The aggregate amount that we may have outstanding at any time in loans
and letters of credit under the working capital portion of our credit facility
is subject to a borrowing base calculation. The borrowing base is limited to $50
million and is calculated monthly. At June 30, 2006, the borrowing base was $50
million. The total amount available for borrowings at June 30, 2006 was $3.5
million under the working capital portion and $50.0 million under the
acquisition portion of our credit facility.
We must comply with various affirmative and negative covenants
contained in our credit facility. Among other things, those covenants limit our
ability to:
- incur additional indebtedness or liens;
- make payments in respect of or redeem or acquire any debt or equity
issued by us;
- sell assets;
- make loans or investments;
-33-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- extend credit;
- acquire or be acquired by other companies;
- enter into or amend certain existing agreements to the detriment of
the lenders under the credit facility; and
- to maintain physical petroleum inventory for which there is not an
off-setting sale or hedging agreement, subject to specified
exceptions.
Our credit facility covenants also require us to achieve specified
minimum financial metrics. For example, before we may make distributions to our
partners, we must maintain a cash flow coverage ratio of at least 1.1 to 1.0. In
general, this calculation compares operating cash inflows, as adjusted in
accordance with the credit facility, less maintenance capital expenditures, to
the sum of interest expense and distributions. At June 30, 2006, the calculation
resulted in a ratio of 1.5 to 1.0. The credit facility also requires that the
level of operating cash inflows during the prior twelve months, as adjusted in
accordance with the credit facility, be at least $8.5 million. At June 30, 2006,
the result of this calculation was $17.8 million. Our credit facility also
requires that we meet or exceed certain other financial ratios, such as a
current ratio, leverage ratio and funded indebtedness to capitalization ratio.
If we meet these covenants and are not otherwise in default under our credit
facility, we are otherwise not limited by our credit facility in making
distributions to our partners.
The covenants described above could prevent us from engaging in
certain transactions which might otherwise be considered beneficial to us. For
example, they could:
- increase our vulnerability to generally adverse economic and industry
conditions;
- limit our ability to make distributions to unitholders; to fund future
working capital, capital expenditures and other general partnership
requirements; to engage in future acquisitions, construction or
development activities; or to otherwise fully realize the value of our
assets and opportunities because of the need to dedicate a substantial
portion of our cash flow from operations to payments on our
indebtedness or to comply with any restrictive terms of our
indebtedness; and
- limit our flexibility in planning for, or reacting to, changes in our
businesses and the industries in which we operate.
Our credit facility contains customary events of default, including
for non-payment of principal and interest, and failure to comply with any
covenant.
Our average daily outstanding balance under our credit facility during
the first half of 2006 was less than $3 million. The interest rate we paid
during this same period was 8.2%.
Our credit facility is secured by liens on substantially all of our
assets.
-34-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL EXPENDITURES
A summary of our capital expenditures in the six months ended June 30,
2006 and 2005 is as follows:
Six months Ended
June 30,
----------------
2006 2005
------ -------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system ...................... $ 67 $ 93
Mississippi pipeline system ................ 78 566
Jay pipeline system ........................ 79 5
Crude oil gathering assets ................. 85 9
Administrative assets ...................... 71 38
------ -------
Total maintenance capital expenditures .. 380 711
Growth capital expenditures:
Mississippi pipeline system ................ 199 828
Natural gas gathering assets ............... -- 3,110
T&P Syngas Company investment .............. -- 13,418
Sandhill Group, LLC investment ............. 5,037 --
Other investment projects .................. 513 --
Crude oil gathering assets ................. -- 229
------ -------
Total growth capital expenditures ....... 5,749 17,585
------ -------
Total capital expenditures ........... $6,129 $18,296
====== =======
We have no commitments to make capital expenditures; however, we anticipate
that our maintenance capital expenditures for 2006 will total to approximately
$1.3 million. These expenditures are expected to relate primarily to
improvements on our Mississippi System. Maintenance capital expenditures for
2007 are expected to total to approximately $1.9 million. Based on the
information available to us at this time, we do not anticipate that future
capital expenditures for compliance with regulatory requirements will be
material.
Expenditures for capital assets to grow the partnership distribution will
depend on our access to debt and capital discussed below in "Sources of Future
Capital." We are pursuing accretive acquisitions which complement our existing
asset base or are in new areas closely related to our existing businesses such
as the three acquisitions made in 2005 and the investments in 2006 discussed in
"Acquisitions in 2006" above.
Since 2003, our growth strategy has expanded from our historic business
segments of crude oil gathering and marketing and crude oil pipeline operations.
Our operations now include a separate pipeline transportation segment that
includes crude oil, natural gas, and CO(2) pipelines, as well as an industrial
gases segment, which includes a CO(2) business, an investment in a syngas joint
venture, and an investment in a CO(2) processing joint venture. We believe this
diversification of our asset base has contributed to our growth.
Denbury has been a significant source of our growth acquisitions since
becoming our general partner in 2002. While neither our partnership agreement
nor any other agreement requires Denbury to pursue a business strategy that
favors us or utilizes our assets, we continue to believe that there may be
opportunities to acquire assets from Denbury as a consequence of our
relationship with them and our mutual areas of operation. However, we would not
expect Denbury to sell or contribute assets to us unless we complete
acquisitions (purchases and/or construction) independent of Denbury that
generate at least as much cash flow as would be generated by our Denbury
acquisitions.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SOURCES OF FUTURE CAPITAL
Our credit facility provides us with $50 million of capacity for
acquisitions and $15 million for borrowings under the working capital portion.
Both portions of the facility are revolving facilities. At June 30, 2006, we had
$11.5 million outstanding under the working capital facility and no debt
outstanding under the acquisition facility.
We expect to use cash flows from operating activities to fund cash
distributions and maintenance capital expenditures needed to sustain existing
operations. Future acquisitions or capital projects for our expansion will
require funding through borrowings under our credit facility or from proceeds
from equity offerings, or a combination of the two sources of funds.
CASH FLOWS
Our primary sources of cash flows are operations, credit facilities,
and in 2005, proceeds from the sale of idle assets. Our primary uses of cash
flows are capital expenditures and distributions. A summary of our cash flows is
as follows:
Six months Ended
June 30,
------------------
2006 2005
------- --------
(in thousands)
Cash provided by (used in):
Operating activities ...... $(1,544) $ (855)
Investing activities ...... $(5,836) $(16,592)
Financing activities ...... $ 5,997 $ 16,997
Operating. Net cash from operating activities for each period have
been comprised of the following:
Six months Ended
June 30,
------------------
2006 2005
-------- -------
(in thousands)
Net (loss) income ............................... $ 6,035 $ 3,513
Depreciation, amortization and impairment ....... 3,893 3,094
Gain on sales of assets ......................... (49) (671)
Direct financing leases ......................... 261 244
Equity in joint ventures, net of distributions .. 25 (252)
Other non-cash items ............................ 266 (755)
Changes in components of working capital, net ... (11,975) (6,028)
-------- -------
Net cash from operating activities ........... $ (1,544) $ (855)
======== =======
Our operating cash flows are affected significantly by changes in
items of working capital. We have had situations where other parties have
prepaid for purchases or paid more than was due, resulting in fluctuations in
one period as compared to the next until the party recovers the excess payment.
In the 2006 first half, we acquired inventory. The timing of operating
expenditures and the related effect on our recorded liabilities also affects
operating cash flows.
Our accounts receivable settle monthly and collection delays generally
relate only to discrepancies or disputes as to the appropriate price, volume or
quality of crude oil delivered. Of the $101 million aggregate receivables on our
consolidated balance sheet at June 30, 2006, approximately $99.7 million, or
98.7%, were less than 30 days past the invoice date.
Investing. We utilized cash flows to make an investment in a joint
venture and other investments and to make capital expenditures, primarily
related to equipment we installed on our newly leased trucks used in our
gathering operations, and for pipeline improvements.
-36-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Financing. In the first half of 2006, we borrowed $11.5 million under our
credit facility. We also paid distributions to our unitholders and our general
partner totaling $4.9 million. In the prior year period, we increased our
borrowings by $19.1 million and paid distributions totaling $2.9 million.
DISTRIBUTIONS
We are required by our partnership agreement to distribute 100% of our
available cash (as defined therein) 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. We have increased our distribution for each of the last
three quarters, including the distribution to be paid for the second quarter of
2006, as shown in the table below.
Date Per Unit Total
Distribution For Paid or to be Paid Amount Amount (000's)
- ---------------- ------------------ -------- --------------
Fourth quarter 2004 February 2005 $0.15 $1,426
First quarter 2005 May 2005 $0.15 $1,426
Second quarter 2005 August 2005 $0.15 $1,426
Third quarter 2005 November 2005 $0.16 $1,521
Fourth quarter 2005 February 2006 $0.17 $2,391
First quarter 2006 May 2006 $0.18 $2,532
Second quarter 2006 August 2006 $0.19 $2,672
The total amounts in the table above increased with the distribution
for the fourth quarter of 2005 due to the issuance of 4,470,630 new common units
in December 2005.
Our general partner is entitled to receive incentive distributions if
the amount we distribute with respect to any quarter exceeds levels specified in
our partnership agreement. Under the quarterly incentive distribution
provisions, our general partner is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit, and 49% of any distributions in excess of $0.33 per unit,
without duplication. The likelihood and timing of the payment of any incentive
distributions will depend on our ability to increase the cash flow from our
existing operations and to make cash flow accretive acquisitions. In addition,
our partnership agreement authorizes us to issue additional equity interests in
our partnership with such rights, powers and preferences (which may be senior to
our common units) as our general partner may determine in its sole discretion,
including with respect to the right to share in distributions and profits and
losses of the partnership. We have not paid any incentive distributions and do
not expect to make incentive distributions during 2006.
-37-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Available Cash before Reserves for the three and six months ended June
30, 2006 is as follows (in thousands):
Three Six
Months Months
Ended Ended
June 30, June 30,
2006 2006
-------- ---------
(in thousands)
AVAILABLE CASH BEFORE RESERVES:
Net income ............................. $3,444 $ 6,035
Depreciation and amortization .......... 2,029 3,893
Cash received from direct financing
leases not included in income ....... 132 261
Cash effects from certain asset sales .. 1 18
Effects of available cash generated by
investments in joint ventures not
included in net income .............. 420 700
Net non-cash (credits) charges ......... 222 575
Maintenance capital expenditures ....... (161) (380)
------ -------
Available Cash before reserves ......... $6,087 $11,102
====== =======
We have reconciled Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the three and six
months ended June 30, 2006 below. For the three months ended June 30, 2006, cash
flows provided by operating activities were $0.8 million, and for the six months
ended June 30, 2006, cash flows utilized in operating activities were $1.5
million.
NON-GAAP FINANCIAL MEASURE
This quarterly report includes the financial measure of Available
Cash, which measure often is referred to as 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. 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, also referred to as discretionary 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
opportunities. Because Available Cash excludes some, but not all, items that
affect net income or loss and because these measures may vary among other
companies, the Available Cash 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 is net cash provided by
operating activities.
Available Cash is a liquidity measure used by our management to
compare cash flows generated by us to the cash distribution paid to our limited
partners and general partner. 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
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
distributable cash flow) is the quantitative standard used throughout the
investment community with respect to publicly-traded partnerships.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the three and six
months ended June 30, 2006, is as follows (in thousands):
Three Six
Months Months
Ended Ended
June 30, June 30,
2006 2006
-------- --------
(in thousands)
Cash flows from operating activities ................................... $ 753 $(1,544)
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures .................................... (161) (380)
Proceeds from sales of certain assets ............................... -- 67
Amortization of credit facility issuance fees ....................... (94) (186)
Cash effects of stock appreciation rights plan ...................... (11) (29)
Effects of available cash generated by joint ventures not included in
cash flows from operating activities ............................. 317 675
Unrealized gains on fair value hedges ............................... 524 524
Net effect of changes in working capital accounts not included in
calculation of Available Cash .................................... 4,759 11,975
------ -------
Available Cash before reserves ......................................... $6,087 $11,102
====== =======
COMMITMENTS AND OFF-BALANCE-SHEET ARRANGEMENTS
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed under Contractual Obligation
and Commercial Commitments below, nor do we have any debt or equity triggers
based upon our unit or commodity prices.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
In addition to the Credit Facility discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes our obligations and commitments
at June 30, 2006.
Payments Due by Period
------------------------------------------------------
Less than After
Contractual Cash Obligations 1 Year 1-3 Years 4-5 Years 5 Years Total
- ---------------------------- --------- --------- --------- ------- --------
(in thousands)
Long-term Debt .......................... $ -- $11,500 $ -- $ -- $ 11,500
Interest Payments (1) ................... 978 900 -- -- 1,878
Other investment projects (2) ........... 500 -- -- -- 500
Operating Lease Obligations ............. 2,876 4,527 2,018 267 9,688
Unconditional Purchase Obligations (3) .. 163,454 49,981 -- -- 213,435
-------- ------- ------ ---- --------
Total Contractual Cash Obligations ...... $167,808 $66,908 $2,018 $267 $237,001
======== ======= ====== ==== ========
(1) Interest on our long-term debt is at market-based rates. Amount shown for
interest payments represents interest that would be paid if the debt
outstanding at June 30, 2006 remained outstanding through the maturity date
of June 1, 2008 and interest
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
rates remained at the June 30, 2006 market levels through June 1, 2008.
Actual obligations may differ from the amounts included above.
(2) We invested $0.5 million in a potential investment project in the second
quarter of 2006, and have made a commitment to invest an additional $0.5
million within the next year. See additional discussion in the Other
Projects section of Note 3 to the consolidated financial statements.
(3) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at June 30, 2006, were used to value the obligations.
Actual obligations may differ from the amounts included above.
In additional to the contractual cash obligations included above, we
also have a contingent obligation related to our acquisition of a 50% interest
in Sandhill, which could require us to pay an additional $2 million for our
interest. See additional discussion in the section on Sandhill in Note 3 to the
consolidated financial statements.
We have guaranteed 50% of the $4.7 million debt obligation to a bank
of Sandhill; however, we believe we are not likely to be required to perform
under this guarantee as Sandhill is expected to make all required payments under
the debt obligation. See additional discussion in the section on Sandhill in
Note 3 to the consolidated financial statements.
NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS
See discussion of new accounting pronouncements in Note 2, "New
Accounting Pronouncements" in the accompanying consolidated financial
statements.
FORWARD LOOKING STATEMENTS
The statements in this Quarterly Report on Form 10-Q that are not
historical information may be "forward looking statements" within the meaning of
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. 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," "intend," "may," "plan," "position," "projection," "strategy" 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:
- demand for, the supply of, changes in forecast data for, and price
trends related to crude oil, liquid petroleum, natural gas and natural
gas liquids or "NGLs" in the United States, 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 consummate strategic
acquisitions, make cost saving changes in operations and integrate
acquired assets or businesses into our existing operations;
- service interruptions in our liquids transportation systems, natural
gas transportation systems or natural gas gathering and processing
operations;
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF 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;
- changes in laws or regulations to which we are subject;
- our inability to borrow or otherwise access funds needed for
operations, expansions or capital expenditures as a result of existing
debt agreements that contain restrictive financial covenants;
- loss of key personnel;
- the effects of competition, in particular, by other pipeline systems;
- hazards and operating risks that may not be covered fully by
insurance;
- the condition of the capital markets in the United States;
- loss of key customers;
- the political and economic stability of the oil producing nations of
the world; and
- general economic conditions, including rates of inflation and interest
rates.
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, 2005. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks primarily related to volatility in crude oil
prices and interest rates.
Our primary price risk relates to the effect of crude oil price
fluctuations on our inventories and the fluctuations each month in grade and
location differentials and their effect on future contractual commitments. We
utilize NYMEX commodity based futures contracts and forward contracts to hedge
our exposure to these market price fluctuations as needed. At June 30, 2006, we
had entered into NYMEX futures contracts that will settle through September
2006. These contracts either do not qualify for hedge accounting or are fair
value hedges, therefore the fair value of these derivatives have received
mark-to-market treatment in current earnings. This accounting treatment is
discussed further under Note 2 "Summary of Significant Accounting Policies" of
our Consolidated Financial Statements in our Annual Report on Form 10-K.
Sell (Short) Buy (Long)
Contracts Contracts
------------ ----------
Futures Contracts
Contract volumes (1,000 bbls) ........... 176 64
Weighted average price per bbl .......... $ 71.23 $71.10
Contract value (in thousands) ........... $12,537 $4,551
Mark-to-market change (in thousands) .... 532 181
------- ------
Market settlement value (in thousands) .. $13,069 $4,732
======= ======
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount and total fair value amount in U.S.
dollars. Fair values were determined by using the notional amount in barrels
multiplied by the June 30, 2006 quoted market prices on the NYMEX.
We are also exposed to market risks due to the floating interest rates on
our credit facility. Our debt bears interest at the LIBOR or prime rate plus the
applicable margin. We do not hedge our interest rates. The average interest rate
presented below is based upon rates in effect at June 30, 2006. The carrying
value of our debt in our credit facility approximates fair value primarily
because interest rates fluctuate with prevailing market rates, and the credit
spread on outstanding borrowings reflects market.
Expected Year
Of Maturity
2008
(in thousands)
--------------
Long-term debt - variable rate 11,500
Average interest rate 8.5%
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 adequate and effective in all material respects in providing to
them on a timely basis material information relating to us (including our
consolidated subsidiaries) required to be disclosed in this quarterly report.
There were no changes during our last fiscal quarter that materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See Part I. Item 1. Note 11 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
ITEM 1A. RISK FACTORS.
There have been no material changes to the risk factors previously
disclosed in our Annual Report on Form 10-K for the year ended December 31,
2005.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 5. OTHER INFORMATION.
None.
ITEM 6. EXHIBITS.
(a) Exhibits.
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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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.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: August 7, 2006 By: /s/ ROSS A. BENAVIDES
------------------------------------
Ross A. Benavides
Chief Financial Officer
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Index to Exhibits
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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