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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
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 Identification No.)
incorporation or organization)
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
------ ------
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This report contains 18 pages
1
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - September 30, 1999 and
December 31, 1998 3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 1999 and 1998 4
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 1999 and 1998 5
Consolidated Statement of Partners' Capital for the Nine
Months Ended September 30, 1999 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 12
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 17
Item 6. Exhibits and Reports on Form 8-K 17
2
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
September 30, December 31,
1999 1998
-------- --------
Assets (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 2,436 $ 7,710
Accounts receivable -
Trade 243,636 167,600
Related party 4,666 4,634
Inventories 1,311 1,966
Other 7,180 3,306
-------- --------
Total current assets 259,229 185,216
FIXED ASSETS, at cost 118,839 119,310
Less: Accumulated depreciation (23,839) (20,707)
-------- --------
Net fixed assets 95,000 98,603
OTHER ASSETS, net of amortization 12,299 13,354
-------- --------
TOTAL ASSETS $366,528 $297,173
======== ========
Liabilities and Partners' Capital
CURRENT LIABILITIES
Current debt $22,100 $ -
Accounts payable -
Trade 248,424 172,143
Related party 2,096 6,200
Accrued liabilities 4,809 5,171
-------- --------
Total current liabilities 277,429 183,514
LONG-TERM DEBT - 15,800
COMMITMENTS AND CONTINGENCIES (Note 9)
MINORITY INTERESTS 30,530 29,988
ADDITIONAL PARTNERSHIP INTERESTS 1,700 -
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued;
8,604 units outstanding 56,051 66,832
General partner 1,136 1,357
-------- --------
Subtotal 57,187 68,189
Treasury units, 21 units (318) (318)
-------- --------
Total partners' capital 56,869 67,871
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $366,528 $297,173
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
3
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
-------- -------- ---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $575,381 $516,353 $1,429,158 $1,701,582
Related parties 14,229 6,260 49,121 24,726
Pipeline revenues 4,207 3,829 12,649 12,204
-------- -------- ---------- ----------
Total revenues 593,817 526,442 1,490,928 1,738,512
COST OF SALES:
Crude costs unrelated parties 573,383 500,199 1,406,587 1,674,175
Crude costs related parties 10,028 12,707 52,301 27,519
Field operating costs 2,845 3,289 8,455 10,293
Pipeline operating costs 2,100 1,815 6,034 5,710
-------- -------- ---------- ----------
Total cost of sales 588,356 518,010 1,473,377 1,717,697
-------- -------- ---------- ----------
GROSS MARGIN 5,461 8,432 17,551 20,815
EXPENSES:
General and administrative 2,740 3,078 8,779 8,599
Depreciation and amortization 2,054 1,989 6,166 5,627
Nonrecurring charge (Note 6) - - - 373
-------- -------- ---------- ----------
OPERATING INCOME 667 3,365 2,606 6,216
OTHER INCOME (EXPENSE):
Interest income 38 70 107 375
Interest expense (333) (84) (849) (99)
Gain (loss) on asset sales (55) (24) 845 8
-------- -------- ---------- ----------
NET INCOME BEFORE MINORITY INTERESTS 317 3,327 2,709 6,500
Minority interests 63 665 542 1,299
-------- -------- ---------- ----------
NET INCOME $ 254 $ 2,662 $ 2,167 $ 5,201
======== ======== ========== ==========
NET INCOME PER COMMON UNIT - BASIC AND
DILUTED $ 0.03 $ 0.30 $ 0.25 $ 0.59
======== ======== ========== ==========
NUMBER OF COMMON UNITS OUTSTANDING 8,604 8,617 8,604 8,622
======== ======== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended September 30,
1999 1998
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,167 $ 5,201
Adjustments to reconcile net income to net cash
provided by (used in) operating activities -
Depreciation 5,114 4,811
Amortization of intangible assets 1,052 816
Minority interests equity in earnings 542 1,299
(Gain) loss on disposals of fixed assets (845) 256
Other noncash charges 1,119 1,233
Changes in components of working capital -
Accounts receivable (76,068) 8,120
Inventories 655 901
Other current assets (3,874) (729)
Accounts payable 72,177 (17,108)
Accrued liabilities (1,481) (1,756)
-------- --------
Net cash provided by operating activities 558 3,044
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (2,086) (12,312)
Decrease (increase) in other assets 415 (4,261)
Proceeds from sales of assets 1,008 188
-------- --------
Net cash used in investing activities (663) (16,385)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Loan Agreement 6,300 18,600
Distributions:
To common unitholders (12,905) (12,938)
To general partner (264) (264)
Issuance of Additional Partnership Interests 1,700 -
Purchase of common units for treasury - (972)
-------- --------
Net cash (used in) provided by financing activities (5,169) 4,426
-------- --------
Net decrease in cash and cash equivalents (5,274) (8,915)
Cash and cash equivalents at beginning of period 7,710 11,812
-------- --------
Cash and cash equivalents at end of period $ 2,436 $ 2,897
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
-------------------------------------
Common General Treasury
Unitholders Partner Units Total
------- ------ ----- -------
Partners' capital at December 31, 1998 $66,832 $1,357 $(318) $67,871
Net income for the nine months ended September 30, 1999 2,124 43 - 2,167
Distributions during the nine months ended September 30, 1999 (12,905) (264) - (13,169)
------- ------ ----- -------
Partners' capital at September 30, 1999 $56,051 $1,136 $(318) $56,869
======= ====== ===== =======
The accompanying notes are an integral part of these consolidated financial
statements.
6
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP") completed an initial public
offering of 8.6 million Common Units at $20.625 per unit, representing limited
partner interests in GELP of 98%. Genesis Energy, L.L.C. (the "General
Partner") serves as general partner of GELP and its operating limited
partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P. has two subsidiary
partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P.
Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to
collectively as GCOLP. The General Partner owns a 2% general partner interest
in GELP.
Transactions at Formation
At the closing of the offering, GELP contributed the net proceeds of the
offering to GCOLP in exchange for an 80.01% general partner interest in GCOLP.
With the net proceeds of the offering, GCOLP purchased a portion of the crude
oil gathering, marketing and pipeline operations of Howell Corporation
("Howell") and made a distribution to Basis Petroleum, Inc. ("Basis") in
exchange for its conveyance of a portion of its crude oil gathering and
marketing operations. GCOLP issued an aggregate of 2.2 million subordinated
limited partner units ("Subordinated OLP Units") to Basis and Howell to obtain
the remaining operations. Basis' Subordinated OLP units were transferred to its
then parent, Salomon Smith Barney Holdings Inc. ("Salomon") in May 1997.
Unless the context otherwise requires, the term "the Partnership" hereafter
refers to GELP and its operating limited partnership.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of September 30, 1999 and December 31, 1998
for GELP and its results of operations, cash flows and changes in partners'
capital for the three and nine months ended September 30, 1999 and 1998.
The financial statements included herein have been prepared by the
Partnership 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, the Partnership believes 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 the Partnership's Annual Report on Form 10-K for the year
ended December 31, 1998 filed with the SEC.
Basic net income per Common Unit is calculated on the number of outstanding
Common Units. The weighted average number of Common Units outstanding for the
three months ended September 30, 1999 and 1998 was 8,604,000 and 8,625,000,
respectively. For the 1999 and 1998 nine month periods, the weighted average
number of Common Units outstanding was 8,604,000 and 8,625,000, respectively.
For this purpose, the 2% General Partner interest is excluded from net income.
Diluted net income per Common Unit did not differ from basic net income per
Common Unit for either period presented.
3. Adoption of Accounting Standards
In November 1998, the Emerging Issues Task Force (EITF) reached a consensus
on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities". This consensus, effective in the first quarter of 1999, requires
that "energy trading" contracts be marked-to-market, with gains or losses
recognized in current earnings. The Partnership has determined that its
activities do not meet the definition in EITF Issue 98-10 of "energy trading"
activities and, therefore, is not required to make any change in its accounting.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This standard was subsequently amended by SFAS 137.
This new standard, which the Partnership will be required to adopt for its
fiscal year 2001, will change the method of accounting for changes in the fair
value of certain
7
derivative instruments by requiring that an entity recognize the derivative
at fair value as an asset or liability on its balance sheet. Depending on the
purpose of the derivative and the item it is hedging, the changes in fair value
of the derivative will be recognized in current earnings or as a component of
other comprehensive income in partners' capital. The Partnership is in the
process of evaluating the impact that this statement will have on its results of
operations and financial position. This new standard could increase volatility
in net income and comprehensive income.
4. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering, transportation and marketing
of crude oil, and it currently reports its operations, both internally and
externally, as a single business segment. No customer accounted for more than
10% of the Partnership's revenues in any period.
5. Credit Resources
GCOLP entered into credit facilities with Salomon (collectively, the "Credit
Facilities"), pursuant to a Master Credit Support Agreement. GCOLP's
obligations under the Credit Facilities are secured by its receivables,
inventories, general intangibles and cash.
Guaranty Facility
Salomon is providing a Guaranty Facility through December 31, 2000 in
connection with the purchase, sale and exchange of crude oil by GCOLP. The
aggregate amount of the Guaranty Facility is limited to $300 million (to be
reduced in each case by the amount of any obligation to a third party to the
extent that such third party has a prior security interest in the collateral).
GCOLP pays a guarantee fee to Salomon which will increase after June 2000,
thereby increasing the cost of the credit support provided to GCOLP under the
Guaranty Facility. At September 30, 1999, the aggregate amount of obligations
covered by guarantees was $153 million, including $95 million in payable
obligations and $58 million of estimated crude oil purchase obligations for
October 1999.
The Master Credit Support Agreement contains various restrictive and
affirmative covenants including (i) restrictions on indebtedness other than (a)
pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as
defined in the Master Credit Support Agreement) entered into in the ordinary
course of business and (c) indebtedness incurred in the ordinary course of
business by acquiring and holding receivables to be collected in accordance with
customary trade terms, (ii) restrictions on certain liens, investments,
guarantees, loans, advances, lines of business, acquisitions, mergers,
consolidations and sales of assets and (iii) compliance with certain risk
management policies, audit and receivable risk exposure practices and cash
management practices as may from time to time be revised or altered by Salomon
in its sole discretion.
Pursuant to the Master Credit Support Agreement, GCOLP is required to
maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b)
Consolidated Working Capital of not less than $1 million, (c) a ratio of its
Consolidated Current Liabilities to Consolidated Working Capital plus net
property, plant and equipment of not more than 7.5 to 1, (d) a ratio of
Consolidated Earnings before Interest, Taxes, Depreciation and Amortization to
Consolidated Fixed Charges of at least 1.75 to 1 as of the last day of each
fiscal quarter prior to December 31, 1999 and (e) a ratio of Consolidated Total
Liabilities to Consolidated Tangible Net Worth of not more than 10.0 to 1 (as
such terms are defined in the Master Credit Support Agreement).
An Event of Default could result in the termination of the Credit
Facilities at the discretion of Salomon. Significant Events of Default include
(a) a default in the payment of (i) any principal on any payment obligation
under the Credit Facilities when due or (ii) interest or fees or other amounts
within two business days of the due date, (b) the guaranty exposure amount
exceeding the maximum credit support amount for two consecutive calendar months,
(c) failure to perform or otherwise comply with any covenants contained in the
Master Credit Support Agreement if such failure continues unremedied for a
period of 30 days after written notice thereof and (d) a material
misrepresentation in connection with any loan, letter of credit or guarantee
issued under the Credit Facilities. Removal of the General Partner will result
in the termination of the Credit Facilities and the release of all of Salomon's
obligations thereunder.
8
There can be no assurance of the availability or the terms of credit for
the Partnership. If the General Partner is removed without its consent,
Salomon's credit support obligations will terminate. In addition, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions. Management of the Partnership
intends to replace the Guaranty Facility with a letter of credit facility with
one or more third party lenders prior to December 2000 and has had preliminary
discussions with banks about a replacement letter of credit facility. The
General Partner may be required to reduce or restrict the Partnership's
gathering and marketing activities because of limitations on its ability to
obtain credit support and financing for its working capital needs. The General
Partner expects that the overall cost of a replacement facility may be
substantially greater than what the Partnership is incurring under its existing
Master Credit Support Agreement. Any significant decrease in the Partnership's
financial strength, regardless of the reason for such decrease, may increase the
number of transactions requiring letters of credit or other financial support,
make it more difficult for the Partnership to obtain such letters of credit,
and/or may increase the cost of obtaining them. This situation could in turn
adversely affect the Partnership's ability to maintain or increase the level of
its purchasing and marketing activities or otherwise adversely affect the
Partnership's profitability and Available Cash.
Working Capital Facility
In August 1998, GCOLP entered into a revolving credit/loan agreement ("Loan
Agreement") with Bank One, Texas, N.A. ("Bank One"). The Loan Agreement
provides for loans or letters of credit in the aggregate not to exceed the
greater of $35 million or the Borrowing Base (as defined in the Loan Agreement).
Loans will bear interest at a rate chosen by GCOLP which would be one or more of
the following: (a) a Floating Base Rate (as defined in the Loan Agreement) that
is generally the prevailing prime rate less one percent; (b) a rate based on the
Federal Funds Rate plus one and one-half percent or (c) a rate based on LIBOR
plus one and one-quarter percent. The Loan Agreement provides for a revolving
period until August 14, 2000, with interest to be paid monthly. All loans
outstanding on August 14, 2000, are due at that time.
The Loan Agreement is collateralized by the accounts receivable and
inventory of GCOLP, subject to the terms of an Intercreditor Agreement between
Bank One and Salomon. A commitment fee of 0.35% on the available portion of the
commitment is provided for in the agreement. Material covenants and
restrictions include requirements to maintain a ratio of current assets to
current liabilities of at least 1:1 and to maintain tangible net worth in GCOLP,
as defined in the Loan Agreement, of $65 million.
At September 30, 1999, the Partnership had $22.1 million of loans
outstanding under the Loan Agreement. The Partnership had no letters of credit
outstanding at September 30, 1999. At September 30, 1999, $12.9 million was
available to be borrowed under the Loan Agreement.
Prior to August 15, 1999, the loan outstanding under the Loan Agreement was
reflected on the balance sheet as Long-Term Debt. Since the term of the Loan
Agreement expires within one year, the loan outstanding under the Loan Agreement
is reflected on the balance sheet under Current Liabilities. There can be no
assurances of the availability or terms of credit to the Partnership after the
Loan Agreement expires in August 2000. The Partnership is in discussions with
banks regarding a replacement of the Loan Agreement.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.)
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to purchase
APIs will end no later than
9
December 31, 2001 or until the $17.6 distribution support is fully
utilized, whichever occurs sooner. APIs purchased by Salomon are not entitled
to cash distributions or voting rights. The APIs will be redeemed if and to the
extent that Available Cash for any future quarter exceeds an amount necessary to
distribute the MQD on all Common Units and Subordinated OLP Units and to
eliminate any arrearages in the MQD on Common Units for prior periods. At
September 30, 1999, APIs totaling $1.7 million had been purchased by Salomon
pursuant to the Distribution Support Agreement. Salomon will purchase
additional APIs totaling $2.2 million in November 1999 to provide cash
distribution support for the distribution to be paid on November 15, 1999.
After the third quarter distribution, $3.9 million of distribution support has
been utilized and $13.7 million remains available through December 31, 2001, or
until such amount is fully utilized whichever occurs sooner. In addition, the
Partnership Agreement authorizes the General Partner to cause GCOLP 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
GCOLP needs.
6. Nonrecurring Charge
In the second quarter of 1998, the Partnership shut-in its Main Pass
pipeline. A charge of $373,000 was recorded, consisting of $109,000 of costs
related to the shut-in and a non-cash write-down of the asset of $264,000.
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
those conducted with unaffiliated parties.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is as
follows (in thousands).
Nine Months Nine Months
Ended Ended
September 30, September 30,
1999 1998
------------ -------------
Sales to affiliates $ 49,121 $ 24,726
Purchases from affiliates $ 52,301 $ 27,519
General and Administrative Services
The Partnership does not directly employ any persons to manage or operate
its business. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs of
these services. Total costs reimbursed to the General Partner by the
Partnership were $12,262,000 and $11,629,000 for the nine months ended September
30, 1999 and 1998, respectively.
Credit Facilities
As discussed in Note 5, Salomon provides Credit Facilities to the
Partnership. For the nine months ended September 30, 1999 and 1998, the
Partnership paid Salomon $483,000 and $462,000, respectively, for guarantee fees
under the Credit Facilities. The Partnership paid Salomon $18,000 for interest
under the Credit Facilities during the nine months ended September 30, 1998.
Additional Partnership Interests
As discussed in Note 5, Salomon purchased APIs totaling $1.7 million in
August 1999.
8. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $103,000 and $378,000 for
the nine months ended September 30, 1999 and 1998, respectively. Payments of
interest were $820,000 and $127,000 for the nine months ended September 30, 1999
and 1998, respectively.
10
9. Contingencies
The Partnership is subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance. The Partnership's
management has made an assessment of its potential environmental exposure and
determined that such exposure is not material to its consolidated financial
position, results of operations or cash flows. As part of the formation of the
Partnership, Basis and Howell agreed to be responsible for certain environmental
conditions related to their ownership and operation of their respective assets
contributed to the Partnership and for any environmental liabilities which Basis
or Howell may have assumed from prior owners of these assets.
The Partnership is subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on the financial
position, results of operations or cash flows of the Partnership.
As part of the formation of the Partnership, Basis and Howell agreed to each
retain liability and responsibility for the defense of any future lawsuits
arising out of activities conducted by Basis and Howell prior to the formation
of the Partnership and have also agreed to cooperate in the defense of such
lawsuits.
10. Distributions
On October 19, 1999, the Board of Directors of the General Partner declared a
cash distribution of $0.50 per Unit for the quarter ended September 30, 1999.
The distribution will be paid November 15, 1999, to the General Partner and all
Common Unitholders of record as of the close of business on October 29, 1999.
The Subordinated OLP Unitholders will not receive a distribution for the
quarter.
The distribution will be paid utilizing approximately $2.2 million of cash
available from the Partnership and $2.2 million of cash provided by Salomon
pursuant to Salomon's Distribution Support Agreement.
11
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Genesis Energy, L.P., operates crude oil common carrier pipelines and is one
of the largest independent gatherers and marketers of crude oil in North
America, with operations concentrated in Texas, Louisiana, Alabama, Florida,
Mississippi, New Mexico, Kansas and Oklahoma. The following review of the
results of operations and financial condition should be read in conjunction with
the Condensed Consolidated Financial Statements and Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except barrels per day.
Three Months Ended September 30, Nine Months Ended September 30,
1999 1998 1999 1998
-------- -------- -------- --------
Gross margin
Gathering and marketing $ 3,354 $ 6,418 $ 10,936 $ 14,321
Pipeline $ 2,107 $ 2,014 $ 6,615 $ 6,494
General and administrative expenses $ 2,740 $ 3,078 $ 8,779 $ 8,599
Depreciation and amortization $ 2,054 $ 1,989 $ 6,166 $ 5,627
Operating income $ 667 $ 3,365 $ 2,606 $ 6,216
Interest income (expense), net $ (295) $ (14) $ (742) $ 276
Barrels per day
Wellhead 97,357 113,097 91,572 116,641
Bulk and exchange 224,957 319,857 253,504 327,630
Pipeline 100,383 77,899 94,951 84,015
Gross margin from gathering and marketing operations is generated by the
difference between the price of crude oil at the point of purchase and the price
of crude oil at the point of sale, minus the associated costs of aggregation and
transportation. The absolute price levels of crude oil do not necessarily bear
a relationship to gross margin, although such price levels significantly impact
revenues and cost of sales. As a result, period-to-period variations in
revenues and cost of sales are generally not meaningful in analyzing the
variation in gross margin. Such changes are not addressed in the following
discussion.
Pipeline gross margins are primarily a function of the level of throughput
and storage activity and are generated by the difference between the regulated
published tariff and the fixed and variable costs of operating the pipeline.
Changes in revenues, volumes and pipeline operating costs, therefore, are
relevant to the analysis of financial results of the Partnership's pipeline
operations.
Nine Months Ended September 30, 1999 Compared with Nine Months Ended
September 30, 1998
Gross margin from gathering and marketing operations was $11.0 million for
the nine months ended September 30, 1999, as compared to $14.3 million for the
nine months ended September 30, 1998. Crude oil production and drilling for new
production by oil producers was significantly impacted beginning in late 1998 by
the decline in crude oil prices. Although crude oil prices have risen in the
second and third quarters of 1999, production and drilling in areas that the
Partnership serves remain low as oil producers have not yet increased their
drilling activities. While average daily wellhead volumes declined by 21% from
1998 to 1999, the Partnership experienced a 10% increase in daily wellhead
volumes between the second and third quarters of 1999. Additionally, the
partnership applied risk management techniques during the nine months ended in
September 30, 1998 to lock in opportunities for favorable margins. The
opportunities to lock in such favorable margins were not available to the same
extent during the nine months ended September 30, 1999.
12
In addition, effective in January 1999, the Partnership lost a large
contract with a producer, resulting in a volume decline of approximately 21,000
barrels per day. This decline in volumes did not have a material impact on
gross margin due to the profit sharing nature of the contract.
Pipeline gross margin was $6.6 million for the nine months ended September
30, 1999, as compared to pipeline gross margin of $6.5 million for the first
nine months of 1998. Pipeline gross margin for the nine months ended September
30, 1999 was favorably impacted compared to 1998 by the acquisition from Equilon
Pipeline Company, L.L.C. of the West Columbia System on September 30, 1998. In
addition, revenues in the 1999 period include tank storage fees of $0.9 million.
Tank storage fees are not expected to continue after the third quarter.
Pipeline operating costs increased $0.3 million in the 1999 nine-month period
over the 1998 period due to increased expenditures primarily in areas of spill
prevention.
General and administrative expenses were $8.8 million for the nine months
ended September 30, 1999, as compared to $8.6 million for the 1998 period. The
increase in 1999 can be attributed primarily to expenditures associated with
Year 2000 remediation.
Depreciation and amortization increased $0.6 million from the 1998 period
to $6.2 million for the 1999 nine month period, primarily attributable to
depreciation on assets acquired from Falco S & D, Inc. during the second quarter
of 1998.
In the 1998 period, the Partnership recorded a nonrecurring charge of $0.4
million as a result of the shut-in of its Main Pass pipeline. The charge
consisted of $0.1 million of costs related to the shut-in and a $0.3 million
write-down of the asset.
Net interest expense for the nine months ended September 30, 1999 was $0.7
million. In the 1998 period, the Partnership received net interest income of
$0.3 million. The increase in interest cost in 1999 was due primarily to an
increase in debt throughout 1998 as a result of the acquisition of assets.
In the 1999 period, the Partnership sold excess trucking assets, resulting
in the recognition of a gain on those sales of $0.9 million.
Three Months Ended September 30, 1999 Compared with Three Months Ended
September 30, 1998
Gross margin from gathering and marketing operations was $3.4 million for
the three months ended September 30, 1999, as compared to $6.4 million for the
three months ended September 30, 1998. The Partnership applied risk management
techniques during the three months ended September 30, 1998 to lock in
opportunities for favorable margins. The opportunities to lock in such
favorable margins were not available to the same degree during the three months
ended September 30, 1999. Crude oil production and drilling for new production
by oil producers was significantly impacted beginning in late 1998 by a decline
in crude oil prices. Although crude oil prices have risen in the second and
third quarters of 1999, production and drilling in areas that the Partnership
serves remain low as oil producers have not yet increased their drilling
activities.
Pipeline gross margin increased $0.1 million between the 1998 and 1999
third quarters. Pipeline gross margin for the three months ended September 30,
1999 was favorably impacted relative to 1998 by the acquisition of the West
Columbia System. In addition, the third quarter of 1999 included $0.2 million
of storage fee income. Pipeline costs increased in the 1999 third quarter due
to increased spill prevention expenditures.
General and administrative expenses decreased $0.3 million between the 1999
and 1998 quarters. The 1998 period included $0.2 million recorded for severance
pay.
Net interest expense increased by $0.3 million in the 1999 third quarter
due to higher debt levels resulting from capital expenditures in 1998 and
slightly higher interest rates.
13
Liquidity and Capital Resources
Cash Flows
Cash flows from operating activities were $0.6 million for the nine months
ended September 30, 1999. Operating activities in the prior year period
generated cash of $3.0 million. The decline in 1999 can be attributed to the
decline in gross margin discussed above.
For the nine months ended September 30, 1999, cash flows utilized in
investing activities were $0.7 million resulting from additions to property and
equipment, offset by the proceeds from the sale of excess trucking equipment.
In the 1998 period, the Partnership expended $16.4 million on asset
acquisitions.
Cash flows utilized in financing activities by the Partnership during the
first nine months of 1999 totaled $5.2 million. Distributions paid to the
common unitholders and the general partner totaling $13.2 million utilized cash
flows. Borrowings under the Loan Agreement of $6.3 million provided financing
cash flows and $1.7 million was provided by the issuance of Additional
Partnership Interests (APIs) to Salomon under the terms of the Distribution
Support Agreement. Cash flows provided by financing activities of $4.4 million
in the 1998 period represented distributions to the common unitholders and the
general partner and the purchase of 66,000 Common Units on the open market,
offset by increased borrowings under the Loan Agreement.
Working Capital and Credit Resources
As discussed in Note 5 of the Notes to Condensed Consolidated Financial
Statements, the Partnership has a Guaranty Facility with Salomon through
December 31, 2000 and a Loan Agreement with Bank One for working capital
purposes that extends through August 2000. If the General Partner is removed
without its consent, Salomon's credit support obligations will terminate. In
addition, Salomon's obligations under the Master Credit Support Agreement may be
transferred or terminated early subject to certain conditions. Management of
the Partnership intends to replace the Guaranty Facility with a letter of credit
facility with one or more third party lenders prior to December 2000. The
General Partner expects that the overall cost of a replacement facility may be
substantially greater than what the Partnership is incurring under its existing
Master Credit Support Agreement. Any significant decrease in the Partnership's
financial strength, regardless of the reason for such decrease, may increase the
number of transactions requiring letters of credit or other financial support,
make it more difficult for the Partnership to obtain such letters of credit,
and/or may increase the cost of obtaining them. This situation could in turn
adversely affect the Partnership's ability to maintain or increase the level of
its purchasing and marketing activities or otherwise adversely affect the
Partnership's profitability and Available Cash.
MQD is $0.50 per Unit with respect to each quarter. The Partnership will
pay a distribution of $0.50 per Unit for the three months ended September 30,
1999 on November 15, 1999 to the General Partner and all Common Unitholders of
record as of the close of business on October 29, 1999. The subordinated OLP
Unitholders will not receive a distribution for that period. Salomon has
committed, subject to certain limitations, to provide total cash distribution
support, with respect to quarters ending on or before December 31, 2001, in an
amount up to an aggregate of $17.6 million in exchange for APIs. At September
30, 1999, $1.7 million of the distribution support had been utilized, and an
additional $2.2 million will be utilized in connection with the distribution for
the third quarter of 1999. The Partnership anticipates that it will be required
to use some level of distribution support from Salomon for the next several
quarters to meet the MQD. After the distribution for the third quarter of 1999,
distribution support in the amount of $13.9 million remains available to the
Partnership. The APIs received by Salomon in exchange for this distribution
support are not entitled to voting rights or cash distributions. The APIs are
required to be redeemed if and to the extent that Available Cash for any future
quarter exceeds an amount necessary to distribute the MQD on all Common Units
and Subordinated OLP Units and to eliminate any arrearages in the MQD on Common
Units for prior periods.
Year 2000 Issue
Many software applications, equipment and embedded chip systems identify
dates using only the last two digits of the year. These systems may be unable
to distinguish between dates in the year 2000 and the year 1900. If not
addressed, this condition could cause such systems to fail or provide incorrect
information when using dates
14
after December 31, 1999. Due to the Partnership's dependence on such
systems, this condition could have an adverse effect on the Partnership.
Partnership's State of Readiness
To address the Year 2000 issue, the Partnership has formed a Year 2000
Steering Committee to coordinate execution of a project to identify, assess and
remedy any critical Year 2000 issues that might impact the Partnership ("Year
2000 Project" or "the Project"). The Year 2000 Project Steering Committee has
established six phases for the Project. The six phases include (i) awareness,
(ii) inventory, (iii) assessment, (iv) remediation, (v) testing and (vi)
implementation. The Year 2000 Steering Committee has classified the key
automated systems for analysis as (a) financial systems applications, (b)
operational system applications, (c) hardware and equipment, (d) embedded chip
systems and (e) third-party systems. The Year 2000 Project includes addressing
the Year 2000 exposure of third parties whose operations are material to the
operations of the Partnership. The Partnership has retained a Year 2000
consulting firm to review the Partnership's Year 2000 Project Plan, execution of
that Plan and associated contingency plans. The Year 2000 consulting firm
reports its findings to the Year 2000 Steering Committee periodically. The
status of the Year 2000 Project is reviewed with the Board of Directors at its
quarterly meetings.
The awareness phase of the Year 2000 project consists of an enterprise-wide
awareness program to communicate to employees and other stakeholders the Year
2000 problems, the issues affecting the Partnership and the processes to be
applied to the Project and to solicit participation to enhance the likelihood of
success of this Project. The initial awareness phase activities have been
completed; however, activities associated with the awareness phase will continue
throughout the course of the Project.
The inventory phase entails identifying all software applications,
equipment, embedded chip systems and third-party systems that should be
evaluated as part of this Project. All applications, equipment and systems have
been identified for evaluation. Due to the dynamic nature of systems in the
operations of the Partnership, the identification phase will be updated and
reassessed throughout the course of the Project. A Year 2000 Change Management
Program has been developed to monitor and control system changes that could
affect the Partnership's Year 2000 Project.
The assessment phase includes analysis and testing of inventoried
applications, equipment and systems to determine the business impact,
probability of failure and identification of the proper course of action to
achieve Year 2000 compliance. All systems have been analyzed to determine the
business impact of failure. All critical applications, equipment and systems
have been assessed as to the probability of failure. The determination of the
proper course of action for all critical applications, equipment and systems
that are not yet compliant is substantially complete.
The assessment phase of the project includes reasonable efforts to obtain
representation and assurances from third parties that their applications,
hardware and equipment, and systems being used by or impacting the Partnership
are or will be modified to be Year 2000 compliant. To date, the responses from
such third parties are positive but inconclusive. As a result, management
cannot predict the potential consequences to the Partnership if applications,
hardware or systems under the control of third parties are not Year 2000
compliant.
The remediation phase will include the modification, conversion or
replacement of existing applications, hardware and systems that are determined
not to be Year 2000 compliant. A software consulting firm has been engaged to
perform the remediation phase on the Partnership's critical financial and
operational systems that are to be modified or converted. Remediation of all
other critical systems was substantially completed by the end of the second
quarter of 1999.
The testing phase will validate the results of the remediation phase. The
implementation phase will perform business system modifications for
applications, hardware and systems that are affected by the remediation phase.
The testing phase was substantially completed during the third quarter of 1999.
The implementation phase was partially completed during the third quarter of
1999. Management expects that the implementation phases will be completed
during the fourth quarter of 1999.
15
Costs of the Year 2000 Project
While the total cost of the Year 2000 Project is still under evaluation,
management currently estimates that the total costs to be incurred by the
Partnership for the Year 2000 Project will be between $600,000 and $700,000.
The Partnership expects to fund these expenditures with cash from operations or
borrowings. Cash expenditures through September 30, 1999 were approximately
$504,000, with $78,000 of that amount for hardware. The Partnership does not
separately track the internal costs incurred for the Year 2000 Project.
Internal costs are primarily the payroll related costs for the Partnership's
information systems group, Year 2000 Steering Committee members and other
operations personnel involved in the Project. Management has not deferred
specific information technology projects as a direct result of the Year 2000
issue.
Risk of Year 2000 Issues
Major applications that pose the greatest Year 2000 risks for the
Partnership if the Year 2000 Project is not successful are the Partnership's
financial and operational system applications and embedded chip systems in field
equipment. Potential problems resulting if the Year 2000 Project is not
successful include disruptions of the Partnership's financial and operational
functions. Affected financial functions include the ability to collect revenue,
issue payments and carry on commercial and banking transaction execution
activities. Operational functions that could be disrupted include the
Partnership's crude oil transportation, storage, gathering and marketing
activities.
Contingency Plans
The goal of the Year 2000 Project is to ensure that all critical systems
and business processes under the direct control of the Partnership remain
functional. However, since certain systems and processes may be interrelated
with systems outside of the control of the Partnership, there can be no
assurance that the Year 2000 Project will be completely successful.
Consequently, contingency and business plans are being developed to respond to
any Year 2000 compliance failures that may occur. Such plans will be completed
during the fourth quarter of 1999.
Management does not expect the costs of the Year 2000 project to have a
material adverse effect on the Partnership's financial position, results of
operations or cash flows. At this time, however, the Partnership cannot
conclude that any failure of the Partnership or third parties to achieve Year
2000 compliance will not adversely affect the Partnership.
Forward Looking Statements
The statements in this Report on Form 10-Q that are not historical
information are forward looking statements within the meaning of Section 27a of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although the Partnership believes that its expectations regarding future
events are based on reasonable assumptions, it can give no assurance that its
goals will be achieved or that its expectations regarding future developments
will prove to be correct. Important factors that could cause actual results to
differ materially from those in the forward looking statements herein include
changes in regulations, the Partnership's success in obtaining additional lease
barrels, refiner demand for various grades of crude oil and the resulting
changes in pricing relationships, developments relating to possible acquisitions
or business combination opportunities, disruptions caused by the Year 2000
issue, the success of the Partnership's risk management activities and
conditions of the capital markets and equity markets during the periods covered
by the forward looking statements.
Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil price
fluctuations on its inventories and the fluctuations each month in grade and
location differentials and their effects on future contractual commitments. The
Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based
futures contracts, forward contracts, swap agreements and option contracts to
hedge its exposure to these market price fluctuations. Management believes the
hedging program has been effective in minimizing overall price risk. At
September 30, 1999, the Partnership used futures and forward contracts in its
hedging program with the latest contract being settled in October 2000.
Information about these contracts is contained in the table set forth below.
16
Sell (Short) Buy (Long)
Contracts Contracts
-------- --------
Crude Oil Inventory:
Volume (1,000 bbls) 111
Carrying value (in thousands) $ 2,730
Fair value (in thousands) $ 2,730
Commodity Futures Contracts
Contract volumes (1,000 bbls) 19,723 19,451
Weighted average price per bbl $ 21.54 $ 21.32
Contract value (in thousands) $424,832 $414,782
Fair value (in thousands) $475,015 $466,072
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 3,659 3,655
Weighted average price per bbl $ 22.62 $ 22.85
Contract value (in thousands) $82,761 $83,497
Fair value (in thousands) $88,060 $88,282
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount in U.S. dollars and total fair value
amount in U.S. dollars. Fair values were determined by using the notional
amount in barrels multiplied by the September 30, 1999 closing prices of the
applicable NYMEX futures contract adjusted for location and grade differentials,
as necessary.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 9 to the Condensed Consolidated Financial
Statements entitled "Contingencies", which is incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 10.1 Eleventh Amendment dated September 10, 1999 to the Master
Credit Support Agreement
Exhibit 10.2 Severance Agreement between Genesis Energy, L.L.C. and
Mark J Gorman
Exhibit 10.3 Severance Agreement between Genesis Energy, L.L.C. and
John P. vonBerg
Exhibit 10.4 Severance Agreement between Genesis Energy, L.L.C. and
John M. Fetzer
Exhibit 10.5 Employment agreement between Genesis Energy, L.L.C. and
Paul A. Scoff
Exhibit 10.6 Employment agreement between Genesis Energy, L.L.C. and
Ben F. Runnels
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K.
None
17
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, L.L.C., as
General Partner
Date: November 12, 1999 By: /s/ Ross A. Benavides
------------------------
Ross A. Benavides
Chief Financial Officer