Form 10-Q for the period ended June 30, 2007
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
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, 2007
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
(State
or other jurisdictions of
incorporation
or organization)
|
|
76-0513049
(I.R.S.
Employer
Identification
No.)
|
|
|
|
500
Dallas, Suite 2500, Houston, TX
(Address
of principal executive offices)
|
|
77002
(Zip
code)
|
Registrant's
telephone number, including area code:
|
|
(713)
860-2500
|
Securities
registered pursuant to Section 12(g) of the Act:
NONE
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
ü
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 ü
|
Non-accelerated
filer_____
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2) of the Exchange Act).
Yes
No
ü
Indicate
number of outstanding shares of each of the issuer’s classes of common stock, as
of the latest practicable date. Common Units outstanding as of August 6, 2007:
28,318,532
This
report contains 40 pages
GENESIS
ENERGY, L.P.
Form
10-Q
INDEX
PART
I.
FINANCIAL INFORMATION
Item
1. Financial
Statements Page
PART
II.
OTHER INFORMATION
GENESIS
ENERGY, L.P.
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
3,832
|
|
$
|
2,318
|
|
Accounts
receivable:
|
|
|
|
|
|
|
|
Trade
|
|
|
88,269
|
|
|
88,006
|
|
Related
Party
|
|
|
1,216
|
|
|
1,100
|
|
Inventories
|
|
|
11,302
|
|
|
5,172
|
|
Net
investment in direct financing leases, net of unearned income -
current
portion - related party
|
|
|
588
|
|
|
568
|
|
Other
|
|
|
1,876
|
|
|
2,828
|
|
Total
current assets
|
|
|
107,083
|
|
|
99,992
|
|
|
|
|
|
|
|
|
|
FIXED
ASSETS, at cost
|
|
|
70,801
|
|
|
70,382
|
|
Less:
Accumulated depreciation
|
|
|
(40,908
|
)
|
|
(39,066
|
)
|
Net
fixed assets
|
|
|
29,893
|
|
|
31,316
|
|
|
|
|
|
|
|
|
|
NET
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income -
related
party
|
|
|
5,074
|
|
|
5,373
|
|
CO2
ASSETS, net of amortization
|
|
|
31,351
|
|
|
33,404
|
|
JOINT
VENTURES AND OTHER INVESTMENTS
|
|
|
17,619
|
|
|
18,226
|
|
OTHER
ASSETS, net of amortization
|
|
|
12,306
|
|
|
2,776
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
203,326
|
|
$
|
191,087
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accounts
payable:
|
|
|
|
|
|
|
|
Trade
|
|
$
|
85,461
|
|
$
|
85,063
|
|
Related
party
|
|
|
1,864
|
|
|
1,629
|
|
Accrued
liabilities
|
|
|
11,890
|
|
|
9,220
|
|
Total
current liabilities
|
|
|
99,215
|
|
|
95,912
|
|
|
|
|
|
|
|
|
|
LONG-TERM
DEBT
|
|
|
22,800
|
|
|
8,000
|
|
OTHER
LONG-TERM LIABILITIES
|
|
|
963
|
|
|
991
|
|
MINORITY
INTERESTS
|
|
|
521
|
|
|
522
|
|
COMMITMENTS
AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS'
CAPITAL:
|
|
|
|
|
|
|
|
Common
unitholders, 13,784 units issued and outstanding
|
|
|
78,166
|
|
|
83,884
|
|
General
partner
|
|
|
1,661
|
|
|
1,778
|
|
Total
partners' capital
|
|
|
79,827
|
|
|
85,662
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
|
$
|
203,326
|
|
$
|
191,087
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
|
|
|
|
(In
thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil gathering and marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties (including revenues from buy/sell arrangements of $69,772
in the
first quarter of 2006)
|
|
$
|
190,293
|
|
$
|
220,633
|
|
$
|
363,136
|
|
$
|
472,894
|
|
Related
parties
|
|
|
442
|
|
|
195
|
|
|
878
|
|
|
379
|
|
Pipeline
transportation, including natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
|
4,950
|
|
|
7,404
|
|
|
10,397
|
|
|
13,994
|
|
Related
parties
|
|
|
1,385
|
|
|
1,217
|
|
|
2,726
|
|
|
2,397
|
|
CO2
marketing revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
|
3,295
|
|
|
3,239
|
|
|
6,162
|
|
|
6,626
|
|
Related
parties
|
|
|
651
|
|
|
655
|
|
|
1,281
|
|
|
655
|
|
Total
revenues
|
|
|
201,016
|
|
|
233,343
|
|
|
384,580
|
|
|
496,945
|
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties (including costs from buy/sell arrangements of $68,899
in the
first quarter of 2006)
|
|
|
184,517
|
|
|
214,737
|
|
|
352,228
|
|
|
460,649
|
|
Related
parties
|
|
|
18
|
|
|
24
|
|
|
29
|
|
|
1,484
|
|
Field
operating costs
|
|
|
4,773
|
|
|
3,720
|
|
|
8,731
|
|
|
7,065
|
|
Pipeline
transportation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
operating costs
|
|
|
2,996
|
|
|
2,477
|
|
|
5,681
|
|
|
4,746
|
|
Natural
gas purchases
|
|
|
1,112
|
|
|
2,542
|
|
|
2,347
|
|
|
5,241
|
|
CO2
marketing costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
costs - related party
|
|
|
1,236
|
|
|
1,153
|
|
|
2,334
|
|
|
2,174
|
|
Other
costs
|
|
|
45
|
|
|
54
|
|
|
91
|
|
|
106
|
|
General
and administrative
|
|
|
5,600
|
|
|
3,249
|
|
|
8,928
|
|
|
5,909
|
|
Depreciation
and amortization
|
|
|
2,046
|
|
|
2,029
|
|
|
3,974
|
|
|
3,893
|
|
Net
(gain) loss on disposal of surplus assets
|
|
|
(8
|
)
|
|
1
|
|
|
(24
|
)
|
|
(49
|
)
|
Total
costs and expenses
|
|
|
202,335
|
|
|
229,986
|
|
|
384,319
|
|
|
491,218
|
|
OPERATING
(LOSS) INCOME
|
|
|
(1,319
|
)
|
|
3,357
|
|
|
261
|
|
|
5,727
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of joint ventures
|
|
|
293
|
|
|
339
|
|
|
554
|
|
|
652
|
|
Interest
income
|
|
|
34
|
|
|
30
|
|
|
78
|
|
|
108
|
|
Interest
expense
|
|
|
(355
|
)
|
|
(293
|
)
|
|
(625
|
)
|
|
(493
|
)
|
Income
tax (expense) benefit
|
|
|
(25
|
)
|
|
11
|
|
|
(55
|
)
|
|
11
|
|
(Loss)
income before cumulative effect adjustment
|
|
|
(1,372
|
)
|
|
3,444
|
|
|
213
|
|
|
6,005
|
|
Cumulative
effect adjustment of adoption of new accounting principle
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
30
|
|
NET
(LOSS) INCOME
|
|
$
|
(1,372
|
)
|
$
|
3,444
|
|
$
|
213
|
|
$
|
6,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
|
|
UNAUDITED
CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED
|
|
(In
thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
NET
(LOSS) INCOME PER COMMON UNIT - BASIC AND DILUTED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
income before cumulative effect adjustment
|
|
$
|
(0.09
|
)
|
$
|
0.24
|
|
$
|
0.02
|
|
$
|
0.43
|
|
Cumulative
effect adjustment
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
NET
(LOSS) INCOME
|
|
$
|
(0.09
|
)
|
$
|
0.24
|
|
$
|
0.02
|
|
$
|
0.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of common units outstanding
|
|
|
13,784
|
|
|
13,784
|
|
|
13,784
|
|
|
13,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
Capital
|
|
|
|
Number
of
|
|
|
|
|
|
|
|
|
|
Common
|
|
Common
|
|
General
|
|
|
|
|
|
Units
|
|
Unitholders
|
|
Partner
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
capital, January 1, 2007
|
|
|
13,784
|
|
$
|
83,884
|
|
$ |
1,778
|
|
$ |
85,662
|
|
Net
income
|
|
|
-
|
|
|
209
|
|
|
4
|
|
|
213
|
|
Cash
distributions
|
|
|
-
|
|
|
(5,927
|
)
|
|
(121
|
)
|
|
(6,048
|
)
|
Partners'
capital, June 30, 2007
|
|
|
13,784
|
|
$
|
78,166
|
|
$
|
1,661
|
|
$
|
79,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
213
|
|
$
|
6,035
|
|
Adjustments
to reconcile net income to net cash provided by operating activities
-
|
|
|
|
|
|
|
|
Depreciation
|
|
|
1,921
|
|
|
1,857
|
|
Amortization
of CO2
contracts
|
|
|
2,053
|
|
|
2,036
|
|
Amortization
of credit facility issuance costs
|
|
|
273
|
|
|
186
|
|
Amortization
of unearned income on direct financing leases
|
|
|
(315
|
)
|
|
(333
|
)
|
Payments
received under direct financing leases
|
|
|
594
|
|
|
594
|
|
Equity
in earnings of investments in joint ventures
|
|
|
(554
|
)
|
|
(652
|
)
|
Distributions
from joint ventures - return on investment
|
|
|
833
|
|
|
677
|
|
Gain
on disposal of assets
|
|
|
(24
|
)
|
|
(49
|
)
|
Cumulative
effect adjustment
|
|
|
-
|
|
|
(30
|
)
|
Non-cash
effect of stock appreciation rights plan
|
|
|
3,340
|
|
|
442
|
|
Other
non-cash items
|
|
|
(992
|
)
|
|
(332
|
)
|
Changes
in components of working capital -
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(379
|
)
|
|
(18,411
|
)
|
Inventories
|
|
|
(6,105
|
)
|
|
(8,363
|
)
|
Other
current assets
|
|
|
952
|
|
|
1,196
|
|
Accounts
payable
|
|
|
931
|
|
|
12,856
|
|
Accrued
liabilities
|
|
|
314
|
|
|
747
|
|
Net
cash provided by (used in) operating activities
|
|
|
3,055
|
|
|
(1,544
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Additions
to property and equipment
|
|
|
(718
|
)
|
|
(480
|
)
|
Distributions
from joint ventures - return of investment
|
|
|
361
|
|
|
153
|
|
Investment
in Sandhill Group, LLC
|
|
|
-
|
|
|
(5,037
|
)
|
Investments,
other
|
|
|
-
|
|
|
(513
|
)
|
Proceeds
from disposal of assets
|
|
|
195
|
|
|
67
|
|
Prepayment
on purchase of Port Hudson assets
|
|
|
(8,100
|
)
|
|
-
|
|
Other,
net
|
|
|
(1,711
|
)
|
|
(26
|
)
|
Net
cash used in investing activities
|
|
|
(9,973
|
)
|
|
(5,836
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Bank
borrowings, net
|
|
|
14,800
|
|
|
11,500
|
|
Other,
net
|
|
|
(319
|
)
|
|
(580
|
)
|
Distributions
to common unitholders
|
|
|
(5,927
|
)
|
|
(4,825
|
)
|
Distributions
to general partner and minority interest owner
|
|
|
(122
|
)
|
|
(98
|
)
|
Net
cash provided by financing activities
|
|
|
8,432
|
|
|
5,997
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash and cash equivalents
|
|
|
1,514
|
|
|
(1,383
|
)
|
Cash
and cash equivalents at beginning of period
|
|
|
2,318
|
|
|
3,099
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at end of period
|
|
$
|
3,832
|
|
$
|
1,716
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
Organization
We
are a
publicly traded Delaware limited partnership formed in December 1996. Our
operations are conducted through our operating subsidiary, Genesis Crude Oil,
L.P., and its subsidiaries. We are engaged in pipeline transportation of crude
oil, and, to a lesser degree, natural gas and carbon dioxide (CO2),
crude
oil gathering and marketing, and industrial gas activities, including wholesale
marketing of CO2
and
processing of syngas through a joint venture. Our assets are located in the
United States Gulf Coast area.
Our
2%
general partner interest is held by Genesis Energy, Inc., a Delaware corporation
and an indirect, wholly-owned subsidiary of Denbury Resources Inc. Denbury
and
its subsidiaries are hereafter referred to as Denbury. Our general partner
also
owns 7.4% of our outstanding common units and all of our incentive distribution
rights. See Note 5.
Our
general partner manages our operations and activities and employs our officers
and personnel, who devote 100% of their efforts to our management.
On
July
25, 2007, we acquired certain energy-related businesses of the Davison family
of
Ruston, Louisiana. See Note 14.
Basis
of Consolidation and Presentation
The
accompanying financial statements and related notes present our consolidated
financial position as of June 30, 2007 and December 31, 2006 and our results
of
operations for the three and six months ended June 30, 2007 and 2006, our cash
flows for the six months ended June 30, 2007 and 2006 and changes in partners’
capital for the six months ended June 30, 2007. All 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. These investments are accounted
for by the equity method, as we exercise significant influence over their
operating and financial policies. See Note 3.
No
provision for federal 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. In May 2006, the State
of Texas enacted a law which 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
on our revenues (for federal income tax purposes) less the cost of the products
sold (for federal income tax purposes), in the State of Texas. See Note
13.
Accounting
measurements at interim dates inherently involve greater reliance on estimates
than at year end and the results of operations for the interim periods shown
in
this report are not necessarily indicative of results to be expected for the
fiscal year. The financial statements included herein have been prepared by
us
without audit pursuant to the rules and regulations of the Securities and
Exchange Commission (SEC). Accordingly, they reflect all adjustments (which
consist solely of normal recurring adjustments) that are, in the opinion of
management, necessary for a fair presentation of the financial results for
interim periods. Certain information and notes normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations. However,
we believe that the disclosures are adequate to make the information presented
not misleading when read in conjunction with the information contained in the
periodic reports we file with the SEC pursuant to the Securities Exchange Act
of
1934, including the financial statements and notes thereto included in our
Annual Report on Form 10-K for the year ended December 31, 2006.
2.
New Accounting Pronouncements
FASB
Interpretation No. 48
In
July
2006, the Financial Accounting Standards Board, or FASB, issued FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109”, or FIN 48, which clarifies the
accounting and disclosure for uncertainty in tax positions, as defined. FIN
48
seeks to reduce the diversity in practice associated with certain aspects of
the
recognition and measurement related to accounting for income taxes. This
interpretation was effective for us beginning January 1, 2007. The adoption of
FIN 48 had no impact on our consolidated financial statements.
SFAS
157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, or SFAS
157. SFAS 157 defines fair value, establishes a framework for measuring fair
value in accordance with accounting principles generally accepted in the United
States, and expands disclosures about fair value measurements. SFAS 157 is
effective for fiscal years beginning after November 15, 2007, with earlier
adoption encouraged. Any amounts recognized upon adoption as a cumulative effect
adjustment will be recorded to the opening balance of retained earnings in
the
year of adoption. SFAS 157 may impact our balance sheet and statement of
operations in many areas including the fair value measurement and allocation
of
the purchase price in business combinations and the fair value measurements
for
derivative instruments, impairment of assets, and asset retirement obligations.
We are currently assessing the impact of SFAS 157 on our consolidated financial
statements.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities”, or SFAS 159. SFAS 159 permits
entities to choose to measure many financial assets and financial liabilities
at
fair value. Unrealized gains and losses on items for which the fair value option
has been elected are reported in earnings. SFAS 159 is effective for fiscal
years beginning after November 15, 2007. We are currently assessing the impact
of SFAS 159 on our consolidated financial statements.
EITF
07-4
In
May
2007, the Emerging Issues Task Force of the FASB issued EITF 07-4, “Application
of the Two-Class Method under FASB Statement No. 128, Earnings
per Share,
to
Master Limited Partnerships.” This EITF considers the question of whether the
incentive distribution rights (“IDRs”) of a master limited partnership represent
a participating security and should be considered in the calculation of earnings
per unit. Under the “two class” method of computing earnings per unit, earnings
are allocated to participating securities as if all of the earnings for the
period had been distributed. The EITF also presents alternative methods for
inclusion of IDRs in the computation of earnings per unit. The EITF did not
reach a conclusion on this topic and will address it at its September 2007
meeting. Once a consensus is reached, it is expected to be effective for fiscal
years beginning after December 15, 2007, and interim periods within those fiscal
years. We will assess the impact of EITF 07-4 once a consensus is reached;
however we would expect it to have an impact on our presentation of earnings
per
unit in the future. For additional information on our incentive distribution
rights, see Note 5.
EITF
04-13
We
enter
into buy/sell arrangements that are accounted for on a gross basis in our
statements of operations as revenues and costs of crude. These transactions
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 either 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
started reflecting these amounts of revenues and purchases as a net amount
in
our consolidated statements of operations beginning in the
second
quarter of 2006. Had this provision been in effect in the first quarter of
2006,
our reported crude oil gathering and marketing revenues from unrelated parties
for the six months ended June 30, 2006 would have been reduced by $70 million
to
$403 million. Our reported crude oil costs from unrelated parties for the six
months ended June 30, 2006, would have been reduced by $69 million to $392
million. This change had no effect on operating income, net income or cash
flows.
3.
Joint Ventures and Other Investments
T&P
Syngas Supply Company
We
own a
50% interest in T&P Syngas Supply Company (“T&P Syngas”), a Delaware
general partnership. Praxair Hydrogen Supply Inc. (“Praxair”) owns the remaining
50% partnership interest in T&P Syngas. 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 as both partners have substantive participating rights. 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 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, 2007 included $402,000 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.
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. We received distributions
from T&P Syngas of $1.1 million during the six months ended June 30,
2007.
The
tables below reflect summarized financial information for T&P Syngas (in
thousands):
|
|
Six
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30, 2007
|
|
June
30, 2006
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,503
|
|
$
|
2,510
|
|
Operating
expenses and depreciation
|
|
|
(890
|
)
|
|
(896
|
)
|
Other
income
|
|
|
9
|
|
|
7
|
|
Net
income
|
|
$
|
1,622
|
|
$
|
1,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2007
|
|
|
December
31, 2006
|
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$
|
1,355
|
|
$
|
1,355
|
|
Non-current
assets
|
|
|
15,084
|
|
|
15,387
|
|
Total
assets
|
|
$
|
16,439
|
|
$
|
16,742
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
474
|
|
$
|
156
|
|
Non-current
liabilties
|
|
|
173
|
|
|
165
|
|
Partners'
capital
|
|
|
15,792
|
|
|
16,421
|
|
Total
liabilites and partners' capital
|
|
$
|
16,439
|
|
$
|
16,742
|
|
Sandhill
Group, LLC
On
April
1, 2006, we acquired a 50% interest in Sandhill Group, LLC (“Sandhill”). At June
30, 2007, Magna Carta held the other 50% interest in Sandhill. Sandhill is
a
limited liability company that owns a CO2
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 CO2
from us
under a long-term supply contract that we acquired in 2005 from Denbury.
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.
Our
consolidated statements of operations for the three and six months ended June
30, 2007 included $48,000 and $57,000, respectively, as our share of the
operating earnings of Sandhill, reduced by amortization of the excess purchase
price of $69,000 and $138,000, respectively. 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. We received distributions from Sandhill of
$60,000 during the six months ended June 30, 2007.
The
tables below reflect summarized financial information for Sandhill (in
thousands):
|
|
Six
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30, 2007
|
|
June
30, 2006
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
5,069
|
|
$
|
2,693
|
|
Operating
expenses and depreciation
|
|
|
(4,956
|
)
|
|
(2,513
|
)
|
Other
income
|
|
|
2
|
|
|
1
|
|
Net
income
|
|
$
|
115
|
|
$
|
181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2007
|
|
|
December
31, 2006
|
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$
|
1,367
|
|
$
|
1,606
|
|
Non-current
assets
|
|
|
6,325
|
|
|
6,592
|
|
Total
assets
|
|
$
|
7,692
|
|
$
|
8,198
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
1,204
|
|
$
|
1,463
|
|
Non-current
liabilties
|
|
|
3,927
|
|
|
4,140
|
|
Partners'
capital
|
|
|
2,561
|
|
|
2,595
|
|
Total
liabilites and partners' capital
|
|
$
|
7,692
|
|
$
|
8,198
|
|
Other
Projects
In
2006,
we invested $1.0 million in a petroleum coke to ammonia project that is in
the
development stage. All of our investment may later be redeemed, with a return,
or converted to equity after the project has obtained construction financing.
We
have committed to invest an additional $1.1 million in this project during
the
remainder of 2007. The funds we have invested will be used for project
development activities, which include the negotiation of off-take agreements
for
the products and by-products of the plant to be constructed, securing permits
and securing financing for the construction phase of the plant.
No
events
or changes in circumstances have occurred that indicate a significant adverse
effect on the fair values of our investments at June 30, 2007, therefore our
investments are included in our consolidated balance sheet at cost.
4.
Debt
Our
credit facility, with a maximum facility amount of $500 million, is with a
group
of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc. The
initial committed amount under our facility was $125 million, of which a maximum
of $50 million could be used for letters of credit. The committed amount
represents the amount the banks have committed to fund pursuant to the terms
of
the credit agreement. The borrowing base is recalculated quarterly and at the
time of material acquisitions. The borrowing base represents the amount that
can
be borrowed or utilized for letters of credit from a credit standpoint based
on
our EBITDA (earnings before interest, taxes, depreciation and amortization),
computed in accordance with the provisions of our credit facility.
The
commitment amount can be increased up to the maximum facility amount for
acquisitions or internal growth projects with approval of the lenders. Likewise,
the borrowing base may be increased to the extent of pro forma additional EBITDA
attributable to acquisitions with approval of the lenders. In connection with
the Davison acquisition on July 25, 2007, we increased the committed amount
under our credit facility to $500 million and the maximum for letters of credit
to $100 million. Our borrowing base as of July 31, 2007 was $380 million. See
Note 14.
At
June
30, 2007, we had $22.8 million borrowed under our credit facility and we had
$3.5 million in letters of credit outstanding. Due to the revolving nature
of
loans under our credit facility, additional borrowings and periodic repayments
and re-borrowings may be made until the maturity date of November 15, 2011.
The
total amount available for borrowings at June 30, 2007 was $53.0 million under
our credit facility.
The
key
terms for rates under our credit facility are as follows:
· |
The
interest rate on borrowings may be based on the prime rate or the
LIBOR
rate, at our option. The interest rate on prime rate loans can range
from
the prime rate plus 0.50% to the prime rate plus 1.875%. The interest
rate
for LIBOR-based loans can range from the LIBOR rate plus 1.50% to
the
LIBOR rate plus 2.875%. The rate is based on our leverage ratio as
computed under the credit facility. Our leverage ratio is recalculated
quarterly and in connection with each material acquisition. As of
July 31,
2007, our borrowing rates were the prime rate plus 1.25% or the LIBOR
rate
plus 2.25%.
|
· |
Letter
of credit fees will range from 1.50% to 2.875% based on our leverage
ratio
as computed under the credit facility. The rate can fluctuate quarterly.
At June 30, 2007, the rate was 1.50%. As of July 31, 2007, our letter
of
credit rate was 2.25%.
|
· |
We
pay a commitment fee on the unused portion of the $125 million commitment.
The commitment fee will range from 0.30% to 0.50% based on our leverage
ratio as computed under the credit facility. The rate can fluctuate
quarterly. At June 30, 2007, the commitment fee rate was 0.30%. As
of July
31, 2007, our commitment rate was
0.50%.
|
Collateral
under the credit facility consists of substantially all our assets. While in
general, our general partner is jointly and severally liable for all of our
obligations unless and except to the extent those obligations provide that
they
are non-recourse to our general partner, our credit facility expressly provides
that it is non-recourse to our general partner (except to the extent of its
pledge of its general partner interest in certain of our subsidiaries) and
Denbury and its other subsidiaries.
Our
credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which we may conduct our business. Our
credit facility contains three primary financial covenants - a debt service
coverage ratio, leverage ratio and funded indebtedness to capitalization ratio
-
that require us to achieve specific minimum financial metrics. In general,
the
debt service coverage ratio calculation compares EBITDA (as adjusted in
accordance with the credit facility) to interest expense. The leverage ratio
calculation compares our consolidated funded debt (as calculated in accordance
with the credit facility) to EBITDA (as adjusted). The funded indebtedness
ratio
compares outstanding debt to the sum of our consolidated total funded debt
plus
our consolidated net worth.
Our
credit facility includes provisions for the temporary adjustment of the required
ratios following material acquisitions and with lender approval. If we meet
these financial metrics and are not otherwise in default under our credit
facility, we may make quarterly distributions; however the amount of such
distributions may not exceed the
sum
of
the distributable cash generated by us for the eight most recent quarters,
less
the sum of the distributions made with respect to those quarters. At June 30,
2007, the excess of distributable cash over distributions under this provision
of the credit facility was $18.4 million. For a summary of our non-financial
covenants, please refer to our Annual Report on Form 10-K for the year ended
December 31, 2006.
The
carrying value of our debt under our credit facility approximates fair value
primarily because interest rates fluctuate with prevailing market rates, and
the
applicable margin on outstanding borrowings reflect what we believe is
market.
5.
Partners’ Capital and Distributions
Partners’
Capital
Partner’s
capital at June 30, 2007 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. On July
25,
2007, in connection with the Davison acquisition, we issued 13,459,209 common
units to the entities owned and controlled by the Davison family. The units
were
issued at a contractual value of $20.8036 per unit. Additionally, our general
partner exercised its right to maintain its right to maintain its proportionate
share of our outstanding common units by purchasing 1,074,882 common units
from
us for $22.4 million cash, or $20.8036 per common unit. As required under our
partnership agreement, our general partner also contributed approximately $6.2
million to maintain its capital account balance. See Note 14.
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 at June 30, 2007) 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. As
discussed in Note 4, our credit facility limits the amount of distributions
we
may pay in any quarter.
We
paid
or will pay the following distributions to the holders of our common units
in
2006 and 2007:
|
|
|
|
|
|
Limited
|
|
General
|
|
|
|
|
|
|
|
|
|
|
|
|
Partner
|
|
|
Partner
|
|
|
|
|
|
|
|
|
|
|
Per
Unit
|
|
|
Interests
|
|
|
Interest
|
|
|
Total
|
|
Distribution
For
|
|
|
Date
Paid
|
|
|
Amount
|
|
|
Amount
|
|
|
Amount
|
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
Fourth
quarter 2005
|
|
|
February
2006
|
|
$
|
0.17
|
|
$
|
2,343
|
|
$
|
48
|
|
$
|
2,391
|
|
First
quarter 2006
|
|
|
May
2006
|
|
$
|
0.18
|
|
$
|
2,481
|
|
$
|
51
|
|
$
|
2,532
|
|
Second
quarter 2006
|
|
|
August
2006
|
|
$
|
0.19
|
|
$
|
2,619
|
|
$
|
53
|
|
$
|
2,672
|
|
Third
quarter 2006
|
|
|
November
2006
|
|
$
|
0.20
|
|
$
|
2,757
|
|
$
|
56
|
|
$
|
2,813
|
|
Fourth
quarter 2006
|
|
|
February
2007
|
|
$
|
0.21
|
|
$
|
2,895
|
|
$
|
59
|
|
$
|
2,954
|
|
First
quarter 2007
|
|
|
May
2007
|
|
$
|
0.22
|
|
$
|
3,032
|
|
$
|
62
|
|
$
|
3,094
|
|
Second
quarter 2007
|
|
|
August
2007
|
|
$
|
0.23
|
|
$
|
3,170
|
(1) |
$
|
65
|
|
$
|
3,235
|
(1) |
(1)
The
distribution payable on August 14, 2007 to holders of our common units is net
of
the amounts payable with respect to the common units issued in connection with
the Davison transaction. The Davison unitholders and our general partner waived
their right to receive such distributions, instead receiving purchase price
adjustments with us. See Note 14.
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 to holders
of our common units in excess of $0.25 per unit, 23.5% of any distributions
to
holders of our common units in excess of $0.28 per unit and 49% of any
distributions to holders of our common units in excess of $0.33 per unit without
duplication. We have not paid any incentive distributions from our inception
through June 30, 2007.
Net
Income (Loss) Per Common Unit
The
following table sets forth the computation of basic net income (loss) per common
unit (in thousands, except per unit amounts).
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
Numerators
for basic and diluted net (loss) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
per
common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
income from continuing operations
|
|
$
|
(1,372
|
)
|
$
|
3,444
|
|
$
|
213
|
|
$
|
6,005
|
|
Less
general partner 2% ownership
|
|
|
(27
|
)
|
|
69
|
|
|
4
|
|
|
120
|
|
(Loss)
income from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
available
for common unitholders
|
|
$
|
(1,345
|
)
|
$
|
3,375
|
|
$
|
209
|
|
$
|
5,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
13,784
|
|
|
13,784
|
|
|
13,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and diluted net (loss) income per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
income from continuing operations
|
|
$
|
(0.09
|
)
|
$
|
0.24
|
|
$
|
0.02
|
|
$
|
0.43
|
|
Loss
from cumulative effect adjustment
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
(loss) income
|
|
$
|
(0.09
|
)
|
$
|
0.24
|
|
$
|
0.02
|
|
$
|
0.43
|
|
6.
Business Segment Information
Our
operations consist of three operating segments: (1) Pipeline Transportation
-
interstate and intrastate crude oil, natural gas and CO2
pipeline
transportation; (2) Industrial Gases - the sale of CO2
acquired
under volumetric production payments to industrial customers and our investment
in a syngas processing facility, and (3) Crude Oil Gathering and Marketing
- the
purchase and sale of crude oil at various points along the distribution chain.
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 operation 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.
|
|
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Pipeline
|
|
Industrial
|
|
Gathering
&
|
|
|
|
|
|
Transportation
|
|
Gases
(a)
|
|
Marketing
|
|
Total
|
|
|
|
(in
thousands)
|
|
Three
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
depreciation
and amortization (b)
|
|
$
|
2,227
|
|
$
|
2,958
|
|
$
|
1,427
|
|
$
|
6,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$
|
337
|
|
$
|
-
|
|
$
|
42
|
|
$
|
379
|
|
Maintenance
capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
expenditures
|
|
$
|
337
|
|
$
|
-
|
|
$
|
42
|
|
$
|
379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$
|
5,347
|
|
$
|
3,946
|
|
$
|
190,735
|
|
$
|
200,028
|
|
Intersegment
(d)
|
|
|
988
|
|
|
-
|
|
|
-
|
|
|
988
|
|
Total
revenues of reportable segments
|
|
$
|
6,335
|
|
$
|
3,946
|
|
$
|
190,735
|
|
$
|
201,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
depreciation
and amortization (b)
|
|
$
|
5,095
|
|
$
|
5,572
|
|
$
|
3,026
|
|
$
|
13,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$
|
559
|
|
$
|
-
|
|
$
|
135
|
|
$
|
694
|
|
Maintenance
capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
expenditures
|
|
$
|
559
|
|
$
|
-
|
|
$
|
135
|
|
$
|
694
|
|
Net
fixed and other non-current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
assets
(c)
|
|
$
|
38,964
|
|
$
|
48,970
|
|
$
|
8,309
|
|
$
|
96,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$
|
11,007
|
|
$
|
7,443
|
|
$
|
364,014
|
|
$
|
382,464
|
|
Intersegment
(d)
|
|
|
2,116
|
|
|
-
|
|
|
-
|
|
|
2,116
|
|
Total
revenues of reportable segments
|
|
$
|
13,123
|
|
$
|
7,443
|
|
$
|
364,014
|
|
$
|
384,580
|
|
|
|
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Pipeline
|
|
Industrial
|
|
Gathering
&
|
|
|
|
|
|
Transportation
|
|
Gases
(a)
|
|
Marketing
|
|
Total
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
a) |
Industrial
gases includes our CO2
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 before cumulative
effect adjustment for the periods presented is as
follows:
|
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Segment
margin excluding depreciation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
amortization
|
|
$
|
6,612
|
|
$
|
8,975
|
|
$
|
13,693
|
|
$
|
16,132
|
|
General
and administrative expenses
|
|
|
(5,600
|
)
|
|
(3,249
|
)
|
|
(8,928
|
)
|
|
(5,909
|
)
|
Depreciation
and amortization expense
|
|
|
(2,046
|
)
|
|
(2,029
|
)
|
|
(3,974
|
)
|
|
(3,893
|
)
|
Net
gain (loss) on disposal of surplus assets
|
|
|
8
|
|
|
(1
|
)
|
|
24
|
|
|
49
|
|
Interest
expense, net
|
|
|
(321
|
)
|
|
(263
|
)
|
|
(547
|
)
|
|
(385
|
)
|
Income
tax (expense) benefit
|
|
|
(25
|
)
|
|
11
|
|
|
(55
|
)
|
|
11
|
|
Income
before cumulative effect adjustment
|
|
$
|
(1,372
|
)
|
$
|
3,444
|
|
$
|
213
|
|
$
|
6,005
|
|
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, in the opinion of management, 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. The transactions with related parties were
as
follows:
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
Truck
transportation services provided to Denbury
|
|
$
|
878
|
|
$
|
379
|
|
Pipeline
transportation services provided to Denbury
|
|
$
|
2,494
|
|
$
|
2,034
|
|
Payments
received under direct financing leases from
|
|
|
|
|
|
|
|
Denbury
|
|
$
|
594
|
|
$
|
594
|
|
Pipeline
transportation income portion of direct financing
|
|
|
|
|
|
|
|
lease
fees with Denbury
|
|
$
|
318
|
|
$
|
333
|
|
Pipeline
monitoring services provided to Denbury
|
|
$
|
60
|
|
$
|
30
|
|
Directors'
fees paid to Denbury
|
|
$
|
74
|
|
$
|
60
|
|
CO2
transportation services provided by Denbury
|
|
$
|
2,334
|
|
$
|
2,174
|
|
Crude
oil purchases from Denbury
|
|
$
|
29
|
|
$
|
1,484
|
|
Operations,
general and administrative services provided
|
|
|
|
|
|
|
|
by
our general partner
|
|
$
|
10,772
|
|
$
|
8,541
|
|
Distributions
to our general partner on its limited partner
|
|
|
|
|
|
|
|
units
and general partner interest
|
|
$
|
559
|
|
$
|
455
|
|
Sales
of CO2
to
Sandhill
|
|
$
|
1,281
|
|
$
|
655
|
|
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 CO2
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
paid
Denbury for the services of each of four of Denbury’s officers who serve as
directors of our general partner, at an annual rate that is $10,000 per director
less than the rate at which
our
independent directors were paid.
CO2
Operations and Transportation
Denbury
charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to
deliver CO2
for us
to our customers. In the first half of 2007, the inflation-adjusted
transportation fee averaged $0.18 per Mcf.
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
both
June 30, 2007 and December 31, 2006, we owed Denbury $0.9 million and $0.8
million, respectively, for purchases of crude oil and CO2
transportation charges. Denbury owed us $0.8 million and $0.6 million for
transportation services at June 30, 2007 and December 31, 2006, respectively.
We
owed our general partner $1.0 million and $0.9 million for administrative
services at June 30, 2007 and December 31, 2006, respectively. At June 30,
2007
and December 31, 2006, Sandhill owed us $0.4 million and $0.5 million,
respectively, for purchases of CO2.
Financing
In
general, our general partner is jointly and severally liable for all of our
obligations unless and except to the extent those obligations provide that
they
are non-recourse to our general partner, although our credit facility expressly
provides that it is non-recourse to owners of our equity interests, including
our general partner (except to the extent of its pledge of its general partner
interest in certain of our subsidiaries) and Denbury and its other
subsidiaries.
We
effectively guarantee our proportionate share (50%) of Sandhill’s outstanding
bank debt, which was $4.2 million ($2.1 million net to us) at June 30,
2007.
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, 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.
Shell
Oil
Company, Occidental Energy Marketing, Inc., and Calumet Specialty Products
Partners, L.P. accounted for 24%, 19% and 12% of total revenues in the first
half of 2007, respectively. 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. 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 $42,000 and $124,000 for the six months ended
June
30, 2007 and 2006, respectively. Payments of interest and commitment fees were
$204,000 and $218,000 for the six months ended June 30, 2007 and 2006,
respectively.
At
June
30, 2007, we had incurred liabilities for fixed asset additions totaling $0.1
million that had not been paid at the end of the second 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, 2007, 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, 2007. We marked these contracts to fair value at June
30,
2007. During the three and six months ended June 30, 2007, we recorded losses of
$80,000 and $19,000, respectively, related to derivative transactions, which
is
included in the consolidated statements of operations under the caption “Crude
oil costs”.
At
June
30, 2007, we had futures contracts 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, 2007, we recognized gains, due to hedge
ineffectiveness, on the fair value hedge of inventory of approximately $81,000
and $456,000, respectively. 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, 2007 includes an increase in other
current assets of $546,000 as a result of these derivative transactions. The
consolidated balance sheet at December 31, 2006 included an increase in other
current assets of $165,000 as a result of derivative transactions.
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”.
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.
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, 2007 and December 31, 2006.
11.
Contingencies
Guarantees
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, 2007 were
$22.8 million and are
reflected
in the consolidated balance sheet. We have also guaranteed the payments by
our
operating partnership under the terms of our operating leases of tractors and
trailers.
We
guaranteed $1.2 million of residual value related to the leases of trailers
from
a lessor. We believe the likelihood we would be required to perform or otherwise
incur any significant losses associated with this guarantee is
remote.
We
effectively guarantee our proportionate share (50%) of Sandhill’s bank debt,
which was $4.2 million ($2.1 million, net to us) at June 30, 2007. Sandhill
makes principal payments totaling $0.6 million annually on that
debt.
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 accurately be estimated at this time, we expect that our
annual expenditures for integrity tests, repairs and improvements under
regulations requiring assessment of the integrity of crude oil pipelines to
average between $1.0 million and $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, or 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 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 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 (“Howell”) entered into a sublease with Koch
Industries, Inc. (“Koch”), 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 (“Anadarko”) 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. (“Basis”) 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
developed a plan of remediation for affected soil and groundwater at Jay Station
which has been approved by appropriate state regulatory agencies. 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
Our
facilities and operations may experience damage as a result of an accident
or
natural disaster. These hazards can cause personal injury or loss of life,
severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain insurance that
we
consider adequate to cover our operations and properties, in amounts we consider
reasonable. Our insurance does not cover every potential risk associated with
operating our facilities, including the potential loss of significant revenues.
The occurrence of a significant event that is not fully-insured could materially
and adversely affect our results of operations. 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.
As
discussed in Note 3, we have committed to invest an additional $1.1 million
in a
potential petroleum coke to ammonia 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
At
December 31, 2005, we had a recorded liability of $0.8 million for our stock
appreciation rights plan, 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 in 2006. 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 adjustment of the liability to its fair value at June
30, 2007, resulted in expense for the six months ended June 30, 2007 of $4.3
million, with $2.8 million, $0.8 million and $0.7 million included in general
and administrative expenses, field operating costs and pipeline operating costs,
respectively. For the three months ended June 30, 2007, the expense we recorded
totaled $3.7 million, with $2.5 million, $0.6 million and $0.6 million included
in general and administrative expenses, field operating costs and pipeline
operating costs, respectively.
The
following table reflects rights activity under our plan during the six months
ended June 30, 2007:
Stock
Appreciation Rights
|
|
Rights
|
|
Weighted
Average Exercise Price
|
|
Weighted
Average Contractual Remaining Term (Yrs)
|
|
Aggregate
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
Outstanding
at January 1, 2007
|
|
|
659,010
|
|
$
|
12.79
|
|
|
|
|
|
|
|
Granted
during 2007
|
|
|
43,138
|
|
$
|
29.12
|
|
|
|
|
|
|
|
Exercised
during 2007
|
|
|
(64,682
|
)
|
$
|
9.42
|
|
|
|
|
|
|
|
Forfeited
or expired during 2007
|
|
|
(38,917
|
)
|
$
|
14.77
|
|
|
|
|
|
|
|
Outstanding
at June 30, 2007
|
|
|
598,549
|
|
$
|
14.20
|
|
|
8.1
|
|
$
|
8,425
|
|
Exercisable
at June 30, 2007
|
|
|
186,528
|
|
$
|
11.19
|
|
|
6.8
|
|
$
|
4,424
|
|
The
weighted-average fair value at June 30, 2007 of rights granted during the first
two quarters of 2007 was $8.93 per right. The total intrinsic value of rights
exercised during the first six months of 2007 was $1.0 million, which was paid
in cash to the participants.
At
June
30, 2007, there was $3.3 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, 2007 multiplied by those 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, 2007, the remaining cost will be recognized over a weighted average period
of 1.1 years.
13.
Income Taxes
In
May
2006, the State of Texas enacted a law which 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
SFAS 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
recorded a deferred tax asset in the amount of $11,000 upon enactment of the
law
in 2006. We believe that we will be able to utilize this deferred tax asset
at
June 30, 2007, and therefore have provided no valuation allowance against this
deferred tax asset.
For
the
three and six months ended June 30, 2007, we have provided current tax expense
in the amount of $25,000 and $55,000, respectively, as the estimate of the
taxes
that will be owed on our income for the period.
The
current liability we have accrued at June 30, 2007 is $55,000.
14.
Subsequent Events
Davison
Businesses Acquisition and Amendment to Credit Facility
On
July
25, 2007, we completed the acquisition of the assets of businesses engaged
in
five energy- related segments from several entities owned and controlled by
the
Davison family of Ruston, Louisiana. The businesses acquired from the Davison
family include:
· |
Refinery
services business - The refinery service business operates as a
third-party contractor to provide the service of processing sour
gas
streams to remove sulfur at more than a dozen refining operations,
located
primarily in Louisiana, Texas and Arkansas. This business is operated
under the name of TDC, L.L.C.
|
· |
Petroleum
products marketing business - The wholesale marketing of petroleum
products business sells a variety of petroleum products to paper
mills,
utilities and other customers for use as fuels in their operations.
This
business has been operated under the name Davison Petroleum
Products.
|
· |
Terminal
business - The terminal business operates terminals for the storage
and
blending of refined petroleum products in north Louisiana and Mississippi.
Each of the terminals is connected to multiple transportation modes.
This
business has been operated under the names Davison Terminal Services,
Sunshine Oil and Storage and Red River
Terminals.
|
· |
Trucking
business - The trucking business operates a fleet of approximately
250
tractors and over 500 trailers under the name Davison Transport.
The
fleet, in addition to third-party carriage, supports the operations
of the
refinery services, petroleum products marketing and terminal
businesses.
|
· |
Fuel
procurement business - The fuel procurement business provides fuel
procurement and delivery logistics management services to wholesale
and
retail customers in more than 35 states nationwide. This business
is
operated under the name of Fuel Masters,
LLC.
|
The
total
consideration for the transaction was $563 million, subject to adjustment.
Approximately one-half of the consideration was paid with 13,459,209 of our
common units, valued at $20.8036 per unit for purposes of the purchase
agreement, totaling $280 million. The remainder of the purchase price of $283
million, adjusted for purchase price adjustments and estimated working capital
of an additional $35.1 million was paid in cash borrowed under our credit
agreement. For financial reporting purposes, the units issued will be valued
at
$24.52, the average value of our units at the time the purchase was
announced.
Additionally,
our general partner exercised its right to maintain its proportionate share
of
our outstanding common units by purchasing 1,074,882 common units from us for
$22.4 million cash, or $20.8036 per common unit. As a result of this purchase,
the general partner will continue to hold 7.4% of our outstanding common units.
As required under our partnership agreement, our general partner also
contributed approximately $6.2 million to maintain its capital account
balance.
We
also
amended our existing credit facility. The amendment increased the committed
amount under our facility from $125 million to $500 million, of which a maximum
of $100 million may be used for letters of credit. The committed amount
represents the amount the banks have committed to fund pursuant to the terms
of
the credit agreement. The remaining significant terms of the credit agreement
did not change.
Port
Hudson Assets Acquisition
Effective
July 1, 2007, we acquired the Port Hudson Crude Oil truck terminal, marine
terminal, and marine dock of BP Pipelines (North America) Inc. (“Port Hudson”)
for $8.1 million. The assets acquired in this transaction include docking
facilities on the Mississippi River, 215,000 barrels of tankage, a pipeline
and
other related assets in East Baton Rouge Parish, Louisiana. The acquisition
was
funded with borrowings under our credit facility. We prepaid the purchase price
for the acquisition on June 29, 2007, with the prepayment reflected in Other
Assets on our consolidated balance sheet at June 30, 2007.
Distribution
On
July
26, 2007, the Board of Directors of the general partner declared a cash
distribution of $0.23 per unit for the quarter ended June 30, 2007. The
distribution will be paid August 14, 2007 to our general partner and all common
unitholders of record as of the close of business on August 6, 2007. The Davison
unitholders and our general partner have waived receipt of their share of the
distribution with respect to the units issued in connection with the Davison
acquisition, instead receiving purchase price adjustments on transactions with
us.
Included
in Management’s Discussion and Analysis are the following sections:
· |
Acquisitions
and Related Activities in 2007
|
· |
Liquidity
and Capital Resources
|
· |
Commitments
and Off-Balance Sheet Arrangements
|
· |
New
Accounting Pronouncements
|
Acquisitions
and Related Activities in 2007
Davison
Businesses Acquisition
On
July
25, 2007, we completed the acquisition of certain assets of businesses engaged
in five energy- related segments from several entities owned and controlled
by
the Davison family of Ruston, Louisiana. The Davison family has conducted
energy-related transportation businesses in Ruston since 1937. The businesses
acquired from the Davison family include:
· |
Refinery
services business - The refinery service business operates as a
third-party contractor to provide the service of processing sour
gas
streams to remove sulfur at more than a dozen refining operations,
located
primarily in Louisiana, Texas and Arkansas. This business is operated
under the name of TDC, L.L.C.
|
· |
Petroleum
products marketing business - The wholesale marketing of petroleum
products business sells a variety of petroleum products to paper
mills,
utilities and other customers for use as fuels in their operations.
This
business has been operated under the name Davison Petroleum
Products.
|
· |
Terminal
business - The terminal business operates terminals for the storage
and
blending of refined petroleum products in north Louisiana and Mississippi.
Each of the terminals is connected to multiple transportation modes.
This
business has been operated under the names Davison Terminal Services,
Sunshine Oil and Storage and Red River
Terminals.
|
· |
Trucking
business - The trucking business operates a fleet of approximately
250
tractors and over 500 trailers under the name Davison Transport.
The
fleet, in addition to third-party carriage, supports the operations
of the
refinery services, petroleum products marketing and terminal
businesses.
|
· |
Fuel
procurement business - The fuel procurement business provides fuel
procurement and delivery logistics management services to wholesale
and
retail customers in more than 35 states nationwide. This business
is
operated under the name of Fuel Masters,
LLC.
|
The
total
consideration for the transaction was $563 million, subject to adjustment.
Approximately one-half of the consideration was paid with 13,459,209 of our
common units, issued at a contractual value of $20.8036 per unit for a total
value of $280 million. The remainder of the purchase price of $283 million,
adjusted for purchase price adjustments and estimated working capital of an
additional $35.1 million was paid in cash borrowed under our credit
facility.
Additionally,
our general partner exercised its right to maintain its proportionate share
of
our outstanding common units by purchasing 1,074,882 common units from us for
$22.4 million cash, or $20.8036 per common unit. As a result of this purchase,
our general partner will continue to hold 7.4% of our outstanding common units.
As required under our partnership agreement, our general partner also
contributed approximately $6.2 million to maintain its capital account
balance.
Pursuant
to the Unitholder Agreement executed on July 25, 2007, the Davison unitholders
have the right to designate up to two directors to the Board of Directors of
our
general partner, depending on their continued level of ownership in us. Until
July 25, 2010, the Davison unitholders have the right to designate two directors
to our general partner’s Board of Directors. Thereafter, the Davison unitholders
will have the right to designate (i) one director if they beneficially own
at
least 10% but less than 35% of our outstanding common units,or (ii)
two
directors
if they beneficially own 35% of more of our outstanding common units. If their
percentage ownership in our common units drops below 10% after July 25, 2010,
the Davison unitholders have no rights to designate directors. On July 31,
2007,
the Davison unitholders hold approximately 48% of our outstanding common
units.
On
July
25, 2007, the Davison unitholders designated James E. Davison and James E.
Davison, Jr. as directors to the Board of Directors of our general
partner.
In
addition, we have agreed to call a special meeting of our unitholders as soon
as
practicable, but no later than 120 days from July 25, 2007 to propose an
amendment to our partnership agreement that would allow the Davison unitholders
to vote on all matters on which unitholders have a right to vote, other than
matters related to the succession, election, removal, withdrawal, replacement
or
substitution of our general partner. Currently our partnership agreement does
not allow any unitholder (including its affiliates) holding more than 20% of
our
outstanding units to vote.
Credit
Agreement Amendment
As
a
result of the transaction with the Davison family, we also amended our existing
credit facility. The amendment increased the committed amount under our facility
from $125 million to $500 million, of which a maximum of $100 million may be
used for letters of credit. The committed amount represents the amount the
banks
have committed to fund pursuant to the terms of the credit
agreement.
Drop-down
Transactions
As
Denbury has publicly stated, upon our achievement of certain goals, primarily
our acquisition (by construction or purchase) of economic projects that are
not
related to Denbury’s operations, Denbury will undertake to “drop-down” certain
midstream Denbury assets to us in an amount of $1.00 of Denbury assets for
every
$1.50 of non-Denbury-related acquisitions we complete. These “drop-down”
transactions are currently thought most likely to consist of property sales
combined with associated transportation or service arrangements or direct
financing leases, or a combination of both. As a result of the transaction
with
the Davisons, we anticipate that during 2007, Denbury will enter into
“drop-down” transactions with us involving their existing CO2 pipelines, with
a
current
estimated value of between $200 million and $250 million. These “drop-down”
transactions would be subject to, among other things, negotiation of specific
terms, the approval of the board of directors of both entities, and the receipt
of fairness opinions by both companies, and are expected to occur during 2007.
We would anticipate a similar transaction with Denbury for the new CO2 pipeline
Denbury is constructing from its Jackson Dome to its Tinsley and Delhi Fields,
once that pipeline is completed, currently estimated to be during 2008. If
in
future periods we are able to consummate with third parties additional
acquisitions of sufficient size with acceptable economic returns, and subject
to
the same types of conditions, Denbury anticipates similar transactions with
us
for its proposed 280 to 300 mile CO2
pipeline
from South Louisiana to Hastings Field, located near Houston, Texas, probably
during 2010. We expect to fund the transactions with Denbury with borrowings
under our credit facility as well as other sources such as a public or private
offering of debt or equity.
Port
Hudson Assets Acquisition
Effective
July 1, 2007, we acquired the Port Hudson Crude Oil truck terminal, marine
terminal, and marine dock of BP Pipelines (North America) Inc. (“Port Hudson”)
for $8.1 million. The assets acquired in this transaction include docking
facilities on the Mississippi River, 215,000 barrels of tankage, a pipeline
and
other related assets in East Baton Rouge Parish, Louisiana. The acquisition
was
funded with borrowings under our credit facility. We made the payment for the
acquisition on June 29, 2007, with the purchase price reflected in Other Assets
on our consolidated balance sheet at June 30, 2007.
Overview
In
the
discussions that follow, we 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 share of the equity in the operating income of our
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.
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 CO2
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 also participate in industrial gas activities, including a
CO2
supply
business, which is associated with the CO2
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
CO2
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 CO2
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 holders of our common units 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. As is evidenced by the discussion above under “Acquisitions
and Related Activities in 2007”,
we are
pursuing acquisitions and projects involving transportation, gathering, terminal
or storage assets and related midstream businesses, some of which may be outside
the scope of our historical operations. We are presently engaged in discussions
with various parties regarding acquisitions of assets or businesses, but we
can
give no assurance that our efforts will be successful or that any acquisitions
will be completed on terms favorable to us.
Increases
in cash flow generally result in increases in Available Cash, which we
distribute quarterly to holders of our common units and general partner. During
the second quarter of 2007, we generated $3.9 million of Available Cash before
Reserves, and distributed $3.2 million to holders of our common units and
general partner. During the second quarter of 2007, cash provided by operations
was $1.3 million.
In
the
second quarter of 2007, we incurred a net loss of $1.4 million, or $0.09 per
common unit, with $3.7 million of that loss attributable to the expense we
recorded for our stock appreciation rights plan. The increase in our common
unit
market price from March 31, 2007 to June 30, 2007 of $13.54, or 63%, increased
the expense we recorded under our plan.
For
the
six months ended June 30, 2007, we generated net income of $0.2 million, or
$0.02 per common unit. Total expense recorded for our stock appreciation rights
plan for the six month period was $4.3 million.
We
increased our cash distribution by $0.01 to $0.22 per unit for the first quarter
of 2007 (which was paid in May 2007) and increased our cash distribution again
to $0.23 per unit for the second quarter of 2007. This distribution will be
paid
in August 2007. This distribution represented a 21% increase from our
distribution of $0.19 per unit for the second quarter of 2006.
The
expense for our stock appreciation rights plan added $2.2 million to general
and
administrative costs, $0.6 million each to pipeline operating costs and to
crude
oil gathering field costs, for a total impact to net income of $3.4
million when compared to the second quarter of 2006. For the six-month period,
our expense for the stock appreciation rights plan added $2.4 million to general
and administrative costs, $0.7 million to pipeline operating costs and $0.8
million to crude oil gathering field costs, for a total of $3.9 million. Under
the accounting method used to account for our stock appreciation rights, we
determine the fair value of the rights at the end of each reporting period
using
a Black-Scholes valuation model and we recognize the change in fair value as
an
expense. This fair value is affected by several assumptions as well as by the
volatility of the market price for our common units. We believe that the
significant increase in our unit price over the last year (particularly in
the
second quarter) has been the most significant contributor to the increase in
expense for this plan. This expense is a non-cash charge until the employees
holding the rights choose to exercise them. See Note 12 of the Notes to
Unaudited Consolidated Financial Statements for information on outstanding
and
exercisable rights.
Results
of Operations
The
contribution of each of our segments to total segment margin in the first
quarters of 2007 and 2006 was as follows:
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Pipeline
transportation
|
|
$
|
2,227
|
|
$
|
3,602
|
|
$
|
5,095
|
|
$
|
6,404
|
|
Industrial
gases
|
|
|
2,958
|
|
|
3,026
|
|
|
5,572
|
|
|
5,653
|
|
Crude
oil gathering and marketing
|
|
|
1,427
|
|
|
2,347
|
|
|
3,026
|
|
|
4,075
|
|
Total
segment margin
|
|
$
|
6,612
|
|
$
|
8,975
|
|
$
|
13,693
|
|
$
|
16,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
Transportation
Operations
We
operate three crude oil common carrier pipeline systems in a four-state area.
We
refer to these pipelines as our Mississippi System, Jay System and Texas System.
Additionally, we operate a CO2
pipeline
in Mississippi to transport CO2
from
Denbury’s main CO2
pipeline
to Brookhaven oil field. Denbury has the exclusive right to use this
CO2
pipeline. We also have several natural gas gathering systems.
Operating
results for our pipeline transportation segment were as follows:
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Crude
oil tariffs and revenues from direct financing leases of crude
oil
pipelines
|
|
$
|
3,458
|
|
$
|
3,534
|
|
$
|
6,994
|
|
$
|
6,867
|
|
Sales
of crude oil pipeline loss allowance volumes
|
|
|
1,441
|
|
|
2,077
|
|
|
3,140
|
|
|
3,395
|
|
Revenues
from direct financing leases of CO2
pipelines
|
|
|
80
|
|
|
86
|
|
|
162
|
|
|
173
|
|
Tank
rental reimbursements and other miscellaneous revenues
|
|
|
164
|
|
|
164
|
|
|
327
|
|
|
308
|
|
Total
revenues from crude oil and CO2
tariffs, including revenues from direct financing leases
|
|
|
5,143
|
|
|
5,861
|
|
|
10,623
|
|
|
10,743
|
|
Revenues
from natural gas tariffs and sales
|
|
|
1,192
|
|
|
2,760
|
|
|
2,500
|
|
|
5,648
|
|
Natural
gas purchases
|
|
|
(1,112
|
)
|
|
(2,542
|
)
|
|
(2,347
|
)
|
|
(5,241
|
)
|
Pipeline
operating costs
|
|
|
(2,996
|
)
|
|
(2,477
|
)
|
|
(5,681
|
)
|
|
(4,746
|
)
|
Segment
margin
|
|
$
|
2,227
|
|
$
|
3,602
|
|
$
|
5,095
|
|
$
|
6,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
per day on crude oil pipelines:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
57,127
|
|
|
62,778
|
|
|
57,499
|
|
|
62,420
|
|
Mississippi
System
|
|
|
20,496
|
|
|
16,990
|
|
|
19,929
|
|
|
16,701
|
|
Jay
System
|
|
|
11,602
|
|
|
13,727
|
|
|
12,204
|
|
|
12,577
|
|
Texas
System
|
|
|
25,029
|
|
|
32,061
|
|
|
25,366
|
|
|
33,142
|
|
Three
Months Ended June 30, 2007 Compared with Three Months Ended June 30,
2006
Pipeline
segment margin for the second quarter of 2007 declined $1.4 million as compared
to the second quarter of 2006. Revenues from crude oil tariffs and related
sources and sales of pipeline loss allowance volumes decreased a total of $0.7
million and pipeline operating costs increased $0.5 million. The remaining
decrease was attributable to a decline in net segment margin from natural gas
pipeline activities.
Crude
oil
tariff and direct financing lease revenues decreased $0.1 million primarily
due
to a decline in the volume on the Texas System. Volumes on that system decreased
7,032 barrels per day; however the impact on revenues was not very significant
due to the relatively low tariffs on that system. Approximately 76% of the
volume on that system is shipped on a tariff of $0.22 per barrel, with an
increase effective June 1, 2007 to $0.31 per barrel. Volumes increased on our
Mississippi System by 3,506 barrels per day, which has a much higher tariff
than
the Texas System, offsetting much of the impact of the volume decrease. On
our
Jay System volumes decreased by 2,125 barrels per day, primarily due to
maintenance work by both us and one of the shippers during the second quarter.
The
volume increase on the Mississippi System was due to increased volumes shipped
on our pipeline by Denbury for which we receive a tariff. 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 CO2
based
tertiary recovery operations, we expect Denbury to add crude oil gathering
and
CO2
supply
infrastructure to those fields, which could create opportunities for
us.
The
Jay
System in Florida/Alabama ships crude oil from fields with relatively short
remaining production lives. Recent changes in the ownership of the more mature
producing fields in the area surrounding our Jay System have led to interest
in
further development of these fields which may lead to increases in production.
Additionally, new
wells
have been drilled in the area. This new production produces greater tariff
revenue for us due to the greater distance that the crude oil is transported
on
the pipeline.
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 have
declined as a result of changes in the supply available for the two refineries
to acquire and ship on our pipeline. 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.
Sales
of
pipeline loss allowance volumes decreased $0.6 million due to a decrease in
volumetric gain volumes of approximately 8,000 barrels. These volumes are sold
at crude oil market prices.
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 failures of
equipment or power cost increases. We perform regular maintenance on our assets
in an effort to keep them in good operational condition and to minimize cost
increases. Costs in the second quarter of 2007 were higher than in the second
quarter of 2006 by a total of $0.5 million, all of which can be attributed
to
expense for our stock appreciation rights plan that relates to our pipeline
operations personnel. This expense increased by $0.6 million between the second
quarters. Slightly offsetting this expense were reductions in many other
categories of expenses.
Six
Months Ended June 30, 2007 Compared with Six Months Ended June 30,
2006
For
the
six-month periods, pipeline segment margin decreased by $1.3 million. Higher
pipeline operating costs accounted for $0.9 million of the increase, with $0.7
million of that increase due to stock appreciation rights plan expense. The
remaining $0.2 million increase in costs related to integrity management testing
and costs to tear down a tank on the Texas System to prepare the location for
its replacement. Revenues from crude oil tariffs and related sources and sales
of pipeline loss allowance volumes decreased a total of $0.1 million and net
segment margin from natural gas pipeline activities decreased by $0.3 million.
The natural gas pipeline activities were impacted by production difficulties
of
a producer attached to the system.
As
in the
second quarter periods, the decline in crude oil pipeline volumes in the six
month periods of 4,921 barrels per day did not have a significant impact on
tariff revenues, as it was attributable to the lower tariff Texas System and
was
partially offset by volumes increases on the higher tariff Mississippi
System.
Industrial
Gases Segment
Our
industrial gases segment includes the results of our CO2
sales to
industrial customers and our share of the operating income of our 50% joint
venture interests in T&P Syngas and Sandhill. Operating results from our
industrial gases segment were as follows:
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
(in
thousands)
|
|
Revenues
from CO2
sales
|
|
$
|
3,946
|
|
$
|
3,894
|
|
$
|
7,443
|
|
$
|
7,281
|
|
CO2
transportation and other costs
|
|
|
(1,281
|
)
|
|
(1,207
|
)
|
|
(2,425
|
)
|
|
(2,280
|
)
|
Equity
in earnings of joint ventures
|
|
|
293
|
|
|
339
|
|
|
554
|
|
|
652
|
|
Segment
margin
|
|
$
|
2,958
|
|
$
|
3,026
|
|
$
|
5,572
|
|
$
|
5,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2
sales - Mcf
|
|
|
75,039
|
|
|
73,495
|
|
|
71,120
|
|
|
70,049
|
|
Three
Months
Ended June 30, 2007 Compared with Three Months Ended June 30,
2006
Segment
margin from industrial gases activities was
consistent between the two second quarter periods. This margin is derived from
two sources - sales of CO2
and our
equity in the earnings of joint ventures.
CO2
Sales
We
supply
CO2
to
industrial customers under seven long-term CO2
sales
contracts. The sales contracts contain provisions for adjustments for inflation
to sales prices based on the Producer Price Index, with a minimum
price.
Our
industrial customers treat the CO2
and
transport it to their own customers. The primary industrial applications of
CO2
by these
customers include beverage carbonation and food chilling and freezing. Based
on
historical data for 2004 through 2007, we can expect some seasonality in our
sales of CO2.
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. Volumes sold each quarter in 2006
and
in the first half of 2007 were as follows:
|
|
Sales
|
|
|
|
Mcf
per Day
|
|
|
|
|
|
First
Quarter 2006
|
|
|
66,565
|
|
Second
Quarter 2006
|
|
|
73,980
|
|
Third
Quarter 2006
|
|
|
82,244
|
|
Fourth
Quarter 2006
|
|
|
68,452
|
|
First
Quarter 2007
|
|
|
67,158
|
|
Second
Quarter 2007
|
|
|
75,039
|
|
Although
CO2
sales
volumes increased 1% between the two periods, the volumes varied under contracts
such that revenues only increased by $52,000. The increased volumes and the
inflation adjustment to the rate we pay Denbury to transport the CO2
in its
pipeline to our customers resulted in greater CO2
transportation costs in the second quarter of 2007 when compared to the 2006
quarter.
Joint
Ventures
We
own a
50% interest in two joint ventures engaged in industrial gases activities,
T&P Syngas and Sandhill. T&P Syngas 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. Our share of the operating income of T&P Syngas for the three
months ended June 30, 2007 and 2006 was the same. During the second quarters
of
2007 and 2006, T&P Syngas paid us distributions totaling $0.5 million and
$0.6 million, respectively, attributable to the first quarters of the
years.
Sandhill
is engaged in the production and distribution of liquid carbon dioxide for
use
in the food, beverage, chemicals and oil industries. The facility acquires
CO2
from us
under a long-term supply contract that we acquired in 2005 from Denbury. Our
share of the operating income of Sandhill for the second quarters of 2007 and
2006 was $48,000 and $90,000, respectively, which we reduced by $69,000 for
the
amortization of excess purchase price.
Six
Months Ended June 30, 2007 Compared with Six Months Ended June 30,
2006
As
in the
three month periods, segment margin from our industrial gases segment for the
six-month periods was consistent, with a $0.1 million, or 1%, decrease,
primarily attributable to our Sandhill joint venture.
Additional
discussion of our joint ventures is included in Note 3 of the Notes to the
Unaudited Consolidated Financial Statements.
Crude
Oil Gathering and Marketing 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,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Revenues
|
|
$
|
190,735
|
|
$
|
220,828
|
|
$
|
364,014
|
|
$
|
473,273
|
|
Crude
oil costs
|
|
|
(184,535
|
)
|
|
(214,761
|
)
|
|
(352,257
|
)
|
|
(462,133
|
)
|
Field
operating costs
|
|
|
(4,773
|
)
|
|
(3,720
|
)
|
|
(8,731
|
)
|
|
(7,065
|
)
|
Segment
margin
|
|
$
|
1,427
|
|
$
|
2,347
|
|
$
|
3,026
|
|
$
|
4,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil total - barrels
|
|
|
32,429
|
|
|
35,372
|
|
|
32,931
|
(1) |
|
40,303
|
(1) |
Crude
oil truck transported only - barrels
|
|
|
4,742
|
|
|
4,258
|
|
|
4,855
|
|
|
3,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
For purposes of comparison, barrels per day before excluding
buy/sell
volumes was 43,381 for the 2007 period
and 45,670 for the 2006 period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30, 2007 as Compared to Three Months Ended June 30,
2006
Gathering
and marketing segment margins decreased $0.9 million for the three months ended
June 30, 2007, as compared to the three months ended June 30, 2006. Revenues
for
this segment are derived from sales of crude oil and from the transportation
by
truck for a fee of crude oil volumes that we did not purchase, with costs for
this segment relating to the purchase of the crude oil and the related
aggregation and transportation costs.
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 prices (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.
When
the
crude oil markets are in contango, (oil prices for future deliveries are higher
than for current deliveries), we may store crude oil as inventory in our storage
tanks that we have purchased at lower prices in the current month for delivery
at higher prices in future months. When we purchase this inventory, we
simultaneously enter into a contract to sell the inventory in the future period,
either with a counterparty or in the crude oil futures market. The maximum
storage available to us for use in this strategy is approximately 120,000
barrels, although maintenance activities on our pipelines impact the
availability of this storage capacity. 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 of
the Notes to the Unaudited 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.
Volumes
declined by 2,943 barrels per day, primarily as a result of competition and
the
elimination of contracts during the second quarter of 2006 that did not meet
our
targets for profitability. We were also impacted by fluctuations in the
differentials between the qualities of crude oil. The overall effect of the
change in volumes and differentials affected segment margin by $0.4
million.
Volumes
that we transported for a fee, but did not purchase, increased by 484 barrels
per day. Most of this increase in volume was attributable to transportation
of
Denbury’s production from their wellheads to our pipeline. The increase in the
fees for these services was $0.5 million between the two second quarter
periods.
The
primary reason for the decrease in segment margin is an increase in field
operating costs of $1.1 million when comparing the second quarter periods.
Expense related to our stock appreciation rights plan increased by $0.6 million
between the periods. Compensation costs to operate the trucks and manage our
crude oil gathering operations increased $0.4 million, as a result of
compensation increases and the use of contract personnel. Increased fuel costs
to operate our fleet of trucks accounted for most of the remaining $0.1 million
increase in costs.
Six
Months Ended June 30, 2007 as Compared to Six Months Ended June 30,
2006
For
the
six month periods, gathering and marketing segment margins decreased $1.0
million to $3.0 million for the six months ended June 30, 2007. Marketing
margins decreased $0.5 million but were offset by increased revenues from
volumes transported for a fee totaling $1.1 million. Field operating costs
increased $1.6 million for the many of the same reasons as in the quarterly
periods.
On
a
like-kind basis, volumes decreased 2,289 barrels per day, or 5%. We eliminated
contracts during the first quarter of 2006 that did not meet our targets for
profitability and we were impacted by significant volatility between crude
quality differentials between the periods, with the overall impact on margin
of
$1.1 million. The margins generated from the storage of crude oil inventory
in
the contango market were $0.6 million greater in the 2007 first six months
than
in the prior year.
The
increase in field costs was attributable to increases in the costs of personnel
to operate our trucks and manage the operations totaling $0.6 million, an
increase in stock appreciation rights expense of $0.8 million, and increased
fuel costs of $0.2 million.
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,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Expenses
excluding effect of stock appreciation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
rights
plan and bonus plan
|
|
$
|
2,650
|
|
$
|
2,299
|
|
$
|
5,189
|
|
$
|
4,464
|
|
Bonus
plan expense
|
|
|
433
|
|
|
630
|
|
|
879
|
|
|
973
|
|
Stock
appreciation rights plan expense
|
|
|
2,517
|
|
|
320
|
|
|
2,860
|
|
|
472
|
|
Total
general and administrative expenses
|
|
$
|
5,600
|
|
$
|
3,249
|
|
$
|
8,928
|
|
$
|
5,909
|
|
Between
the second quarter periods, general and administrative expenses increased by
$2.4 million, with $2.2 million attributed to increased stock appreciation
rights plan expense and the remaining $0.2 million to other costs. These other
costs included employee compensation expenses and fees for legal and other
consulting services, offset by a decrease in bonus plan expense.
For
the
six-month periods, the $3.0 million increase in general and administrative
costs
is also primarily attributable to $2.4 million of increased stock appreciation
rights plan expense. The remaining increase is related to increased employee
compensation expenses and legal and other consulting fees.
Depreciation,
amortization and impairment expense
was flat
between 2006 and 2007 second quarters, and $0.1 million greater between the
six-month periods. The increase in the six month periods relates primarily
to
amortization of our CO2
assets
due to the greater volumes sold.
Interest
expense, net.
Interest
expense, net was as follows:
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
(in
thousands)
|
|
Interest
expense, including commitment fees
|
|
$
|
289
|
|
$
|
218
|
|
$
|
498
|
|
$
|
343
|
|
Capitalized
interest
|
|
|
-
|
|
|
(2
|
)
|
|
(6
|
)
|
|
(2
|
)
|
Amortization
of facility fees
|
|
|
66
|
|
|
77
|
|
|
133
|
|
|
152
|
|
Interest
income
|
|
|
(34
|
)
|
|
(30
|
)
|
|
(78
|
)
|
|
(108
|
)
|
Net
interest expense
|
|
$
|
321
|
|
$
|
263
|
|
$
|
547
|
|
$
|
385
|
|
During
the second quarter of 2007, our average outstanding balance of debt was $2.2
million more than in the second quarter of 2006. Additionally, our average
interest rate was 0.5% greater than in the 2006 period, resulting in $71,000
more interest expense. For the six month periods, our average outstanding
balance of debt was $5.6 million greater than the prior year period, which
when
combined with an interest rate that was 0.5% greater resulted in $155,000 more
interest expense.
Liquidity
and Capital Resources
Capital
Resources
Capital
Resources/Sources
of Cash
In
the
last 12 months, we have adopted a growth strategy that has dramatically
increased our cash requirements. We now expect our capital resources to include
equity and debt offerings (public and private) and other financing transactions.
Accordingly, we expect to access the capital markets (equity and debt) from
time
to time to partially refinance our capital structure and to fund other needs
including acquisitions. Our ability to satisfy
future
capital needs with respect to our growth strategy will depend on our ability
to
raise substantial amounts of additional capital, to utilize our current credit
facility and to implement our growth strategy successfully.
In
November 2006, we entered into a credit facility with a maximum facility amount
of $500 million (replacing our $100 million facility). The initial committed
amount under our facility was $125 million, of which a maximum of $50 million
may be used for letters of credit. The committed amount represents the amount
the banks have committed to fund pursuant to the terms of the credit agreement.
The borrowing base under the facility at June 30, 2007 was approximately $79
million, and is recalculated quarterly and at the time of acquisitions. The
borrowing base represents the amount that can be borrowed or utilized for
letters of credit based on our EBITDA, computed in accordance with the
provisions of our credit facility. We increased the committed amount under
our
facility to $500 million and the maximum amount for letters of credit to $100
in
connection with the Davison transaction. As of July 31, 2007, the borrowing
base
was $380 million and our outstanding borrowings were $304 million.
The
terms
of our credit facility also effectively limit the amount of distributions that
we may pay to our general partner and holders of common units. Such
distributions may not exceed the sum of the distributable cash generated for
the
eight most recent quarters, less the sum of the distributions made with respect
to those quarters. See Note 4 of the Notes to the Unaudited Consolidated
Financial Statements.
We
financed the Davison acquisition with the issuance of 13,459,209 common units
for a total contractual value of $280 million ($20.8036 per common unit) and
cash, which we funded with borrowings under our credit facility and the issuance
of 1,074,882 common units to our general partner. Our general partner exercised
its right to maintain its proportionate ownership interest in our common units,
by purchasing these units for $22.4 million or $20.8036 per common unit.
Additionally, we received $6.2 million from the general partner to maintain
its
general partner capital account balance as required by our partnership
agreement. Other acquisitions may be initially funded primarily with debt or
equity or any combination thereof.
Uses
of Cash
Our
cash
requirements include funding day-to-day operations, maintenance and expansion
capital projects, debt service, refinancings and distributions on our common
units and other equity interests. We expect to use cash flows from operating
activities to fund cash distributions and maintenance capital expenditures
needed to sustain existing operations. Future expansion capital - acquisitions
or capital projects - will require funding through various financing
arrangements, as more particularly described under “Liquidity and Capital
Resources - Capital Resources/Sources of Cash” above.
Operating.
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. The timing of capital
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 $89.5 million aggregate receivables on our
consolidated balance sheet at June 30, 2007, approximately $88.3 million, or
98.6%, were less than 30 days past the invoice date.
Investing.
We
utilized cash flows to make capital expenditures, primarily for pipeline
improvements. We received distributions from our T&P Syngas joint venture
that exceeded our share of the earnings of T&P Syngas of $0.4 million during
the first six months of 2007. Additionally we paid $8.1 million for our
acquisition of the Port Hudson assets on June 29, 2007, and received $0.2
million from the sale of surplus assets.
Financing.
Net
cash of $8.4 million was provided by financing activities. We borrowed $14.8
million under our credit facility. We paid distributions totaling $6.0 million
to our limited partners and our general partner during the six month period,
and
expended $0.3 million on other financing activities.
Capital
Expenditures.
A
summary of our capital expenditures in the six months ended June 30, 2007 and
2006 is as follows:
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
Maintenance
capital expenditures:
|
|
|
|
|
|
|
|
Mississippi
pipeline systems
|
|
$
|
67
|
|
$
|
78
|
|
Jay
pipeline system
|
|
|
78
|
|
|
79
|
|
Texas
pipeline system
|
|
|
414
|
|
|
67
|
|
Crude
oil gathering assets
|
|
|
112
|
|
|
85
|
|
Administrative
and other assets
|
|
|
23
|
|
|
71
|
|
Total
maintenance capital expenditures
|
|
|
694
|
|
|
380
|
|
|
|
|
|
|
|
|
|
Growth
capital expenditures (including construction in progress and investments
in joint ventures)
|
|
|
|
|
|
|
|
Mississippi
pipeline systems
|
|
|
-
|
|
|
199
|
|
Sandhill
Group, LLC investment
|
|
|
-
|
|
|
5,037
|
|
Other
investment projects
|
|
|
-
|
|
|
513
|
|
Total
growth capital expenditures
|
|
|
-
|
|
|
5,749
|
|
Total
capital expenditures
|
|
$
|
694
|
|
$
|
6,129
|
|
We
have
no commitments to make capital expenditures; however, we anticipate that our
maintenance capital expenditures relating to our existing assets for 2007 will
be approximately $3.5 million. These expenditures are expected to relate
primarily to the replacement of a tank on the Texas System and replacement
of a
segment of our Jay System. 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.
As
discussed under “Acquisitions
and Related Activities in 2007 ”
above,
we closed
on
the transaction with the Davison family in the third quarter of 2007 and we
are
currently negotiating with Denbury regarding the acquisition of certain
CO2
pipeline
assets before the end of 2007.
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 eight
quarters, including the distribution to be paid for the second quarter of 2007,
as shown in the table below.
|
|
|
|
|
|
Limited
|
|
General
|
|
|
|
|
|
|
|
|
|
Partner
|
|
Partner
|
|
|
|
|
|
|
|
Per
Unit
|
|
Interests
|
|
Interest
|
|
Total
|
|
Distribution
For
|
|
Date
Paid
|
|
Amount
|
|
Amount
|
|
Amount
|
|
Amount
|
|
|
|
|
|
|
|
(in
thousands)
|
|
Fourth
quarter 2005
|
|
|
February
2006
|
|
$
|
0.17
|
|
$
|
2,343
|
|
$
|
48
|
|
$
|
2,391
|
|
First
quarter 2006
|
|
|
May
2006
|
|
$
|
0.18
|
|
$
|
2,481
|
|
$
|
51
|
|
$
|
2,532
|
|
Second
quarter 2006
|
|
|
August
2006
|
|
$
|
0.19
|
|
$
|
2,619
|
|
$
|
53
|
|
$
|
2,672
|
|
Third
quarter 2006
|
|
|
November
2006
|
|
$
|
0.20
|
|
$
|
2,757
|
|
$
|
56
|
|
$
|
2,813
|
|
Fourth
quarter 2006
|
|
|
February
2007
|
|
$
|
0.21
|
|
$
|
2,895
|
|
$
|
59
|
|
$
|
2,954
|
|
First
quarter 2007
|
|
|
May
2007
|
|
$
|
0.22
|
|
$
|
3,032
|
|
$
|
62
|
|
$
|
3,094
|
|
Second
quarter 2007
|
|
|
August
2007
|
|
$
|
0.23
|
|
$
|
3,170
|
|
$
|
65
|
|
$
|
3,235
|
|
See
Note
5 of the Notes to the Unaudited Consolidated Financial Statements.
Available
Cash before reserves for the three and six months ended June 30, 2007 is as
follows (in thousands):
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
|
|
Ended
|
|
|
|
June
30, 2007
|
|
June
30, 2007
|
|
Net
income
|
|
$
|
(1,372
|
)
|
$
|
213
|
|
Depreciation
and amortization
|
|
|
2,046
|
|
|
3,974
|
|
Cash
received from direct financing leases not included in
income
|
|
|
141
|
|
|
279
|
|
Effects
of available cash generated by investments in joint ventures not
included
in income
|
|
|
186
|
|
|
485
|
|
Non-cash
charges
|
|
|
3,050
|
|
|
3,333
|
|
Proceeds
from disposals of surplus assets
|
|
|
179
|
|
|
195
|
|
Maintenance
capital expenditures
|
|
|
(379
|
)
|
|
(694
|
)
|
Available
Cash before reserves
|
|
$
|
3,851
|
|
$
|
7,785
|
|
We
have
reconciled Available Cash before reserves (a non-GAAP liquidity measure) to
cash
flow from operating activities (the GAAP measure) for the three and six months
ended June 30, 2007 below. For the three months and six months ended June 30,
2007, cash flows provided by operating activities were $1.3 million and $3.1
million, respectively.
Non-GAAP
Financial Measure
This
quarterly report includes the financial measure of Available Cash before
reserves, which is a “non-GAAP” measure because it is not contemplated by or
referenced in accounting principles generally accepted in the U.S., also
referred to as GAAP. The accompanying schedule provides a reconciliation of
this
non-GAAP financial measure to its most directly comparable GAAP financial
measure. Our non-GAAP financial measure should not be considered as an
alternative to GAAP measures such as net income, operating income, cash flow
from operating activities or any other GAAP measure of liquidity or financial
performance. We believe that investors benefit from having access to the same
financial measures being utilized by management, lenders, analysts and other
market participants.
Available
Cash before reserves, also referred to as 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 before reserves excludes some, but not all, items that affect
net
income or loss and because these measures may vary among other companies, the
Available Cash before reserves data presented in this Quarterly Report on Form
10-Q may not be comparable to similarly titled measures of other companies.
The
GAAP measure most directly comparable to Available Cash before reserves is
net
cash provided by operating activities.
Available
Cash before reserves is a liquidity measure used by our management to compare
cash flows generated by us to the cash distribution paid to our 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 distributable cash flow) is the
quantitative standard used throughout the investment community with respect
to
publicly-traded partnerships.
The
reconciliation of Available Cash before reserves (a non-GAAP liquidity measure)
to cash flow from operating activities (the GAAP measure) for the three and
six
months ended June 30, 2007, is as follows (in thousands):
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
|
|
Ended
|
|
|
|
June
30, 2007
|
|
June
30, 2007
|
|
Cash
flows from operating activities
|
|
$
|
1,318
|
|
$
|
3,055
|
|
Adjustments
to reconcile operating cash flows to Available Cash:
|
|
|
|
|
|
|
|
Maintenance
capital expenditures
|
|
|
(379
|
)
|
|
(694
|
)
|
Proceeds
from sales of certain assets
|
|
|
179
|
|
|
195
|
|
Amortization
of credit facility issuance fees
|
|
|
(137
|
)
|
|
(273
|
)
|
Effects
of available cash generated by investments in joint ventures not
included
in cash flows from operating activities
|
|
|
70
|
|
|
206
|
|
Cash
effects of exercises under SAR Plan
|
|
|
(588
|
)
|
|
(995
|
)
|
Other
items affecting Available Cash
|
|
|
690
|
|
|
1,009
|
|
Net
effect of changes in operating accounts not included in calculation
of
Available Cash
|
|
|
2,698
|
|
|
5,282
|
|
Available
Cash before reserves
|
|
$
|
3,851
|
|
$
|
7,785
|
|
Commitments
and Off-Balance-Sheet Arrangements
Contractual
Obligation and Commercial Commitments
Our
obligations that are not currently recorded on our balance sheet consist of
our
operating leases and crude oil purchase commitments. Neither the amounts nor
the
terms of these commitments or contingent obligations have changed significantly
from the year-end 2006 amounts reflected in our Annual Report on Form 10-K.
Please refer to Management’s Discussion and Analysis of Financial Condition and
Results of Operations — “Commitments and Off-Balance Sheet Arrangements”
contained in our 2006 Form 10-K for further information regarding our
commitments and obligations.
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
above,
nor do we have any debt or equity triggers based upon our unit or commodity
prices.
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;
|
· |
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;
|
· |
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;
|
· |
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, 2006. Except as required by applicable securities
laws, we do not intend to update these forward-looking statements and
information.
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, 2007, we had entered into
NYMEX
future contracts that will settle through September 2007. 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)
|
|
|
148
|
|
|
1
|
|
Weighted
average price per bbl
|
|
$
|
67.00
|
|
$
|
70.68
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$
|
9,917
|
|
|
1
|
|
Mark-to-market
change (in thousands)
|
|
|
546
|
|
|
-
|
|
Market
settlement value (in thousands)
|
|
$
|
10,463
|
|
$
|
1
|
|
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, 2007 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 Rate or Prime Rate plus the
applicable margin. We do not hedge our interest rates. At June 30, 2007, we
had
$22.8 million of debt outstanding under our credit facility.
We
maintain disclosure controls and procedures and internal controls designed
to
ensure that information required to be disclosed in our filings under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission’s
rules and forms. Our chief executive officer and chief financial officer, with
the participation of our management, have evaluated our disclosure controls
and
procedures as of the end of the period covered by this Quarterly Report on
Form
10-Q and have determined that such disclosure controls and procedures are
effective in ensuring that material information required to be disclosed in
this
quarterly report is accumulated and communicated to them and our management
to
allow timely decisions regarding required disclosures.
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.
PART
II. OTHER INFORMATION
See
Part
I. Item 1. Note 11 to the Consolidated Financial Statements entitled
“Contingencies”, which is incorporated herein by reference.
For
additional information about our risk factors, see Item 1A of our Annual Report
on Form 10-K for the year ended December 31, 2006. In addition, we believe
that
the following additional and updated risks factors are relevant for the
businesses that we acquired from the Davison family.
Fluctuations
in commodity prices could adversely affect our business.
Oil,
natural gas, other petroleum products, and CO2
prices
are volatile and could have an adverse effect on our profits and cash flow.
Our
operations are affected by price reductions in those commodities. Price
reductions in those commodities can cause material long and short term
reductions in the level of throughput, volumes and margins in our logistic
and
supply businesses. Price changes for sodium
hydrosulfide (NaHS) and caustic soda
affect
the margins we achieve in our refinery services business acquired from the
Davison family.
Prices
for commodities can fluctuate in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our
control.
Our
refinery
services operations are dependent upon the supply of caustic soda and the demand
for NaHS, as well as the operations of the refiners for whom we process sour
gas.
Caustic
soda is a major component used in the provision of sour gas treatment services
provided by us to refineries. NaHS, the resulting product from the refinery
services we provide, is a vital ingredient in a number of industrial and
consumer products and processes. Any decrease in the supply of caustic soda
could affect our ability to provide sour gas treatment services to refiners
and
any decrease in the demand for NaHS by the parties to whom we sell the NaHS
could adversely affect our business. The refineries' need for our sour gas
services is also dependent on the competition from other refineries, the impact
of future economic conditions, fuel conservation measures, alternative fuel
requirements, government regulation or technological advances in fuel economy
and energy generation devices, all of which could reduce demand for our
services.
Our
sour
gas treatment services are dependent on contracts with fourteen
refineries.
If
one or
more of those customers experience financial difficulties or changes in their
strategy for sulfur removal such that they do not need our services, our cash
flows could be adversely affected and we cannot assure you that an unanticipated
reduction in the need for our services might not occur.
Our
operating results from
trucking operations acquired from the Davison family may fluctuate and may
be
materially adversely affected by economic conditions and business factors unique
to the trucking industry.
Our
trucking business is dependent upon factors, many of which are beyond our
control. Those factors include excess capacity in the trucking industry,
difficulty in attracting and retaining qualified drivers, significant increases
or fluctuations in fuel prices, fuel taxes, license and registration fees and
insurance and claims costs, to the extent not offset by increases in freight
rates. Our results of operations from our trucking operations also are affected
by recessionary economic cycles and downturns in customers’ business cycles.
Economic and other conditions may adversely affect our trucking customers and
their ability to pay for our services.
In
the
past, there have been shortages of drivers in the trucking industry and such
shortages may occur in the future. Periodically, the trucking industry
experiences substantial difficulty in attracting and retaining qualified
drivers. If we are unable to continue to retain and attract drivers, we could
be
required to adjust our driver compensation package, let trucks sit idle or
otherwise operate at a reduced level, which could adversely affect our
operations and profitability.
Significant
increases or rapid fluctuations in fuel prices are major issues for the
transportation industry. Increases in fuel costs, to the extent not offset
by
rate per mile increases or fuel surcharges, have an adverse effect on our
operations and profitability.
See
Note
4 and 14 of the Notes to the Unaudited Consolidated Financial
Statements.
None.
None.
None.
(a) Exhibits.
31.1
|
|
Certification
by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
31.2
|
|
Certification
by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934
|
32.1
|
|
Certification
by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
32.2
|
|
Certification
by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
|
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 9, 2007
|
By:
|
/s/
Ross
A. Benavides
|
|
|
Ross
A. Benavides
Chief
Financial Officer
|