form10q.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-Q
T QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the
quarterly period ended September 30, 2009
OR
£ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
Commission
file number 1-12295
GENESIS
ENERGY, L.P.
(Exact
name of registrant as specified in its charter)
Delaware
|
76-0513049
|
(State
or other jurisdictions of incorporation or organization)
|
(I.R.S.
Employer Identification No.)
|
|
|
919
Milam, Suite 2100, Houston, TX
|
77002
|
(Address
of principal executive offices)
|
(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 T No
£
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or such shorter period that the registrant was required to submit and
post such files).
Yes o No
£
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Large
accelerated filer £
|
Accelerated
filer T
|
Non-accelerated
filer £
|
Smaller
reporting company £
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2) of the Exchange Act).
Yes £ No
T
Indicate
the number of shares outstanding of each of the issuer’s classes of common
stock, as of the latest practicable date. Common Units outstanding as
of November 9, 2009: 39,482,971
Form
10-Q
INDEX
PART
I. FINANCIAL INFORMATION
Item
1.
|
Financial
Statements
|
Page
|
|
|
|
|
|
3
|
|
|
|
|
|
4
|
|
|
|
|
|
5
|
|
|
|
|
|
6
|
|
|
|
|
|
7
|
|
|
|
|
|
8
|
|
|
|
|
|
|
Item
2.
|
|
33
|
|
|
|
Item
3.
|
|
48
|
|
|
|
Item
4.
|
|
49
|
|
|
|
|
|
|
PART
II. OTHER INFORMATION
|
|
|
|
Item
1.
|
|
49
|
|
|
|
Item
1A.
|
|
49
|
|
|
|
Item
2.
|
|
49
|
|
|
|
Item
3.
|
|
50
|
|
|
|
Item
4.
|
|
50
|
|
|
|
Item
5.
|
|
50
|
|
|
|
Item
6.
|
|
50
|
|
|
|
|
|
|
|
51
|
UNAUDITED
CONSOLIDATED BALANCE SHEETS
(In
thousands)
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
8,700 |
|
|
$ |
18,985 |
|
Accounts
receivable - trade, net of allowance for doubtful accounts of $1,915 and
$1,132 at September 30, 2009 and December 31, 2008,
respectively
|
|
|
126,533 |
|
|
|
112,229 |
|
Accounts
receivable - related party
|
|
|
2,330 |
|
|
|
2,875 |
|
Inventories
|
|
|
38,825 |
|
|
|
21,544 |
|
Net
investment in direct financing leases, net of unearned income -current
portion - related party
|
|
|
4,088 |
|
|
|
3,758 |
|
Other
|
|
|
9,096 |
|
|
|
8,736 |
|
Total
current assets
|
|
|
189,572 |
|
|
|
168,127 |
|
|
|
|
|
|
|
|
|
|
FIXED
ASSETS, at cost
|
|
|
370,607 |
|
|
|
349,212 |
|
Less: Accumulated
depreciation
|
|
|
(83,857 |
) |
|
|
(67,107 |
) |
Net
fixed assets
|
|
|
286,750 |
|
|
|
282,105 |
|
|
|
|
|
|
|
|
|
|
NET
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related
party
|
|
|
174,108 |
|
|
|
177,203 |
|
CO2
ASSETS, net of accumulated amortization
|
|
|
21,169 |
|
|
|
24,379 |
|
EQUITY
INVESTEES AND OTHER INVESTMENTS
|
|
|
20,129 |
|
|
|
19,468 |
|
INTANGIBLE
ASSETS, net of accumulated amortization
|
|
|
144,659 |
|
|
|
166,933 |
|
GOODWILL
|
|
|
325,046 |
|
|
|
325,046 |
|
OTHER
ASSETS, net of accumulated amortization
|
|
|
6,836 |
|
|
|
15,413 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
1,168,269 |
|
|
$ |
1,178,674 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts
payable - trade
|
|
$ |
97,186 |
|
|
$ |
96,454 |
|
Accounts
payable - related party
|
|
|
3,499 |
|
|
|
3,105 |
|
Accrued
liabilities
|
|
|
28,568 |
|
|
|
26,713 |
|
Total
current liabilities
|
|
|
129,253 |
|
|
|
126,272 |
|
|
|
|
|
|
|
|
|
|
LONG-TERM
DEBT
|
|
|
384,400 |
|
|
|
375,300 |
|
DEFERRED
TAX LIABILITIES
|
|
|
16,707 |
|
|
|
16,806 |
|
OTHER
LONG-TERM LIABILITIES
|
|
|
3,079 |
|
|
|
2,834 |
|
COMMITMENTS
AND CONTINGENCIES (Note 17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS'
CAPITAL:
|
|
|
|
|
|
|
|
|
Common
unitholders, 39,483 and 39,457 units issued and outstanding, at September
30, 2009 and December 31, 2008, respectively
|
|
|
595,698 |
|
|
|
616,971 |
|
General
partner
|
|
|
16,205 |
|
|
|
16,649 |
|
Accumulated
other comprehensive loss
|
|
|
(908 |
) |
|
|
(962 |
) |
Total
Genesis Energy, L.P. partners' capital
|
|
|
610,995 |
|
|
|
632,658 |
|
Noncontrolling
interests
|
|
|
23,835 |
|
|
|
24,804 |
|
Total
partners' capital
|
|
|
634,830 |
|
|
|
657,462 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
|
$ |
1,168,269 |
|
|
$ |
1,178,674 |
|
The
accompanying notes are an integral part of these unaudited consolidated
financial statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In
thousands, except per unit amounts)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
$ |
355,604 |
|
|
$ |
554,838 |
|
|
$ |
833,658 |
|
|
$ |
1,552,559 |
|
Related
parties
|
|
|
846 |
|
|
|
1,558 |
|
|
|
3,218 |
|
|
|
3,432 |
|
Refinery
services
|
|
|
30,006 |
|
|
|
61,306 |
|
|
|
112,894 |
|
|
|
160,945 |
|
Pipeline
transportation, including natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
services - unrelated parties
|
|
|
4,009 |
|
|
|
5,062 |
|
|
|
11,442 |
|
|
|
16,139 |
|
Transportation
services - related parties
|
|
|
7,977 |
|
|
|
8,205 |
|
|
|
24,175 |
|
|
|
13,372 |
|
Natural
gas sales revenues
|
|
|
435 |
|
|
|
1,158 |
|
|
|
1,667 |
|
|
|
4,085 |
|
CO2
marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
|
3,712 |
|
|
|
4,039 |
|
|
|
9,821 |
|
|
|
10,895 |
|
Related
parties
|
|
|
800 |
|
|
|
753 |
|
|
|
2,211 |
|
|
|
2,217 |
|
Total
revenues
|
|
|
403,389 |
|
|
|
636,919 |
|
|
|
999,086 |
|
|
|
1,763,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
costs - unrelated parties
|
|
|
324,162 |
|
|
|
521,779 |
|
|
|
751,524 |
|
|
|
1,471,254 |
|
Product
costs - related parties
|
|
|
- |
|
|
|
- |
|
|
|
1,754 |
|
|
|
- |
|
Operating
costs
|
|
|
22,894 |
|
|
|
20,927 |
|
|
|
60,766 |
|
|
|
55,294 |
|
Refinery
services operating costs
|
|
|
17,160 |
|
|
|
48,265 |
|
|
|
73,711 |
|
|
|
116,700 |
|
Pipeline
transportation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
transportation operating costs
|
|
|
2,852 |
|
|
|
2,647 |
|
|
|
7,984 |
|
|
|
7,493 |
|
Natural
gas purchases
|
|
|
395 |
|
|
|
1,136 |
|
|
|
1,519 |
|
|
|
3,990 |
|
CO2
marketing costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
costs - related party
|
|
|
1,603 |
|
|
|
1,488 |
|
|
|
4,251 |
|
|
|
4,121 |
|
Other
costs
|
|
|
16 |
|
|
|
15 |
|
|
|
47 |
|
|
|
45 |
|
General
and administrative
|
|
|
10,128 |
|
|
|
9,239 |
|
|
|
27,188 |
|
|
|
26,929 |
|
Depreciation
and amortization
|
|
|
15,806 |
|
|
|
18,100 |
|
|
|
47,358 |
|
|
|
51,610 |
|
Net
loss (gain) on disposal of surplus assets
|
|
|
17 |
|
|
|
(58 |
) |
|
|
(141 |
) |
|
|
36 |
|
Total
costs and expenses
|
|
|
395,033 |
|
|
|
623,538 |
|
|
|
975,961 |
|
|
|
1,737,472 |
|
OPERATING
INCOME
|
|
|
8,356 |
|
|
|
13,381 |
|
|
|
23,125 |
|
|
|
26,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in (losses) earnings of joint ventures
|
|
|
(788 |
) |
|
|
216 |
|
|
|
1,382 |
|
|
|
378 |
|
Interest
income
|
|
|
18 |
|
|
|
118 |
|
|
|
55 |
|
|
|
352 |
|
Interest
expense
|
|
|
(3,436 |
) |
|
|
(4,601 |
) |
|
|
(9,881 |
) |
|
|
(8,543 |
) |
Income
before income taxes
|
|
|
4,150 |
|
|
|
9,114 |
|
|
|
14,681 |
|
|
|
18,359 |
|
Income
tax (expense) benefit
|
|
|
(253 |
) |
|
|
1,504 |
|
|
|
(1,661 |
) |
|
|
1,233 |
|
NET
INCOME
|
|
|
3,897 |
|
|
|
10,618 |
|
|
|
13,020 |
|
|
|
19,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncontrolling
interests
|
|
|
402 |
|
|
|
145 |
|
|
|
1,025 |
|
|
|
144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME ATTRIBUTABLE TO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GENESIS
ENERGY, L.P.
|
|
$ |
4,299 |
|
|
$ |
10,763 |
|
|
$ |
14,045 |
|
|
$ |
19,736 |
|
GENESIS
ENERGY, L.P.
UNAUDITED
CONSOLIDATED STATEMENTS
OF
OPERATIONS - CONTINUED
(In
thousands, except per unit amounts)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
PER
COMMON UNIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
|
|
$ |
0.14 |
|
|
$ |
0.25 |
|
|
$ |
0.43 |
|
|
$ |
0.45 |
|
DILUTED
|
|
$ |
0.14 |
|
|
$ |
0.25 |
|
|
$ |
0.43 |
|
|
$ |
0.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
UNITS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
|
|
|
39,480 |
|
|
|
39,452 |
|
|
|
39,467 |
|
|
|
38,796 |
|
DILUTED
|
|
|
39,614 |
|
|
|
39,524 |
|
|
|
39,600 |
|
|
|
38,853 |
|
The
accompanying notes are an integral part of these unaudited consolidated
financial statements.
UNAUDITED
CONSOLIDATED STATEMENTS
OF
COMPREHENSIVE INCOME
(In
thousands)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
3,897 |
|
|
$ |
10,618 |
|
|
$ |
13,020 |
|
|
$ |
19,592 |
|
Change
in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
period reclassification to earnings
|
|
|
224 |
|
|
|
(5 |
) |
|
|
514 |
|
|
|
(5 |
) |
Changes
in derivative financial instruments - interest rate swaps
|
|
|
(315 |
) |
|
|
(211 |
) |
|
|
(400 |
) |
|
|
(211 |
) |
Comprehensive
income
|
|
|
3,806 |
|
|
|
10,402 |
|
|
|
13,134 |
|
|
|
19,376 |
|
Comprehensive
loss (income) attributable to noncontrolling interests
|
|
|
46 |
|
|
|
110 |
|
|
|
(60 |
) |
|
|
110 |
|
Comprehensive
income attributable to Genesis Energy, L.P.
|
|
$ |
3,852 |
|
|
$ |
10,512 |
|
|
$ |
13,074 |
|
|
$ |
19,486 |
|
The
accompanying notes are an integral part of these unaudited consolidated
financial statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In
thousands)
|
|
Partners' Capital
|
|
|
|
Number
of Common Units
|
|
|
Common
Unitholders
|
|
|
General
Partner
|
|
|
Accumulated
Other Comprehensive Loss
|
|
|
Non-
Controlling Interests
|
|
|
Total
Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
capital, January 1, 2009
|
|
|
39,457 |
|
|
$ |
616,971 |
|
|
$ |
16,649 |
|
|
$ |
(962 |
) |
|
$ |
24,804 |
|
|
$ |
657,462 |
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
- |
|
|
|
17,892 |
|
|
|
(3,847 |
) |
|
|
- |
|
|
|
(1,025 |
) |
|
|
13,020 |
|
Interest
rate swap losses reclassified to interest expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
251 |
|
|
|
263 |
|
|
|
514 |
|
Interest
rate swap loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(197 |
) |
|
|
(203 |
) |
|
|
(400 |
) |
Cash
contributions
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
Cash
distributions
|
|
|
- |
|
|
|
(39,958 |
) |
|
|
(4,191 |
) |
|
|
- |
|
|
|
(4 |
) |
|
|
(44,153 |
) |
Contribution
for executive compensation (See Note 12)
|
|
|
- |
|
|
|
- |
|
|
|
7,587 |
|
|
|
- |
|
|
|
- |
|
|
|
7,587 |
|
Unit
based compensation expense
|
|
|
26 |
|
|
|
793 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
793 |
|
Partners'
capital, September 30, 2009
|
|
|
39,483 |
|
|
$ |
595,698 |
|
|
$ |
16,205 |
|
|
$ |
(908 |
) |
|
$ |
23,835 |
|
|
$ |
634,830 |
|
|
|
Partners' Capital
|
|
|
|
Number
of Common Units
|
|
|
Common
Unitholders
|
|
|
General
Partner
|
|
|
Accumulated
Other Comprehensive Loss
|
|
|
Non-
Controlling Interests
|
|
|
Total
Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
capital, January 1, 2008
|
|
|
38,253 |
|
|
$ |
615,265 |
|
|
$ |
16,539 |
|
|
$ |
- |
|
|
$ |
570 |
|
|
$ |
632,374 |
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
- |
|
|
|
17,972 |
|
|
|
1,764 |
|
|
|
- |
|
|
|
(144 |
) |
|
|
19,592 |
|
Interest
rate swap loss reclassified to interest expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(5 |
) |
Interest
rate swap loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(104 |
) |
|
|
(107 |
) |
|
|
(211 |
) |
Cash
contributions
|
|
|
- |
|
|
|
- |
|
|
|
510 |
|
|
|
- |
|
|
|
25,505 |
|
|
|
26,015 |
|
Cash
distributions
|
|
|
- |
|
|
|
(34,805 |
) |
|
|
(2,017 |
) |
|
|
- |
|
|
|
(4 |
) |
|
|
(36,826 |
) |
Issuance
of units
|
|
|
2,037 |
|
|
|
41,667 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
41,667 |
|
Redemption
of units
|
|
|
(838 |
) |
|
|
(16,667 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(16,667 |
) |
Partners'
capital, September 30, 2008
|
|
|
39,452 |
|
|
$ |
623,432 |
|
|
$ |
16,796 |
|
|
$ |
(106 |
) |
|
$ |
25,817 |
|
|
$ |
665,939 |
|
The
accompanying notes are an integral part of these unaudited consolidated
financial statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In
thousands)
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
13,020 |
|
|
$ |
19,592 |
|
Adjustments
to reconcile net income to net cash provided by operating activities
-
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
47,358 |
|
|
|
51,610 |
|
Amortization
of credit facility issuance costs
|
|
|
1,448 |
|
|
|
962 |
|
Amortization
of unearned income and initial direct costs on direct financing
leases
|
|
|
(13,606 |
) |
|
|
(6,342 |
) |
Payments
received under direct financing leases
|
|
|
16,390 |
|
|
|
6,056 |
|
Equity
in earnings of investments in joint ventures
|
|
|
(1,382 |
) |
|
|
(378 |
) |
Distributions
from joint ventures - return on investment
|
|
|
800 |
|
|
|
971 |
|
Non-cash
effect of unit-based compensation plans
|
|
|
10,345 |
|
|
|
(1,342 |
) |
Deferred
and other tax liabilities
|
|
|
1,084 |
|
|
|
(3,388 |
) |
Other
non-cash items
|
|
|
(283 |
) |
|
|
(1,031 |
) |
Net
changes in components of operating assets and liabilities (See Note
13)
|
|
|
(19,343 |
) |
|
|
(10,480 |
) |
Net
cash provided by operating activities
|
|
|
55,831 |
|
|
|
56,230 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Payments
to acquire fixed and intangible assets
|
|
|
(28,656 |
) |
|
|
(29,890 |
) |
CO2
pipeline transactions and related costs
|
|
|
- |
|
|
|
(228,891 |
) |
Distributions
from joint ventures - return of investment
|
|
|
- |
|
|
|
886 |
|
Investments
in joint ventures and other investments
|
|
|
(83 |
) |
|
|
(2,210 |
) |
Acquisition
of Grifco assets
|
|
|
- |
|
|
|
(65,693 |
) |
Other,
net
|
|
|
500 |
|
|
|
(213 |
) |
Net
cash used in investing activities
|
|
|
(28,239 |
) |
|
|
(326,011 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Bank
borrowings
|
|
|
174,300 |
|
|
|
490,900 |
|
Bank
repayments
|
|
|
(165,200 |
) |
|
|
(179,500 |
) |
Credit
facility issuance fees
|
|
|
- |
|
|
|
(2,255 |
) |
Redemption
of common units for cash
|
|
|
- |
|
|
|
(16,667 |
) |
General
partner contributions
|
|
|
7 |
|
|
|
510 |
|
Net
noncontrolling interest (distributions) contributions
|
|
|
(4 |
) |
|
|
25,501 |
|
Distributions
to common unitholders
|
|
|
(39,958 |
) |
|
|
(34,805 |
) |
Distributions
to general partner interest
|
|
|
(4,191 |
) |
|
|
(2,017 |
) |
Other,
net
|
|
|
(2,831 |
) |
|
|
(1,366 |
) |
Net
cash (used in) provided by financing activities
|
|
|
(37,877 |
) |
|
|
280,301 |
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(10,285 |
) |
|
|
10,520 |
|
Cash
and cash equivalents at beginning of period
|
|
|
18,985 |
|
|
|
11,851 |
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at end of period
|
|
$ |
8,700 |
|
|
$ |
22,371 |
|
The
accompanying notes are an integral part of these unaudited consolidated
financial statements.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
and Basis of Presentation and Consolidation
Organization
We are a
growth-oriented limited partnership focused on the midstream segment of the oil
and gas industry in the Gulf Coast area of the United States. We
conduct our operations through our operating subsidiaries and joint
ventures. We manage our businesses through four
divisions:
|
·
|
Pipeline
transportation of crude oil and carbon
dioxide;
|
|
·
|
Refinery
services involving processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and sale of the related by-product,
sodium hydrosulfide (or NaHS, commonly pronounced
nash);
|
|
·
|
Supply
and logistics services, which includes terminaling, blending, storing,
marketing, and transporting by trucks and barges of crude oil and
petroleum products; and
|
|
·
|
Industrial
gas activities, including wholesale marketing of CO2 and
processing of syngas through a joint
venture.
|
Our 2%
general partner interest is held by Genesis Energy, LLC, a Delaware limited
liability company and an indirect subsidiary of Denbury Resources
Inc. Denbury and its subsidiaries are hereafter referred to as
Denbury. Our general partner and its affiliates also own 10.2% of our
outstanding common units.
Our
general partner manages our operations and activities and employs our officers
and personnel, who devote 100% of their efforts to our management.
Basis
of Presentation and Consolidation
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 consolidated 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
consolidated financial statements and notes thereto included in our Annual
Report on Form 10-K for the year ended December 31, 2008.
Except
per unit amounts, or as noted within the context of each footnote disclosure,
the dollar amounts presented in the tabular data within these footnote
disclosures are stated in thousands of dollars.
The
accompanying unaudited consolidated financial statements and related notes
present our consolidated financial position as of September 30, 2009 and
December 31, 2008 and our results of operations and changes in comprehensive
income for the three and nine months ended September 30, 2009 and 2008, and cash
flows and changes in partners’ capital for the nine months ended September 30,
2009 and 2008. Intercompany transactions have been
eliminated. The accompanying unaudited consolidated financial
statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis
Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their
subsidiaries.
We
participate in three joint ventures: DG Marine Transportation, LLC
(DG Marine), T&P Syngas Supply Company (T&P Syngas) and Sandhill Group,
LLC (Sandhill). We acquired our interest in DG Marine in July 2008,
and, since then DG Marine has been consolidated in our financial
statements. We account for our 50% investments in T&P Syngas and
Sandhill by the equity method of accounting.
Our
general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P.
and TD Marine, LLC (TD Marine), a related party, owns a 51% economic interest in
DG Marine. The net interest of our general partner and TD Marine in
our results of operations and financial position are reflected in our financial
statements as noncontrolling interests.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Subsequent
Events
We have
considered subsequent events through November 9, 2009, the date of issuance, in
preparing the consolidated financial statements and notes thereto.
2. Recent
Accounting Developments
Pending
Measuring
Liabilities and Fair Value
In August
2009, the FASB issued guidance that provides clarification to the valuation
techniques required to measure the fair value of liabilities. The guidance also
provides clarification around required inputs to the fair value measurement of a
liability and definition of a Level 1 liability. The guidance is effective for
interim and annual periods beginning after August 2009. We will adopt this
standard beginning with our financial statements for the year ending December
31, 2009. We do not anticipate that our adoption of this standard will have a
material effect on our financial statements.
Consolidation
of Variable Interest Entities (“VIEs”)
In June
2009, the FASB issued authoritative guidance to amend the manner in which
entities evaluate whether consolidation is required for VIEs. The
model for determining which enterprise has a controlling financial interest and
is the primary beneficiary of a VIE has changed significantly under the new
guidance. Previously, variable interest holders had to determine
whether they had a controlling interest in a VIE based on a quantitative
analysis of the expected gains and/or losses of the entity. In
contrast, the new guidance requires an enterprise with a variable interest in a
VIE to qualitatively assess whether it has a controlling interest in the entity,
and if so, whether it is the primary beneficiary. Furthermore, this
guidance requires that companies continually evaluate VIEs for consolidation,
rather than assessing based upon the occurrence of triggering
events. This revised guidance also requires enhanced disclosures
about how a company’s involvement with a VIE affects its financial statements
and exposure to risks. This guidance is effective for us beginning
January 1, 2010. We are currently assessing the impacts this guidance
may have on our financial statements.
Implemented
Accounting
Standards Codification
In June
2009, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 168, “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162,” (The Codification). The
Codification establishes the FASB Accounting Standards Codification (ASC) as the
source of authoritative U.S. generally accepted accounting principles (GAAP)
recognized by the FASB to be applied by nongovernmental entities. The
Codification reorganizes GAAP pronouncements by topic and modifies the GAAP
hierarchy to include only two levels: authoritative and
non-authoritative. All of the content in the Codification carries the
same level of authority. This statement was effective for financial
statements issued for interim and annual periods ending after September 15,
2009. We adopted the Codification on September 30,
2009. Thus, subsequent references to GAAP in our consolidated
financial statements will refer exclusively to the Codification.
Recognized
and Non-Recognized Subsequent Events
In May
2009, the FASB issued new guidance for accounting for subsequent
events. The new guidance, which is now part of Accounting Standards
Codification (ASC) 855, “Subsequent Events”, establishes the accounting for and
disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. It
requires the disclosure of the date through which an entity has evaluated
subsequent events and the basis for that date, that is, whether that date
represents the date the financial statements were issued or were available to be
issued. See “Subsequent Events” included in “Note 1 – Organization
and Basis of Presentation and Consolidation” for the related disclosure. The new
guidance was applied prospectively beginning in the second quarter of 2009 and
did not have a material impact on our consolidated financial
statements.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Disclosures
about Fair Value of Financial Instruments
In April
2009, the FASB issued new guidance regarding interim disclosures about the fair
value of financial instruments. The new guidance, which is now part
of ASC 825, “Financial Instruments”, requires fair value disclosures on an
interim basis for financial instruments that are not reflected in the
consolidated balance sheets at fair value. Previously, the fair values of those
financial instruments were only disclosed on an annual basis. We adopted the new
guidance for our quarter ended June 30, 2009, and there was no material impact
on our consolidated financial statements.
Business
Combinations
In
December 2007, the FASB issued revised guidance for the accounting of business
combinations. The revised guidance, which is now part of ASC 805,
“Business Combinations”, retains the purchase method of accounting used in
business combinations but replaces superseded guidance by establishing
principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction costs
and restructuring costs be charged to expense as incurred. In
addition, the revised guidance requires disclosures to enable users of the
financial statements to evaluate the nature and financial effects of the
business combination. The revised guidance will apply to acquisitions
we make after December 31, 2008. The impact to us will be dependent
on the nature of the business combination.
Noncontrolling
Interests in Consolidated Financial Statements
In
December 2007, the FASB issued guidance regarding noncontrolling interests in
consolidated financial statements. The new guidance, which is now a part of ASC
810, “Consolidation”, establishes accounting and reporting standards for
noncontrolling interests, which were referred to as minority interests in prior
literature. A noncontrolling interest is the portion of equity in a
subsidiary not attributable, directly or indirectly, to a parent
company. The new guidance requires, among other things, that (i)
ownership interests of noncontrolling interests be presented as a component of
equity on the balance sheet (i.e. elimination of the mezzanine “minority
interest” category); (ii) elimination of minority interest expense as a line
item on the statement of operations and, as a result, that net income be
allocated between the parent and the noncontrolling interests on the face of the
statement of operations; and (iii) enhanced disclosures regarding noncontrolling
interests. The provisions of the new guidance were effective for
fiscal years beginning after December 15, 2008. On January 1, 2009,
we adopted the new guidance which changed the presentation of the interests in
Genesis Crude Oil, L.P. held by our general partner and the interests in DG
Marine held by our joint venture partner in our consolidated financial
statements. Amounts for prior periods have been changed to be
consistent with the presentation required by the new guidance.
Derivative
Instruments and Hedging Activities
In
March 2008, the FASB issued new guidance regarding disclosures about derivative
instruments and hedging activities. The new guidance, which is now a part of ASC
815, “Derivatives and Hedging Activities”, require enhanced disclosures about
our derivative and hedging activities. This guidance was effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. We adopted the guidance on January 1, 2009 and have included the
enhanced disclosures in Note 15.
Application
of the Two-Class Method to Master Limited Partnerships
In March
2008, the FASB issued new guidance in ASC 260, “Earnings per Share”, regarding
the application of the two-class method to Master Limited
Partnerships. Under this guidance, the computation of earnings per
unit will be affected by the incentive distribution rights (“IDRs”) we are
contractually obligated to distribute at the end of the each reporting
period. In periods when earnings are in excess of cash distributions,
we will reduce net income or loss for the current reporting period (for purposes
of calculating earnings or loss per unit only) by the amount of available cash
that will be distributed to our limited partners and general partner for its
general partner interest and incentive distribution rights for the reporting
period, and the remainder will be allocated to the limited partner and general
partner in accordance with their ownership interests. When cash
distributions exceed current-period earnings, net income or loss (for purposes
of calculating earnings or loss per unit only) will be reduced (or increased) by
cash distributions, and the resulting excess of distributions over earnings will
be allocated to the general partner and limited partner based on their
respective sharing of losses. The new guidance was effective for
fiscal years beginning after December 15, 2008, and interim periods within those
fiscal years. We adopted ASC 260 on January 1, 2009 and have
reflected the calculation of earnings per unit for the three and nine months
ended September 30, 2009 and 2008 in accordance with its
provisions. See Note 9.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Determination
of the Useful Life of Intangible Assets
In April
2008, the FASB issued revised guidance, which is now a part of ASC 350,
“Intangibles – Goodwill and Other”, regarding the determination of the useful
life of intangible assets. The revised guidance amends the factors
that should be considered in developing renewal or extension assumptions used to
determine the useful life of an intangible asset under superseded
guidance. The purpose of the revised guidance is to develop
consistency between the useful life assigned to intangible assets and the cash
flows from those assets. The revised guidance was effective for
fiscal years beginning after December 31, 2008. We adopted the
provisions of the revised guidance on January 1, 2009, and adoption had no
effect on our consolidated financial statements.
Fair
Value Measurements
We
adopted new guidance issued by the FASB regarding fair value measurements for
our financial assets and financial liabilities on January 1, 2008, which is now
a part of ASC 820, “Fair Value Measurements and Disclosures.” The
adoption or financial assets and financial liabilities did not have a material
impact on us. With regard to our non-recurring non-financial assets
and non-financial liabilities, we adopted the provisions of this guidance
effective January 1, 2009. This includes applying the provisions to
(i) nonfinancial assets and liabilities initially measured at fair value in
business combinations; (ii) reporting units or nonfinancial assets and
liabilities measured at fair value in conjunction with goodwill impairment
testing, (iii) other nonfinancial assets measured at fair value in conjunction
with impairment assessments; and (iv) asset retirement obligations initially
measured at fair value. The adoption for non-financial assets and
liabilities does not require any new fair value measurements, but rather applies
to all other accounting pronouncements that require or permit fair value
measurements. The adoption of the guidance for non-financial assets
and liabilities as described above had no material impact on us. See
Note 16 for further information regarding fair-value measurements.
3. Consolidated
Joint Venture – DG Marine
DG Marine
is a joint venture we formed with TD Marine. TD Marine owns (indirectly) a 51%
economic interest in DG Marine, and we own (directly and indirectly) a 49%
economic interest. This joint venture gives us the capability to
provide transportation services of petroleum products by barge and complements
our other supply and logistics operations.
We have
entered into a subordinated loan agreement with DG Marine whereby we may (at our
sole discretion) lend up to $25 million to DG Marine. The loan
agreement provides for DG Marine to pay us interest on any loans at the prime
rate plus 4%. Those loans will mature on January 31,
2012. Under that subordinated loan agreement, DG Marine is required
to make monthly payments to us of principal and interest to the extent DG Marine
has any available cash that otherwise would have been distributed to the owners
of DG Marine in respect of their equity interest. DG Marine also has
a revolving credit facility with a syndicate of financial institutions that
includes restrictions on DG Marine’s ability to make specified payments under
our subordinated loan agreement and distributions in respect of our equity
interest. At December 31, 2008, there were no amounts outstanding
under the subordinated loan agreement. At September 30, 2009,
$17 million was outstanding under the subordinated loan agreement; however this
amount was eliminated in consolidation. In October 2009, we loaned an
additional $8 million to DG Marine.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
At
September 30, 2009 and December 31, 2008, our unaudited consolidated balance
sheets included the following amounts related to DG Marine:
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
Cash
|
|
$ |
1,308 |
|
|
$ |
623 |
|
Accounts
receivable - trade
|
|
|
3,176 |
|
|
|
2,812 |
|
Other
current assets
|
|
|
2,432 |
|
|
|
859 |
|
Fixed
assets, at cost
|
|
|
124,276 |
|
|
|
110,214 |
|
Accumulated
depreciation
|
|
|
(7,492 |
) |
|
|
(3,084 |
) |
Intangible
assets, net
|
|
|
1,871 |
|
|
|
2,208 |
|
Other
assets
|
|
|
1,535 |
|
|
|
2,178 |
|
Total
assets
|
|
$ |
127,106 |
|
|
$ |
115,810 |
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
1,448 |
|
|
$ |
1,072 |
|
Accrued
liabilities
|
|
|
10,853 |
|
|
|
9,258 |
|
Long-term
debt
|
|
|
49,400 |
|
|
|
55,300 |
|
Other
long-term liabilities
|
|
|
906 |
|
|
|
1,393 |
|
Total
liabilities
|
|
$ |
62,607 |
|
|
$ |
67,023 |
|
4. Inventories
Inventories
are valued at the lower of cost or market. The costs of inventories
did not exceed market values at September 30, 2009. The costs of inventories at
December 31, 2008 exceeded market values by approximately $1.2 million, and are
reflected below at those market values. The major components of
inventories were as follows:
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
Crude
oil
|
|
|
16,358 |
|
|
|
1,878 |
|
Petroleum
products
|
|
|
18,781 |
|
|
|
5,589 |
|
Caustic
soda
|
|
|
993 |
|
|
|
7,139 |
|
NaHS
|
|
|
2,677 |
|
|
|
6,923 |
|
Other
|
|
|
16 |
|
|
|
15 |
|
Total
inventories
|
|
$ |
38,825 |
|
|
$ |
21,544 |
|
5. Fixed
Assets and Asset Retirement Obligations
Fixed
assets consisted of the following:
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
Land,
buildings and improvements
|
|
$ |
13,635 |
|
|
$ |
13,549 |
|
Pipelines
and related assets
|
|
|
153,379 |
|
|
|
139,184 |
|
Machinery
and equipment
|
|
|
26,533 |
|
|
|
22,899 |
|
Transportation
equipment
|
|
|
32,811 |
|
|
|
32,833 |
|
Barges
and push boats
|
|
|
122,913 |
|
|
|
96,865 |
|
Office
equipment, furniture and fixtures
|
|
|
4,295 |
|
|
|
4,401 |
|
Construction
in progress
|
|
|
4,488 |
|
|
|
27,906 |
|
Other
|
|
|
12,553 |
|
|
|
11,575 |
|
Subtotal
|
|
|
370,607 |
|
|
|
349,212 |
|
Accumulated
depreciation and impairment
|
|
|
(83,857 |
) |
|
|
(67,107 |
) |
Total
|
|
$ |
286,750 |
|
|
$ |
282,105 |
|
Depreciation
expense was $6.3 million and $19.4 million for the three and nine months ended
September 30, 2009, respectively. For the three and nine months ended
September 30, 2008, depreciation expense was $6.5 million and $16.8 million,
respectively.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Asset
Retirement Obligations
The
following table summarizes the changes in our asset retirement obligations for
the nine months ended September 30, 2009.
Asset
retirement obligations as of December 31, 2008
|
|
$ |
1,430 |
|
Liabilities
incurred and assumed in the period
|
|
|
726 |
|
Liabilities
settled in the period
|
|
|
(117 |
) |
Accretion
expense
|
|
|
91 |
|
Asset
retirement obligations as of September 30, 2009
|
|
|
2,130 |
|
Less
current portion included in accrued liabilities
|
|
|
(150 |
) |
Long-term
asset retirement obligations as of September 30, 2009
|
|
$ |
1,980 |
|
Certain
of our unconsolidated affiliates have asset retirement obligations recorded at
September 30, 2009 and December 31, 2008 relating to contractual
agreements. These amounts are immaterial to our financial
statements.
6. Intangible
Assets and Goodwill
Intangible
Assets
The
following table reflects the components of intangible assets being amortized at
the dates indicated:
|
|
|
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
|
|
Weighted Amortization Period in
Years
|
|
|
Gross Carrying Amount
|
|
|
Accumulated Amortization
|
|
|
Carrying Value
|
|
|
Gross Carrying Amount
|
|
|
Accumulated Amortization
|
|
|
Carrying Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
relationships:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
services
|
|
5 |
|
|
$ |
94,654 |
|
|
$ |
37,592 |
|
|
$ |
57,062 |
|
|
$ |
94,654 |
|
|
$ |
26,017 |
|
|
$ |
68,637 |
|
Supply
and logistics
|
|
5 |
|
|
|
35,430 |
|
|
|
14,109 |
|
|
|
21,321 |
|
|
|
35,430 |
|
|
|
9,957 |
|
|
|
25,473 |
|
Supplier
relationships -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
services
|
|
2 |
|
|
|
36,469 |
|
|
|
27,534 |
|
|
|
8,935 |
|
|
|
36,469 |
|
|
|
24,483 |
|
|
|
11,986 |
|
Licensing
Agreements -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
services
|
|
6 |
|
|
|
38,678 |
|
|
|
10,555 |
|
|
|
28,123 |
|
|
|
38,678 |
|
|
|
7,176 |
|
|
|
31,502 |
|
Trade
names -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics
|
|
7 |
|
|
|
18,888 |
|
|
|
4,863 |
|
|
|
14,025 |
|
|
|
18,888 |
|
|
|
3,118 |
|
|
|
15,770 |
|
Favorable
lease -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics
|
|
15 |
|
|
|
13,260 |
|
|
|
1,026 |
|
|
|
12,234 |
|
|
|
13,260 |
|
|
|
671 |
|
|
|
12,589 |
|
Other
|
|
5 |
|
|
|
3,823 |
|
|
|
864 |
|
|
|
2,959 |
|
|
|
1,322 |
|
|
|
346 |
|
|
|
976 |
|
Total
|
|
5 |
|
|
$ |
241,202 |
|
|
$ |
96,543 |
|
|
$ |
144,659 |
|
|
$ |
238,701 |
|
|
$ |
71,768 |
|
|
$ |
166,933 |
|
We are
recording amortization of our intangible assets based on the period over which
the asset is expected to contribute to our future cash
flows. Generally, the contribution to our cash flows of the customer
and supplier relationships, licensing agreements and trade name intangible
assets is expected to decline over time, such that greater value is attributable
to the periods shortly after the acquisition was made. The favorable
lease and other intangible assets are being amortized on a straight-line
basis. Amortization expense on intangible assets was $8.3 million and
$24.8 million for the three and nine months ended September 30, 2009,
respectively. Amortization expense on intangible assets was $11.6
million and $34.8 million for the three and nine months ended September 30,
2008, respectively.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Estimated
amortization expense for each of the five subsequent fiscal years is expected to
be as follows:
Year Ended December 31
|
|
Amortization
Expense to be
Recorded
|
|
Remainder
of 2009
|
|
$ |
8,328 |
|
2010
|
|
$ |
26,635 |
|
2011
|
|
$ |
21,918 |
|
2012
|
|
$ |
18,261 |
|
2013
|
|
$ |
14,264 |
|
2014
|
|
$ |
11,790 |
|
Goodwill
The
carrying amount of goodwill by business segment at September 30, 2009 and
December 31, 2008 was $302.0 million to refinery services and $23.1 million to
supply and logistics.
7. Equity
Investees and Other Investments
T&P
Syngas Supply Company
We are
accounting for our 50% ownership in T&P Syngas under the equity method of
accounting. We received distributions from T&P Syngas of $0.8
million and $1.7 million during the nine months ended September 30, 2009 and
2008, respectively. During the first quarter of 2009, “Equity in
earnings of joint ventures” included $1.7 million of non-cash items related to
T&P Syngas that increased earnings.
The
tables below reflect summarized financial information for T&P
Syngas:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,217 |
|
|
$ |
1,054 |
|
|
$ |
3,368 |
|
|
$ |
3,487 |
|
Operating
expenses and depreciation
|
|
|
(2,809 |
) |
|
|
(392 |
) |
|
|
(3,907 |
) |
|
|
(1,124 |
) |
Other
income (expense)
|
|
|
(12 |
) |
|
|
(11 |
) |
|
|
1 |
|
|
|
4 |
|
Net
(loss) income
|
|
$ |
(1,604 |
) |
|
$ |
651 |
|
|
$ |
(538 |
) |
|
$ |
2,367 |
|
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
3,016 |
|
|
$ |
3,131 |
|
Non-current
assets
|
|
|
17,728 |
|
|
|
18,906 |
|
Total
assets
|
|
$ |
20,744 |
|
|
$ |
22,037 |
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
1,372 |
|
|
$ |
543 |
|
Non-current
liabilities
|
|
|
213 |
|
|
|
198 |
|
Partners'
capital
|
|
|
19,159 |
|
|
|
21,296 |
|
Total
liabilities and partners' capital
|
|
$ |
20,744 |
|
|
$ |
22,037 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
8. Debt
At
September 30, 2009, our obligations under credit facilities consisted of the
following:
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
Genesis
Credit Facility
|
|
$ |
335,000 |
|
|
$ |
320,000 |
|
DG
Marine Credit Facility
|
|
|
49,400 |
|
|
|
55,300 |
|
Total
Long-Term Debt
|
|
$ |
384,400 |
|
|
$ |
375,300 |
|
Genesis
Credit Facility
We have a
$500 million credit facility, $100 million of which can be used for letters of
credit, with a group of banks led by Fortis Capital Corp. and Deutsche Bank
Securities Inc. Due to the revolving nature of loans under our credit
facility, we may repay and re-borrow amounts until the maturity date of November
15, 2011. Our borrowing base is recalculated quarterly and at the
time of material acquisitions. Our borrowing base represents the
amount that we can borrow or utilize for letters of credit, and it is calculated
based on our EBITDA (earnings before interest, taxes, depreciation and
amortization), as defined in accordance with the provisions of our credit
facility. Our borrowing base may be increased to the extent of pro
forma additional EBITDA, (as defined in the credit agreement), attributable to
acquisitions or internal growth projects with approval of the
lenders.
As of
September 30, 2009, our borrowing base was $419 million, and we had $335 million
borrowed and $4.1 million in letters of credit outstanding. Thus, our
total remaining availability at September 30, 2009 was $79.9 million under our
credit facility. As discussed above, our borrowing base may be
increased up to $500 million for material acquisitions and internal growth
projects.
DG
Marine Credit Facility
DG Marine
has a $90 million revolving credit facility with a syndicate of banks led by
SunTrust Bank and BMO Capital Markets Financing, Inc. That facility, which
matures on July 18, 2011, is secured by all of the equity interests issued by DG
Marine and substantially all of DG Marine’s assets. Other than the
pledge of our equity interest in DG Marine, that facility is non-recourse to
us. At September 30, 2009, our Unaudited Consolidated Balance Sheet
included $127.1 million of DG Marine’s assets in our total assets.
At
September 30, 2009, DG Marine had $49.4 million outstanding under its credit
facility. As DG Marine has completed its capital expenditures
for its fleet expansion, DG Marine reduced the maximum amount that may be
borrowed under its facility to $54 million in November 2009.
In August
2008, DG Marine entered into a series of interest rate swap agreements to
effectively fix the underlying LIBOR rate on $32.9 million of its borrowings
under its credit facility through July 18, 2011. The fixed interest rates in the
swap agreements range from the three-month interest rate of 3.60% in effect at
September 30, 2009 to 4.68% at July 18, 2011.
Fair Value of our
Debt
We have
estimated the total fair value of our long-term debt under our credit agreement
and the DG Marine credit facility to be approximately $371.4 million, or $13.0
million less than the carrying value of that debt. As a result of the
current credit environment, we believe that the fair value of our debt does not
approximate its carrying value as of September 30, 2009 because the applicable
interest rate margin on our debt was below the market rates as of
that date.
9. Partners’
Capital and Distributions
Partners’
Capital
Partner’s
capital at September 30, 2009 consists of 39,482,971 common units, including
4,028,096 units owned by our general partner and its affiliates, representing a
98% aggregate ownership interest in the Partnership and its subsidiaries (after
giving effect to the general partner interest), and a 2% general partner
interest.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Our
general partner owns all of our general partner interest, our incentive
distribution rights, and all of the 0.01% general partner interest in Genesis
Crude Oil, L.P. (which is reflected as a noncontrolling interest in our
Unaudited Consolidated Balance Sheets) and operates our business.
Without
obtaining unitholder approval, we may issue an unlimited number of additional
limited partner interests and other equity securities, the proceeds from which
could be used to provide additional funds for acquisitions or other
needs.
Distributions
We will
distribute 100% of our available cash (as defined by our partnership agreement)
within 45 days after the end of each quarter to unitholders of record and to our
general partner. Available cash consists generally of all of our cash
receipts less cash disbursements adjusted for net changes to
reserves.
Pursuant
to our partnership agreement, our general partner receives incremental incentive
cash distributions when unitholders’ cash distributions exceed certain target
thresholds. The allocations of distributions between our common
unitholders and our general partner (including its general partner interest and
the incentive distribution rights) are as follows:
|
|
Unitholders
|
|
|
General Partner
|
|
Quarterly
Cash Distribution per Common Unit:
|
|
|
|
|
|
|
Up
to and including $0.25 per Unit
|
|
|
98.00 |
% |
|
|
2.00 |
% |
First
Target - $0.251 per Unit up to and including $0.28 per
Unit
|
|
|
84.74 |
% |
|
|
15.26 |
% |
Second
Target - $0.281 per Unit up to and including $0.33 per
Unit
|
|
|
74.53 |
% |
|
|
25.47 |
% |
Over
Second Target - Cash distributions greater than $.033 per
Unit
|
|
|
49.02 |
% |
|
|
50.98 |
% |
We paid
or will pay the following distributions in 2008 and 2009:
Distribution For
|
|
Date Paid
|
|
Per Unit Amount
|
|
|
Limited Partner Interests
Amount
|
|
|
General Partner Interest
Amount
|
|
|
General Partner Incentive Distribution
Amount
|
|
|
Total Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
quarter 2008
|
|
August
2008
|
|
$ |
0.3150 |
|
|
$ |
12,427 |
|
|
$ |
254 |
|
|
$ |
633 |
|
|
$ |
13,314 |
|
Third
quarter 2008
|
|
November
2008
|
|
$ |
0.3225 |
|
|
$ |
12,723 |
|
|
$ |
260 |
|
|
$ |
728 |
|
|
$ |
13,711 |
|
Fourth
quarter 2008
|
|
February
2009
|
|
$ |
0.3300 |
|
|
$ |
13,021 |
|
|
$ |
266 |
|
|
$ |
823 |
|
|
$ |
14,110 |
|
First
quarter 2009
|
|
May
2009
|
|
$ |
0.3375 |
|
|
$ |
13,317 |
|
|
$ |
271 |
|
|
$ |
1,125 |
|
|
$ |
14,713 |
|
Second
quarter 2009
|
|
August
2009
|
|
$ |
0.3450 |
|
|
$ |
13,621 |
|
|
$ |
278 |
|
|
$ |
1,427 |
|
|
$ |
15,326 |
|
Third
quarter 2009
|
|
November
2009 (1)
|
|
$ |
0.3525 |
|
|
$ |
13,918 |
|
|
$ |
284 |
|
|
$ |
1,729 |
|
|
$ |
15,931 |
|
(1) This
distribution will be paid on November 13, 2009 to our general partner and
unitholders of record as of November 2, 2009.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Net
Income Allocation to Partners
Net income is allocated to our partners
in the Consolidated Statements of Partners’ Capital as follows:
|
·
|
To
our general partner – income in the amount of the incentive distributions
paid in the period.
|
|
·
|
To
our general partner – expense in the amount of the executive compensation
expense to be borne by our general partner (See Note
12).
|
|
·
|
To
our limited partners and general partner – the remainder of net income in
the ratio of 98% to the limited partners and 2% to our general
partner.
|
Net
Income Per Common Unit
Our net
income is first allocated to our general partner based on the amount of
incentive distributions to be paid for the quarter. New accounting
guidance issued by the FASB, effective January 1, 2009 for us, resulted in a
change in the calculation of net income per common unit by changing the amount
of the incentive distributions to be considered in the calculation from the
distributions paid during the quarter to the distributions to be paid with
respect to the quarter. As required by the new accounting guidance,
we have retrospectively applied the provisions of the new accounting guidance to
the calculation of net income per common unit for the periods in 2008 in the
table below. As a result, basic and diluted net income per common
unit remained the same as compared to amounts previously reported for the three
months ended September 30, 2008. However, basic and diluted net
income decreased by $0.02 and $0.01, respectively, from the amounts previously
reported for the nine months ended September 30, 2008.
We then
allocate to our general partner the expense related to the Class B Membership
Awards to our executive officers, as our general partner will bear the cash cost
of those awards. The remainder of our net income is then allocated
98% to our limited partners and 2% to our general partner. Basic net
income per limited partner unit is determined by dividing net income
attributable to limited partners by the weighted average number of outstanding
limited partner units during the period. Diluted net income per
common unit is calculated in the same manner, but also considers the impact to
common units for the potential dilution from phantom units outstanding. (See
Note 12 for discussion of phantom units.)
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
following table sets forth the computation of basic and diluted net income per
common unit.
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Numerators
for basic and diluted net income per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to Genesis Energy, L.P.
|
|
$ |
4,299 |
|
|
$ |
10,763 |
|
|
$ |
14,045 |
|
|
$ |
19,736 |
|
Less:
General partner's incentive distribution to to be paid for the
period
|
|
|
(1,729 |
) |
|
|
(728 |
) |
|
|
(4,281 |
) |
|
|
(1,790 |
) |
Add: Expense
for Class B Membership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards
(Note 12)
|
|
|
3,088 |
|
|
|
- |
|
|
|
7,587 |
|
|
|
- |
|
Subtotal
|
|
|
5,658 |
|
|
|
10,035 |
|
|
|
17,351 |
|
|
|
17,946 |
|
Less:
General partner 2% ownership
|
|
|
(113 |
) |
|
|
(201 |
) |
|
|
(347 |
) |
|
|
(359 |
) |
Income
available for common unitholders
|
|
$ |
5,545 |
|
|
$ |
9,834 |
|
|
$ |
17,004 |
|
|
$ |
17,587 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
39,480 |
|
|
|
39,452 |
|
|
|
39,467 |
|
|
|
38,796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for diluted per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
39,480 |
|
|
|
39,452 |
|
|
|
39,467 |
|
|
|
38,796 |
|
Phantom
Units
|
|
|
134 |
|
|
|
72 |
|
|
|
133 |
|
|
|
57 |
|
|
|
|
39,614 |
|
|
|
39,524 |
|
|
|
39,600 |
|
|
|
38,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per common unit
|
|
$ |
0.14 |
|
|
$ |
0.25 |
|
|
$ |
0.43 |
|
|
$ |
0.45 |
|
Diluted
net income per common unit
|
|
$ |
0.14 |
|
|
$ |
0.25 |
|
|
$ |
0.43 |
|
|
$ |
0.45 |
|
10. Business
Segment Information
Our
operations consist of four operating segments: (1) Pipeline
Transportation – interstate and intrastate crude oil and CO2; (2)
Refinery Services – processing high sulfur (or “sour”) gas streams as part of
refining operations to remove the sulfur and selling the related by-product; (3)
Supply and Logistics – terminaling, blending, storing, marketing, gathering and
transporting crude oil and petroleum products by truck and barge, and (4)
Industrial Gases – the sale of CO2 acquired
under volumetric production payments to industrial customers and our investment
in a syngas processing facility. Substantially all of our revenues are derived
from, and substantially all of our assets are located in the United
States.
During
the fourth quarter of 2008, we revised the manner in which we internally
evaluate our segment performance. As a result, we changed our
definition of segment margin to include within segment margin all costs that are
directly associated with the business segment. Segment margin now
includes costs such as general and administrative expenses that are directly
incurred by the business segment. Segment margin also includes all
payments received under direct financing leases. In order to improve
comparability between periods, we exclude from segment margin the non-cash
effects of our stock-based compensation plans which are impacted by changes in
the market price for our common units. Segment information for the
three and nine months ended September 30, 2008 has been retrospectively revised
to conform to this segment presentation. We now define segment margin
as revenues less cost of sales, operating expenses (excluding non-cash charges,
such as depreciation and amortization), and segment general and administrative
expenses, plus our equity in distributable cash generated by our joint
ventures. Our segment margin definition also excludes the non-cash
effects of our stock-based compensation plans, and includes the non-income
portion of payments received under direct financing leases. Our chief
operating decision maker (our Chief Executive Officer) evaluates segment
performance based on a variety of measures including segment margin, segment
volumes where relevant and maintenance capital investment.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Pipeline Transportation
|
|
|
Refinery Services
|
|
|
Supply &Logistics
|
|
|
Industrial Gases (a)
|
|
|
Total
|
|
Three Months Ended September 30,
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (b)
|
|
$ |
10,269 |
|
|
$ |
12,694 |
|
|
$ |
9,423 |
|
|
$ |
2,893 |
|
|
$ |
35,279 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
capital expenditures
|
|
$ |
451 |
|
|
$ |
162 |
|
|
$ |
723 |
|
|
$ |
- |
|
|
$ |
1,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
10,729 |
|
|
$ |
31,365 |
|
|
$ |
356,783 |
|
|
$ |
4,512 |
|
|
$ |
403,389 |
|
Intersegment
(d)
|
|
|
1,692 |
|
|
|
(1,359 |
) |
|
|
(333 |
) |
|
|
- |
|
|
|
- |
|
Total
revenues of reportable segments
|
|
$ |
12,421 |
|
|
$ |
30,006 |
|
|
$ |
356,450 |
|
|
$ |
4,512 |
|
|
$ |
403,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (b)
|
|
$ |
11,474 |
|
|
$ |
11,486 |
|
|
$ |
9,754 |
|
|
$ |
3,906 |
|
|
$ |
36,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
capital expenditures
|
|
$ |
261 |
|
|
$ |
351 |
|
|
$ |
1,371 |
|
|
$ |
- |
|
|
$ |
1,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
11,836 |
|
|
$ |
63,492 |
|
|
$ |
556,799 |
|
|
$ |
4,792 |
|
|
$ |
636,919 |
|
Intersegment
(d)
|
|
|
2,589 |
|
|
|
(2,186 |
) |
|
|
(403 |
) |
|
|
- |
|
|
|
- |
|
Total
revenues of reportable segments
|
|
$ |
14,425 |
|
|
$ |
61,306 |
|
|
$ |
556,396 |
|
|
$ |
4,792 |
|
|
$ |
636,919 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Pipeline Transportation
|
|
|
Refinery Services
|
|
|
Supply &Logistics
|
|
|
Industrial Gases (a)
|
|
|
Total
|
|
Nine Months Ended September 30,
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (b)
|
|
$ |
30,841 |
|
|
$ |
38,643 |
|
|
$ |
21,979 |
|
|
$ |
8,785 |
|
|
$ |
100,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures (c)
|
|
$ |
2,963 |
|
|
$ |
2,029 |
|
|
$ |
22,274 |
|
|
$ |
83 |
|
|
$ |
27,349 |
|
Maintenance
capital expenditures
|
|
$ |
1,201 |
|
|
$ |
704 |
|
|
$ |
1,853 |
|
|
$ |
- |
|
|
$ |
3,758 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
32,927 |
|
|
$ |
117,193 |
|
|
$ |
836,934 |
|
|
$ |
12,032 |
|
|
$ |
999,086 |
|
Intersegment
(d)
|
|
|
4,357 |
|
|
|
(4,299 |
) |
|
|
(58 |
) |
|
|
- |
|
|
|
- |
|
Total
revenues of reportable segments
|
|
$ |
37,284 |
|
|
$ |
112,894 |
|
|
$ |
836,876 |
|
|
$ |
12,032 |
|
|
$ |
999,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin (b)
|
|
$ |
23,396 |
|
|
$ |
40,195 |
|
|
$ |
21,595 |
|
|
$ |
10,791 |
|
|
$ |
95,977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures (c)
|
|
$ |
80,926 |
|
|
$ |
2,700 |
|
|
$ |
111,575 |
|
|
$ |
2,210 |
|
|
$ |
197,411 |
|
Maintenance
capital expenditures
|
|
$ |
463 |
|
|
$ |
856 |
|
|
$ |
1,648 |
|
|
$ |
- |
|
|
$ |
2,967 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
27,509 |
|
|
$ |
167,824 |
|
|
$ |
1,555,199 |
|
|
$ |
13,112 |
|
|
$ |
1,763,644 |
|
Intersegment
(d)
|
|
|
6,087 |
|
|
|
(6,879 |
) |
|
|
792 |
|
|
|
- |
|
|
|
- |
|
Total
revenues of reportable segments
|
|
$ |
33,596 |
|
|
$ |
160,945 |
|
|
$ |
1,555,991 |
|
|
$ |
13,112 |
|
|
$ |
1,763,644 |
|
|
a)
|
Industrial
gases includes our CO2
marketing operations and our equity income from our investments in T&P
Syngas and Sandhill.
|
|
b)
|
A
reconciliation of segment margin to income before income taxes and
noncontrolling interests for the periods presented is as
follows:
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
35,279 |
|
|
$ |
36,620 |
|
|
$ |
100,248 |
|
|
$ |
95,977 |
|
Corporate
general and administrative expenses
|
|
|
(9,141 |
) |
|
|
(4,743 |
) |
|
|
(24,218 |
) |
|
|
(15,729 |
) |
Depreciation
and amortization
|
|
|
(15,806 |
) |
|
|
(18,100 |
) |
|
|
(47,358 |
) |
|
|
(51,610 |
) |
Net
(loss) gain on disposal of surplus assets
|
|
|
(17 |
) |
|
|
58 |
|
|
|
141 |
|
|
|
(36 |
) |
Interest
expense, net
|
|
|
(3,418 |
) |
|
|
(4,483 |
) |
|
|
(9,826 |
) |
|
|
(8,191 |
) |
Non-cash
(credits) expenses not included in segment margin
|
|
|
(1,008 |
) |
|
|
1,080 |
|
|
|
(1,850 |
) |
|
|
927 |
|
Other
non-cash items affecting segment margin
|
|
|
(1,739 |
) |
|
|
(1,318 |
) |
|
|
(2,456 |
) |
|
|
(2,979 |
) |
Income
before income taxes
|
|
$ |
4,150 |
|
|
$ |
9,114 |
|
|
$ |
14,681 |
|
|
$ |
18,359 |
|
|
c)
|
Capital
expenditures include fixed asset additions and acquisitions of
businesses.
|
|
d)
|
Intersegment
sales were conducted on an arm’s length
basis.
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
11. 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:
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Truck
transportation services provided to Denbury
|
|
$ |
2,616 |
|
|
$ |
2,343 |
|
Pipeline
transportation services provided to Denbury
|
|
$ |
10,481 |
|
|
$ |
6,899 |
|
Payments
received under direct financing leases from Denbury
|
|
$ |
16,390 |
|
|
$ |
6,056 |
|
Pipeline
transportation income portion of direct financing lease
fees
|
|
$ |
13,754 |
|
|
$ |
6,450 |
|
Pipeline
monitoring services provided to Denbury
|
|
$ |
90 |
|
|
$ |
80 |
|
Directors'
fees paid to Denbury
|
|
$ |
150 |
|
|
$ |
147 |
|
CO2
transportation services provided by Denbury
|
|
$ |
4,029 |
|
|
$ |
4,120 |
|
Crude
oil purchases from Denbury
|
|
$ |
1,754 |
|
|
$ |
- |
|
Operations,
general and administrative services provided by our general
partner
|
|
$ |
38,999 |
|
|
$ |
38,669 |
|
Distributions
to our general partner on its limited partner units and general partner
interest, including incentive distributions
|
|
$ |
7,055 |
|
|
$ |
4,563 |
|
Sales
of CO2 to
Sandhill
|
|
$ |
2,211 |
|
|
$ |
2,217 |
|
Petroleum
products sales to Davison family businesses
|
|
$ |
602 |
|
|
$ |
1,089 |
|
Transportation
Services
We
provide truck transportation services to Denbury to move its crude oil from the
wellhead to our Mississippi pipeline. Denbury pays us a fee for that
trucking service which varies with the distance we haul its crude
oil. Those fees are reflected in the Unaudited Consolidated
Statements of Operations as supply and logistics revenues.
Denbury
is the only shipper (other than us) on our Mississippi pipeline, and we earn
tariffs for transporting its oil. We earned fees from Denbury for the
transportation of its CO2 on our
Free State pipeline. We also earned fees from Denbury under the
direct financing lease arrangements for the Olive and Brookhaven crude oil
pipelines and the Brookhaven and NEJD CO2
pipelines. The fees from those arrangements are recorded as pipeline
transportation income.
We also
provide pipeline monitoring services to Denbury. That revenue is
included in pipeline revenues in our Unaudited Consolidated Statements of
Operations.
Directors’
Fees
We paid
Denbury for the services of each of its officers who serve as directors of our
general partner. The annual rate and rate for attendance at meetings
are the same as the rates at which our other directors were paid.
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 nine months of 2009, the
inflation-adjusted transportation fee averaged $0.2004 per Mcf.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Operations,
General and Administrative Services
We do not
directly employ any persons to manage or operate our business. Those
functions and personnel are provided by our general partner. We
reimburse our general partner for all direct and indirect costs of those
services, excluding any payments to our management team pursuant to their Class
B Membership Interests. See Note 12.
Amounts
due to and from Related Parties
At
September 30, 2009 and December 31, 2008, we owed Denbury $1.1 million and $1.0
million, respectively, for CO2
transportation charges and purchases of crude oil. Denbury owed us
$1.5 million and $2.0 million for transportation services at September 30, 2009
and December 31, 2008, respectively. We owed our general partner $2.3
million and $2.1 million for administrative services at September 30, 2009 and
December 31, 2008, respectively. Sandhill owed us $0.8 million and
$0.7 million for purchases of CO2 at
September 30, 2009 and December 31, 2008, respectively.
DG
Marine Joint Venture
Our
partner in the DG Marine joint venture is TD Marine, a joint venture consisting
of three members of the Davison family. We acquired our refinery
services segment as well as certain other businesses from the Davison family in
2007. In connection with that transaction, members of the Davison
family, collectively, became our largest unitholder group.
Financing
Our
credit facility is non-recourse to our general partner, except to the extent of
its pledge of its 0.01% general partner interest in Genesis Crude Oil,
L.P. Our general partner’s principal assets are its general and
limited partnership interests in us. Our credit agreement obligations
are not guaranteed by Denbury or any of its other subsidiaries.
We
guarantee 50% of the obligation of Sandhill to a bank. At September
30, 2009, the total amount of Sandhill’s obligation to the bank was $2.65
million; therefore, our guarantee was for $1.33 million.
Approximately
14% of the outstanding common shares of Community Trust Bank are held by Davison
family members. Community Trust Bank is a 17% participant in the DG
Marine credit facility. James E. Davison, Jr., a member of our board
of directors, also serves on the board of the holding company that owns
Community Trust Bank.
As
discussed in Note 12, we recorded a non-cash capital contribution from our
general partner of $7.6 million for the nine months ended September 30, 2009
related to the Class B Membership Awards for our executive management
team.
12. Equity-Based
Compensation
We
recorded charges and credits related to our equity-based compensation plans and
awards for three and nine months ended September 30, 2009 and 2008 as
follows:
Expense (Credits to Expense)
Related to Equity-Based Compensation
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
Statement of Operations
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Pipeline
operating costs
|
|
$ |
124 |
|
|
$ |
(87 |
) |
|
$ |
208 |
|
|
$ |
(206 |
) |
Refinery
services operating costs
|
|
|
139 |
|
|
|
(8 |
) |
|
|
289 |
|
|
|
44 |
|
Supply
and logistics operating costs
|
|
|
481 |
|
|
|
(146 |
) |
|
|
910 |
|
|
|
(198 |
) |
General
and administrative expenses
|
|
|
3,710 |
|
|
|
(367 |
) |
|
|
9,041 |
|
|
|
(594 |
) |
Total
|
|
$ |
4,454 |
|
|
$ |
(608 |
) |
|
$ |
10,448 |
|
|
$ |
(954 |
) |
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Stock
Appreciation Rights Plan
The
following table reflects rights activity under our plan during the nine months
ended September 30, 2009:
Stock Appreciation Rights
|
|
Rights
|
|
|
Weighted Average Exercise
Price
|
|
|
Weighted Average Contractual Remaining Term
(Yrs)
|
|
|
Aggregate Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at January 1, 2009
|
|
|
1,017,985 |
|
|
$ |
18.09 |
|
|
|
|
|
|
|
Granted
during 2009
|
|
|
228,212 |
|
|
$ |
13.00 |
|
|
|
|
|
|
|
Exercised
during 2009
|
|
|
(16,336 |
) |
|
$ |
14.62 |
|
|
|
|
|
|
|
Forfeited
or expired during 2009
|
|
|
(77,034 |
) |
|
$ |
18.54 |
|
|
|
|
|
|
|
Outstanding
at September 30, 2009
|
|
|
1,152,827 |
|
|
$ |
17.13 |
|
|
|
5.9 |
|
|
$ |
1,171 |
|
Exercisable
at September 30, 2009
|
|
|
477,006 |
|
|
$ |
17.73 |
|
|
|
6.0 |
|
|
$ |
997 |
|
The
weighted-average fair value at September 30, 2009 of rights granted during the
first nine months of 2009 was $3.59 per right, determined using the following
assumptions:
Assumptions
Used for Fair Value of Rights
|
|
Granted in 2009
|
|
Expected
life of rights (in years)
|
|
|
5.75 |
|
Risk-free
interest rate
|
|
|
2.61 |
% |
Expected
unit price volatility
|
|
|
44.09 |
% |
Expected
future distribution yield
|
|
|
8.50 |
% |
The total
intrinsic value of rights exercised during the first nine months of 2009 was
less than $0.1 million, which was paid in cash to the participants.
At
September 30, 2009, there was $1.2 million of total unrecognized compensation
cost related to rights that we expect will vest under the plan. For the awards
outstanding at September 30, 2009, the remaining cost will be recognized over a
weighted average period of two years.
2007
Long Term Incentive Plan
The
following table summarizes information regarding our non-vested Phantom Unit
grants as of September 30, 2009:
Non-vested
Phantom Unit Grants
|
|
Number
of Units
|
|
|
Weighted-Average
Grant-Date Fair Value
|
|
|
|
|
|
|
|
|
Non-vested
at January 1, 2009
|
|
|
78,388 |
|
|
$ |
19.32 |
|
Granted
|
|
|
82,501 |
|
|
$ |
8.14 |
|
Vested
|
|
|
(27,347 |
) |
|
$ |
19.19 |
|
Forfeited
|
|
|
(3,500 |
) |
|
$ |
8.88 |
|
Non-vested
at September 30, 2009
|
|
|
130,042 |
|
|
$ |
12.54 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
weighted-average fair value of Phantom Units granted during 2009 was determined
using the following assumptions:
Grant
Date Price
|
|
$ |
10.19 |
|
Expected
Distribution Rate
|
|
$ |
0.33 |
|
Risk
Free Rate
|
|
|
0.73%
- 1.50 |
% |
The
aggregate grant date fair value of Phantom Unit awards granted during the nine
months ended September 30, 2009 was $0.7 million. As of September 30,
2009, there was $0.7 million of unrecognized compensation expense related to
these units. This unrecognized compensation cost is expected to be
recognized over a weighted-average period of two years.
Class
B Membership Interests
As part
of finalizing the compensation arrangements for our Senior Executives on
December 31, 2008, our general partner awarded them an equity interest in our
general partner as long-term incentive compensation. These Class B Membership
Interests compensate the holders thereof by providing rewards based on increased
shares of the cash distributions attributable to our incentive distribution
rights (or IDRs) (See Note 9) to the extent we increase Cash Available Before
Reserves, or CABR (defined below) (from which we pay distributions on our common
units) above specified targets. CABR generally means Available
Cash before Reserves, less Available Cash before Reserves generated from
specific transactions with our general partner and its affiliates (including
Denbury Resources Inc.) The Class B Membership Interests do not provide any
Senior Executive with a direct interest in any assets (including our IDRs) owned
by our general partner.
Our
general partner has agreed that it will not seek reimbursement (on behalf of
itself or its affiliates) under our partnership agreement for the costs of these
Senior Executive compensation arrangements to the extent relating to their
ownership of Class B Membership Interests (including current cash distributions
made by the general partner out of its IDRs and payment of redemption amounts
for those IDRs) and the deferred compensation amounts. Although our
general partner will not seek reimbursement for the costs of the Class B
Membership Interests and deferred compensation plan arrangements, we will record
non-cash compensation expense attributable to such costs. The
Class B Membership Interests awarded to our senior executives are accounted for
as liability awards under the accounting guidance for stock-based
compensation. As such, the fair value of the compensation cost we
record for these awards is recomputed at each measurement date through final
settlement and the expense to be recorded is adjusted based on that fair
value. This expense will be recorded on an accelerated basis to align
with the requisite service period of the awards.
Management’s
estimates of the fair value of these awards are based on assumptions regarding a
number of future events, including estimates of the Available Cash before
Reserves we will generate each quarter through the final vesting date of
December 31, 2012, estimates of the future amount of incentive distributions we
will pay to our general partner, and assumptions about appropriate discount
rates. Changes in our assumptions will change the amount of
compensation cost we record. Additionally, the determination of fair
value is affected by the distribution yield of a group of publicly-traded
entities that are general partners in publicly-traded master limited
partnerships, a factor over which we have no control. These
assumptions were used to estimate the total amount that would be paid under the
Class B Membership awards through the final vesting date.
At
September 30, 2009, management estimates that the fair value of the Class B
Membership Awards and the related deferred compensation awards granted to our
Senior Executives is approximately $22.9 million. Management’s
estimates of fair value were made in order to record non-cash compensation
expense over the vesting period, and do not necessarily represent the
contractual amounts payable under these awards at September 30,
2009. For the three and nine months ended September 30, 2009, we
recorded expense of $3.1 million and $7.6 million,
respectively.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
13. Supplemental
Cash Flow Information
The
following table provides information regarding the net changes in components of
operating assets and liabilities.
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Decrease
(increase) in:
|
|
|
|
|
|
|
Accounts
receivable
|
|
$ |
(7,513 |
) |
|
$ |
(23,670 |
) |
Inventories
|
|
|
(15,048 |
) |
|
|
(6,481 |
) |
Other
current assets
|
|
|
(523 |
) |
|
|
(3,214 |
) |
Increase
(decrease) in:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
4,071 |
|
|
|
17,076 |
|
Accrued
liabilities
|
|
|
(330 |
) |
|
|
5,809 |
|
Net
changes in components of operating assets and liabilities, net of working
capital acquired
|
|
$ |
(19,343 |
) |
|
$ |
(10,480 |
) |
Cash
received by us for interest for the nine months ended September 30, 2009 and
2008 was $42,000 and $118,000, respectively. Payments of interest and
commitment fees were $10.9 million and $8.2 million for the nine months ended
September 30, 2009 and 2008, respectively.
Cash paid
for income taxes during the nine months ended September 30, 2009 and 2008 was
$1.0 million and $0.4 million, respectively.
At
September 30, 2009, we had incurred liabilities for fixed asset and other asset
additions totaling $0.3 million that had not been paid at the end of the third
quarter, and, therefore, are not included in the caption “Payments to acquire
fixed and intangible assets” and “Other, net” under investing activities on the
Unaudited Consolidated Statements of Cash Flows. At September 30,
2008, we had incurred $0.5 million of liabilities that had not been paid at that
date and are not included in “Payments to acquire fixed and intangible assets”
under investing activities. Additionally, $1.0 million of fixed
assets were reclassified to supplies in “Other Current Assets” in our Unaudited
Consolidated Balance Sheets at September 30, 2009 due to the expected short-term
utilization of the assets.
In May
2008, we issued common units with a value of $25 million as part of the
consideration for the acquisition of the Free State Pipeline from
Denbury. In July 2008, we issued common units with a value of $16.7
million as part of the consideration for the acquisition of the inland marine
transportation assets of Grifco. These common unit issuances are non-cash
transactions and the value of the assets acquired is not included in investing
activities and the issuance of the common units is not reflected under financing
activities in our Unaudited Consolidated Statements of Cash Flows for the nine
months ended September 30, 2008.
14. Major
Customers and Credit Risk
Due to
the nature of our supply and logistics operations, a disproportionate percentage
of our trade receivables consist of obligations of energy
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 accounted for 12% and 15% of total revenues in the nine months ended
September 30, 2009 and 2008, respectively. The majority of the
revenues from this customer in both periods relate to our crude oil supply and
logistics operations.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
15. Derivatives
On
January 1, 2009, we adopted new accounting guidance which require enhanced
disclosures about (1) how and why we use derivative instruments, (2) how
derivative instruments and related hedged items are accounted for by us and (3)
how derivative instruments and related hedged items affect our financial
position, financial performance and cash flows.
Commodity
Derivatives
We have
exposure to commodity price changes related to our inventory and purchase
commitments. We utilize derivative instruments (primarily futures and
options contracts traded on the NYMEX) to hedge our exposure to commodity
prices, primarily crude oil, fuel oil and petroleum products; however, only a
portion of these instruments are designated as hedges under the accounting
guidance. Our decision as to whether to designate derivative instruments as fair
value hedges for accounting purposes relates to our expectations of the length
of time we expect to have the commodity price exposure and our expectations as
to whether the derivative contract will qualify as highly effective under
accounting guidance in limiting our exposure to commodity price
risk. Most of the petroleum products, including fuel oil,that we
supply cannot be hedged with a high degree of effectiveness with derivative
contracts available on the NYMEX; therefore, we do not designate derivative
contracts utilized to limit our price risk related to these products as hedges
for accounting purposes. Typically we utilize crude oil and natural
gas futures and option contracts to limit our exposure to the effect of
fluctuations in petroleum products prices on the future sale of our inventory or
commitments to purchase petroleum products, and we recognize any changes in fair
value of the derivative contracts as increases or decreases in our cost of
sales. The recognition of changes in fair value of the derivative
contracts not designated as hedges for accounting purposes can occur in
reporting periods that do not coincide with the recognition of gain or loss on
the actual transaction being hedged. Therefore we will, on occasion,
report gains or losses in one period that will be partially offset by gains or
losses in a future period when the hedged transaction is completed.
We have
designated certain crude oil futures contracts as hedges of crude oil inventory
due to our expectation that these contracts will be highly effective in hedging
our exposure to fluctuations in crude oil prices during the period that we
expect to hold that inventory. We account for these derivative
instruments as fair value hedges under the accounting
guidance. Changes in the fair value of these derivative instruments
designated as fair value hedges are used to offset related changes in the fair
value of the hedged crude oil inventory. Any hedge ineffectiveness in
these fair value hedges and any amounts excluded from effectiveness testing are
recorded as a gain or loss in the consolidated statements of
operations.
In
accordance with NYMEX requirements, we fund the margin associated with our loss
positions on commodity derivative contracts traded on the NYMEX. The
amount of the margin is adjusted daily based on the fair value of the commodity
contracts. The margin requirements are intended to mitigate a party’s
exposure to market volatility and the associated contracting party
risk. We offset fair value amounts recorded for our NYMEX derivative
contracts against margin funding as required by the NYMEX in Other Current
Assets in our Unaudited Consolidated Balance Sheets.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
At
September 30, 2009, we had the following outstanding derivative commodity
futures, forwards and options contracts that were entered into to hedge
inventory or fixed price purchase commitments:
|
|
Sell (Short) Contracts
|
|
|
Buy (Long) Contracts
|
|
Designated
as hedges under accounting rules:
|
|
|
|
|
|
|
Crude
oil futures:
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
253 |
|
|
|
74 |
|
Weighted
average contract price per bbl
|
|
$ |
66.03 |
|
|
$ |
68.96 |
|
|
|
|
|
|
|
|
|
|
Not
qualifying or not designated as hedges under accounting
rules:
|
|
|
|
|
|
|
|
|
Crude
oil futures:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
66 |
|
|
|
- |
|
Weighted
average contract price per bbl
|
|
$ |
68.80 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Heating
oil futures:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
93 |
|
|
|
- |
|
Weighted
average contract price per gal
|
|
$ |
1.86 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
RBOB
gasoline futures:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average contract price per gal
|
|
$ |
1.80 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
#6
Fuel Oil futures:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
30 |
|
|
|
- |
|
Weighted
average contract price per bbl
|
|
$ |
1.44 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Crude
oil written calls:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
35 |
|
|
|
- |
|
Weighted
average premium received
|
|
$ |
2.29 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Heating
oil written calls:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average premium received
|
|
$ |
3.94 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Natural
gas written calls:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average premium received
|
|
$ |
3.48 |
|
|
$ |
- |
|
Interest
Rate Derivatives
DG Marine
utilizes swap contracts with financial institutions to hedge interest payments
for $32.9 million of its outstanding debt through July 2011. The
weighted average interest rate of these swap contracts is 4.26%. DG
Marine expects these interest rate swap contracts to be highly effective in
limiting its exposure to fluctuations in market interest rates, therefore, we
have designated these swap contracts as cash flow hedges under accounting
guidance. The effective portion of the derivative represents the
change in fair value of the hedge that offsets the change in cash flows of the
hedged item. The effective portion of the gain or loss in the fair
value of these swap contracts is reported as a component of Accumulated Other
Comprehensive Income (Loss) (AOCI) and reclassified into future earnings
contemporaneously as interest expense associated with the underlying debt under
the DG Marine credit facility is recorded. To the extent that the
change in the fair value of the interest rate swaps does not perfectly offset
the change in the fair value of our exposure to interest rates, the ineffective
portion of the hedge will be immediately recognized in interest expense in our
Unaudited Consolidated Statements of Operations.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Financial
Statement Impacts
The
following table summarizes the accounting treatment and classification of our
derivative instruments on our Unaudited Consolidated Financial
Statements.
|
|
|
|
Impact of Unrealized Gains and
Losses
|
Derivative Instrument
|
|
Hedged Risk
|
|
Unaudited Consolidated Balance
Sheets
|
|
Unaudited Consolidated Statements of
Operations
|
Designated
as hedges under accounting guidance:
|
|
|
|
|
|
|
Crude
oil futures contracts (fair value hedge)
|
|
Volatility
in crude oil prices - effect on market value of inventory
|
|
Derivative
is recorded in Other Current Assets (offset against margin deposits) and
offsetting change in fair value of inventory is recorded in
Inventory
|
|
Excess,
if any, over effective portion of hedge is recorded in Supply and
Logistics - Cost of Sales. Effective portion is offset in Cost of Sales
against change in value of inventory being hedged
|
|
|
|
|
|
|
|
Interest
rate swaps (cash flow hedge)
|
|
Changes
in interest rates
|
|
Entire
hedge is recorded in Accrued Liabilities or Other Liabilities depending on
duration
|
|
Expect
hedge to fully offset hedged risk; no ineffectiveness recorded. Effective
portion is recorded in interest expense.
|
|
|
|
|
|
|
|
Not
qualifying or not designated as hedges under accounting
guidance:
|
|
|
|
|
|
|
Commodity
hedges consisting of crude oil, heating oil and natural gas futures and
forward contracts and call options
|
|
Volatility
in crude oil and petroleum products prices - effect on market value of
inventory or purchase commitments.
|
|
Derivative
is recorded in Other Current Assets (offset against margin deposits) or
Accrued Liabilities
|
|
Entire
amount of change in fair
value of derivative is recorded in Supply and Logistics - Cost of
Sales
|
Unrealized
gains are subtracted from net income and unrealized losses are added to net
income in determining cash flows from operating
activities. Additionally, the offsetting change in the fair value of
inventory that is recorded for our fair value hedges is also eliminated from net
income in determining cash flows from operating
activities. Changes in margin deposits necessary to fund
unrealized losses also affect cash flows from operating
activities.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
following tables reflected the estimated fair value gain (loss) position of our
hedge derivatives and related inventory impact for qualifying hedges at
September 30, 2009:
|
|
Fair
Value of Derivative Assets and Liabilities
|
|
|
Derivative Assets
|
|
Unaudited Consolidated Balance Sheets
Location
|
|
Derivative Liabilities
|
|
|
Unaudited Consolidated Balance Sheets
Location
|
Commodity
derivatives - futures and call options:
|
|
|
|
|
|
|
|
|
|
Hedges
designated under accounting guidance as fair value hedges
|
|
$ |
142 |
|
Other
Current Assets
|
|
$ |
(1,199 |
)(1) |
|
Other
Current Assets
|
Undesignated
hedges
|
|
|
120 |
|
Other
Current Assets
|
|
|
(668 |
)(1) |
|
Other
Current Assets
|
Total
commodity derivatives
|
|
|
262 |
|
|
|
|
(1,867 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swaps designated as cash flow hedges under accounting
rules:
|
|
|
|
|
|
|
|
|
|
|
|
Portion
expected to be reclassified into earnings within one year
|
|
|
|
|
|
|
|
(1,112 |
) |
|
Accrued
Liabilities
|
Portion
expected to be reclassified into earnings after one year
|
|
|
|
|
|
|
|
(738 |
) |
|
Other
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
derivatives
|
|
$ |
262 |
|
|
|
$ |
(3,717 |
) |
|
|
|
(1)
|
These
derivative liabilities have been funded with margin deposits recorded in
our Unaudited Consolidated Balance Sheets in Other Current
Assets.
|
|
|
Three
Months Ended September 30, 2009 Effect on Unaudited Consolidated
Statements of Operations and Other
Comprehensive Income (Loss)
|
|
|
|
Amount of Gain (Loss) Recognized in
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
& Logistics - Product Costs
|
|
|
Interest
Expense
|
|
|
Other
Comprehensive Income
(Loss)
|
|
|
|
|
|
Reclassified
from AOCI
|
|
|
Effective
Portion
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - futures and call options:
|
|
|
|
|
|
|
|
|
|
Contracts
designated as hedges under accounting guidance:
|
|
$ |
758 |
(1) |
|
$ |
- |
|
|
$ |
- |
|
Contracts
not considered hedges under accounting guidance:
|
|
|
1,288 |
|
|
|
|
|
|
|
|
|
Total
commodity derivatives
|
|
|
2,046 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swaps designated as cash flow hedges under accounting
guidance
|
|
|
|
|
|
|
(224 |
) |
|
|
(315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
derivatives
|
|
$ |
2,046 |
|
|
$ |
(224 |
) |
|
$ |
(315 |
) |
|
(1)
|
Represents
the amount of loss recognized in income for derivatives related to the
fair value hedge of inventory. The amount excludes the gain on
the hedged inventory under the fair value hedge of $0.2
million.
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Nine Months Ended September 30, 2009 Effect on
Unaudited Consolidated Statements of Operations and Other Comprehensive
Income (Loss)
|
|
|
|
Amount of Gain (Loss) Recognized in
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
&Logistics - Product Costs
|
|
|
Interest
Expense
|
|
|
Other
Comprehensive Income
(Loss)
|
|
|
|
|
|
Reclassified
from AOCI
|
|
|
Effective
Portion
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - futures and call options:
|
|
|
|
|
|
|
|
|
|
Contracts
designated as hedges under accounting guidance:
|
|
$ |
(4,094 |
)(1) |
|
$ |
- |
|
|
$ |
- |
|
Contracts
not considered hedges under accounting guidance:
|
|
|
(1,075 |
) |
|
|
|
|
|
|
|
|
Total
commodity derivatives
|
|
|
(5,169 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swaps designated as cash flow hedges under accounting
guidance
|
|
|
|
|
|
|
(514 |
) |
|
|
(400 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
derivatives
|
|
$ |
(5,169 |
) |
|
$ |
(514 |
) |
|
$ |
(400 |
) |
|
(1)
|
Represents
the amount of loss recognized in income for derivatives related to the
fair value hedge of inventory. The amount excludes the gain on
the hedged inventory under the fair value hedge of $6.4
million.
|
During
the first nine months of 2009, DG Marine’s interest rate hedges fully offset the
hedged risk; therefore, there was no ineffectiveness recorded for the
hedges.
We expect
to reclassify $1.1 million in unrealized losses from AOCI into interest expense
during the next 12 months. Because a portion of these losses are
based on market prices at the current period end, actual amounts to be
reclassified to earnings will differ and could vary materially as a result of
changes in market conditions. We have no derivative contracts with
credit contingent features.
16. Fair-Value
Measurements
The
following table sets forth by level within the fair value hierarchy our
financial assets and liabilities that were accounted for at fair value on a
recurring basis as of September 30, 2009. As required by fair value
accounting guidance, financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Our assessment of the significance of a particular
input to the fair value requires judgment and may affect the placement of assets
and liabilities within the fair value hierarchy levels.
|
|
Fair Value at September 30,
2009
|
|
|
Fair Value at December 31,
2008
|
|
Recurring Fair Value
Measures
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$ |
262 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
482 |
|
|
$ |
- |
|
|
$ |
- |
|
Liabilities
|
|
$ |
(1,867 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(970 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swaps - Liabilities
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(1,850 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(1,964 |
) |
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Level
1
Included
in Level 1 of the fair value hierarchy as commodity derivative contracts are
exchange-traded futures and exchange-traded option contracts. The
fair value of these exchange-traded derivative contracts is based on unadjusted
quoted prices in active markets and is, therefore, included in Level 1 of the
fair value hierarchy.
Level
2
At
September 30, 2009, we had no Level 2 fair value measurements.
Level
3
Included
within Level 3 of the fair value hierarchy are our interest rate
swaps. The fair value of our interest rate swaps is based on
indicative broker price quotations. These derivatives are included in Level 3 of
the fair value hierarchy because broker price quotations used to measure fair
value are indicative quotations rather than quotations whereby the broker or
dealer is ready and willing to transact. However, the fair value of
these Level 3 derivatives is not based upon significant management assumptions
or subjective inputs.
The
following table provides a reconciliation of changes in fair value of the
beginning and ending balances for our derivatives measured at fair value using
inputs classified as Level 3 in the fair value hierarchy:
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Balance
at beginning of period
|
|
$ |
(1,759 |
) |
|
$ |
- |
|
|
$ |
(1,964 |
) |
|
$ |
- |
|
Realized
and unrealized gains (losses)-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassified
into interest expense for settled contracts
|
|
|
224 |
|
|
|
(5 |
) |
|
|
514 |
|
|
|
(5 |
) |
Included
in other comprehensive income
|
|
|
(315 |
) |
|
|
(211 |
) |
|
|
(400 |
) |
|
|
(211 |
) |
Balance
at end of period
|
|
$ |
(1,850 |
) |
|
$ |
(216 |
) |
|
$ |
(1,850 |
) |
|
$ |
(216 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
amount of losses for the nine months ended included in earnings
attributable to the change in unrealized losses relating to liabilities
still held at September 30, 2009 and 2008, respectively
|
|
|
|
|
|
|
|
|
|
$ |
(9 |
) |
|
$ |
(2 |
) |
See Note
15 for additional information on our derivative instruments.
We
generally apply fair value techniques on a non-recurring basis associated with
(1) valuing potential impairment loss related to goodwill, (2) valuing asset
retirement obligations, and (3) valuing potential impairment loss related to
long-lived assets.
17. Contingencies
Guarantees
We
guarantee to the lessor approximately $1.2 million of residual value related to
leases of trailers. We also guarantee 50% of the obligations of
Sandhill under a credit facility with a bank. At September 30, 2009,
Sandhill owed $2.65 million; therefore our guaranty was $1.33
million. Sandhill makes principal payments for this obligation
totaling $0.6 million per year. We believe the likelihood that we
would be required to perform or otherwise incur any significant losses
associated with either of these guarantees is remote.
Other
Matters
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.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Our
facilities and operations may experience damage as a result of an accident or
natural disaster. Such hazards can cause personal injury or loss of
life, severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain
insurance that we consider adequate to cover our operations and properties, in
amounts we consider reasonable. Our insurance does not cover every
potential risk associated with operating our facilities, including the potential
loss of significant revenues. The occurrence of a significant event
that is not fully-insured could materially and adversely affect our results of
operations.
We are
subject to lawsuits in the normal course of business, as well as examinations 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.
Item
2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Included
in Management’s Discussion and Analysis are the following sections:
|
·
|
Available
Cash before Reserves
|
|
·
|
Liquidity
and Capital Resources
|
|
·
|
Commitments
and Off-Balance Sheet Arrangements
|
|
·
|
New
Accounting Pronouncements
|
In the
discussions that follow, we will focus on two measures that we use to manage the
business and to review the results of our operations. Those two
measures are segment margin and Available Cash before
Reserves. During the fourth quarter of 2008, we revised the manner in
which we internally evaluate our segment performance. As a result, we
changed our definition of segment margin to include within segment margin all
costs that are directly associated with a business segment. Segment
margin now includes costs such as general and administrative expenses that are
directly incurred by a business segment. Segment margin also includes
all payments received under direct financing leases. In order to
improve comparability between periods, we exclude from segment margin the
non-cash effects of our stock-based compensation plans which are impacted by
changes in the market price for our common units. Previous periods
have been retrospectively revised to conform to this segment
presentation. We now define segment margin as revenues less cost of
sales, operating expenses (excluding non-cash charges, such as depreciation and
amortization), and segment general and administrative expenses, plus our equity
in distributable cash generated by our joint ventures. In addition,
our segment margin definition excludes the non-cash effects of our stock-based
compensation plans, and includes the non-income portion of payments received
under direct financing leases. Our chief operating decision maker
(our Chief Executive Officer) evaluates segment performance based on a variety
of measures including segment margin, segment volumes where relevant, and
maintenance capital investment. A reconciliation of segment margin to
income before income taxes is included in our segment disclosures in Note 10 to
the consolidated financial statements.
Available
Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific
items, the most significant of which are the addition of non-cash expenses (such
as depreciation), the substitution of cash generated by our joint ventures in
lieu of our equity income attributable to such joint ventures, the elimination
of gains and losses on asset sales (except those from the sale of surplus
assets) and the subtraction of maintenance capital expenditures, which are
expenditures that are necessary to sustain existing (but not to provide new
sources of) cash flows. For additional information on Available
Cash before Reserves and a reconciliation of this measure to cash flows from
operations, see “Liquidity and
Capital Resources - Non-GAAP Reconciliation” below.
Overview
In the
third quarter of 2009, we reported net income attributable to the partnership of
$4.3 million, or $0.14 per common unit. Non-cash expense related to
our senior executive compensation arrangements totaling $3.1 million reduced net
income during the third quarter. See additional discussion of our
senior executive compensation expense in “Results of Operations – Other Costs,
Interest and Income Taxes” below.
During
the third quarter of 2009, we generated $23.7 million of Available Cash before
Reserves, and we will distribute $15.9 million to holders of our common units
and general partner for the third quarter. During the third quarter
of 2009, cash provided by operating activities was $36.8 million.
Macroeconomic
conditions have adversely affected business conditions in several of the
industries that we service, and, consequently, us. Segment margin as
compared to the third quarter of 2008, after consideration of the effects of
acquisitions in 2008, declined for three of our segments. However,
total segment margin increased from the first quarter to second quarter of 2009
and further increased $2.3 million in the third quarter when compared to the
second quarter of 2009.
On
October 13, 2009, we announced that our distribution to our common unitholders
relative to the third quarter of 2009 will be $0.3525 per unit (to be paid in
November 2009). This distribution amount represents a 9.3%
increase from our distribution of $0.3225 per unit for the third quarter of
2008. During the third quarter of 2009, we paid a distribution of
$0.3450 per unit related to the second quarter of 2009.
The
current economic crisis has restricted the availability of credit and access to
capital in our business environment. Despite efforts by U.S. Treasury
and banking regulators to provide liquidity to the financial sector, certain
components of the capital markets continue to remain
constrained. While we anticipate that the challenging economic
environment will continue for the foreseeable future, we believe that our
current cash balances, future internally-generated funds and funds available
under our credit facility will provide sufficient resources to meet our current
working capital needs. The financial performance of our existing
businesses and the fact that we do not need to access the capital markets (other
than opportunistically), may allow us to take advantage of acquisition and/or
growth opportunities that may develop.
Our
ability to fund large new projects or make large acquisitions in the near term
may be limited by the current conditions in the credit and equity markets which
may impact our ability to issue new debt or equity financing. We may
consider other arrangements to fund large growth projects and acquisitions such
as private equity and joint venture arrangements.
Available
Cash before Reserves
Available
Cash before Reserves was as follows (in thousands):
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Net
income attributable to Genesis Energy, L.P.
|
|
$ |
4,299 |
|
|
$ |
10,763 |
|
|
$ |
14,045 |
|
|
$ |
19,736 |
|
Depreciation
and amortization
|
|
|
15,806 |
|
|
|
18,100 |
|
|
|
47,358 |
|
|
|
51,610 |
|
Cash
received from direct financing leases not included in
income
|
|
|
951 |
|
|
|
893 |
|
|
|
2,787 |
|
|
|
1,437 |
|
Cash
effects of sales of certain assets
|
|
|
156 |
|
|
|
147 |
|
|
|
613 |
|
|
|
573 |
|
Effects
of available cash generated by equity method investees not included in
income
|
|
|
787 |
|
|
|
401 |
|
|
|
(332 |
) |
|
|
1,467 |
|
Cash
effects of stock-based compensation plans
|
|
|
(77 |
) |
|
|
(113 |
) |
|
|
(84 |
) |
|
|
(384 |
) |
Non-cash
tax (benefit) expense
|
|
|
(3 |
) |
|
|
(2,462 |
) |
|
|
1,084 |
|
|
|
(3,388 |
) |
Earnings
of DG Marine in excess of distributable cash
|
|
|
(1,108 |
) |
|
|
(428 |
) |
|
|
(3,982 |
) |
|
|
(428 |
) |
Non-cash
equity-based compensation expense (benefit)
|
|
|
4,454 |
|
|
|
(610 |
) |
|
|
10,448 |
|
|
|
(958 |
) |
Other
non-cash items, net
|
|
|
(214 |
) |
|
|
(1,156 |
) |
|
|
(914 |
) |
|
|
(1,174 |
) |
Maintenance
capital expenditures
|
|
|
(1,336 |
) |
|
|
(1,983 |
) |
|
|
(3,758 |
) |
|
|
(2,967 |
) |
Available
Cash before Reserves
|
|
$ |
23,715 |
|
|
$ |
23,552 |
|
|
$ |
67,265 |
|
|
$ |
65,524 |
|
We have
reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from
operating activities (the GAAP measure) for the three and nine months ended
September 30, 2009 and 2008 in “Liquidity and Capital Resources –
Non-GAAP Reconciliation” below. For the three and nine months
ended September 30, 2009, cash flows provided by operating activities were $36.8
million and $55.8 million, respectively. For the three and nine
months ended September 30, 2008, cash flows provided by operating activities
were $33.5 million and $56.2 million, respectively.
Results
of Operations
The
contribution of each of our segments to total segment margin in the three and
nine month periods ended September 30, 2009 and 2008 was as
follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Pipeline
transportation
|
|
$ |
10,269 |
|
|
$ |
11,474 |
|
|
$ |
30,841 |
|
|
$ |
23,396 |
|
Refinery
services
|
|
|
12,694 |
|
|
|
11,486 |
|
|
|
38,643 |
|
|
|
40,195 |
|
Supply
and logistics
|
|
|
9,423 |
|
|
|
9,754 |
|
|
|
21,979 |
|
|
|
21,595 |
|
Industrial
gases
|
|
|
2,893 |
|
|
|
3,906 |
|
|
|
8,785 |
|
|
|
10,791 |
|
Total
segment margin
|
|
$ |
35,279 |
|
|
$ |
36,620 |
|
|
$ |
100,248 |
|
|
$ |
95,977 |
|
Pipeline
Transportation Segment
Operating
results for our pipeline transportation segment were as follows:
|
|
Three Months Ended
September 30
|
|
|
Nine Months Ended
September 30
|
|
Pipeline System
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi-Bbls/day
|
|
|
22,643 |
|
|
|
25,232 |
|
|
|
24,046 |
|
|
|
24,323 |
|
Jay
- Bbls/day
|
|
|
10,550 |
|
|
|
13,817 |
|
|
|
9,767 |
|
|
|
13,422 |
|
Texas
- Bbls/day
|
|
|
24,593 |
|
|
|
25,627 |
|
|
|
26,477 |
|
|
|
28,298 |
|
Free
State - Mcf/day
|
|
|
133,038 |
|
|
|
155,131 |
|
|
|
146,160 |
|
|
|
154,408 |
(1) |
|
(1)
|
Represents
the volume per day for the four months we owned the pipeline in the 2008
period.
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil tariffs and revenues from direct financing leases of crude oil
pipelines
|
|
$ |
4,511 |
|
|
$ |
4,228 |
|
|
$ |
12,461 |
|
|
$ |
12,333 |
|
Non-income
payments under direct financing leases
|
|
|
951 |
|
|
|
893 |
|
|
|
2,787 |
|
|
|
1,437 |
|
Sales
of crude oil pipeline loss allowance volumes
|
|
|
922 |
|
|
|
2,333 |
|
|
|
3,127 |
|
|
|
7,659 |
|
CO2
tariffs and revenues from direct financing leases of CO2
pipelines
|
|
|
6,361 |
|
|
|
6,647 |
|
|
|
19,481 |
|
|
|
8,971 |
|
Tank
rental reimbursements and other miscellaneous revenues
|
|
|
171 |
|
|
|
35 |
|
|
|
488 |
|
|
|
468 |
|
Revenues
from natural gas tariffs and sales
|
|
|
456 |
|
|
|
1,182 |
|
|
|
1,727 |
|
|
|
4,165 |
|
Natural
gas purchases
|
|
|
(395 |
) |
|
|
(1,136 |
) |
|
|
(1,519 |
) |
|
|
(3,990 |
) |
Pipeline
operating costs, excluding non-cash charges for our equity-based
compensation plans and other non-cash charges
|
|
|
(2,708 |
) |
|
|
(2,708 |
) |
|
|
(7,711 |
) |
|
|
(7,647 |
) |
Segment
margin
|
|
$ |
10,269 |
|
|
$ |
11,474 |
|
|
$ |
30,841 |
|
|
$ |
23,396 |
|
Three
Months Ended September 30, 2009 Compared with Three Months Ended September 30,
2008
Pipeline
segment margin for the third quarter of 2009 decreased $1.2 million as compared
to the third quarter of 2008. The significant components of this
change were as follows:
|
·
|
A
decrease in revenues from sales of pipeline loss allowance volumes reduced
segment margin by $1.4 million. The decline in market prices
for crude oil reduced the value of our pipeline loss allowance volumes
and, accordingly, our loss allowance revenues. Average crude
oil market prices decreased approximately $50 per barrel between the two
quarters. In addition, pipeline loss allowance volumes
decreased approximately 5,600 barrels between the
periods.
|
|
·
|
A
decline in volumes transported on our crude oil pipelines between the two
periods decreased segment margin by $0.4 million. The
decreased volumes were principally due to a producer connected to our Jay
System shutting in production in 2009 due to the decline in crude oil
prices in the latter half of 2008. Volume fluctuations on the
Mississippi System, where the incremental tariff rate is only $0.25 per
barrel, are primarily a result of Denbury’s crude oil production
activities. The impact of volume decreases on the Texas System
on revenues is not very significant due to the relatively low tariffs on
that system. Approximately 77% of the volume on that system in
the third quarter was shipped on a tariff of $0.31 per
barrel.
|
|
·
|
A
decrease in revenues and payments related to CO2
pipelines of $0.3 million between the two quarters, although an increase
of $0.1 million in payments under direct financing leases not affecting
income partially offset this decrease. The remaining $0.2
million decrease was related to the Free State pipeline. The
average volume transported on the Free State pipeline for the third
quarter of 2009 was 133 MMcf per day, with the transportation fees and the
minimum payments totaling $1.6 million and $0.3 million,
respectively. Transportation fees and the minimum payments for
the 2008 third quarter were $1.9 million and $0.3 million, respectively,
with the average transportation volume at 155 MMcf per
day. Denbury has exclusive use of this pipeline and variations
in its CO2
tertiary oil recovery activities create the fluctuations in the volumes
transported on the Free State
pipeline.
|
|
·
|
Tariff
rate increases of approximately 7.6% on our Jay and Mississippi pipelines
went into effect July 1, 2009, partially mitigating the effects of lower
crude oil pipeline volumes. The rate increases increased
segment margin between the two periods by approximately $0.7
million.
|
Nine
Months Ended September 30, 2009 Compared with Nine Months Ended September 30,
2008
Pipeline
segment margin between the nine month periods increased $7.4
million. The significant component of this change was an increase in
revenues from CO2 financing
leases and tariffs of $10.5 million and a related increase in non-income
payments from the same financing leases of $1.4 million. The
nine-month period in 2008 only included results from the NEJD and Free State
CO2
pipelines for a four-month period while the 2009 period included nine months of
results.
Partially
offsetting these increases was a decrease in revenues from sales of pipeline
loss allowance volumes of $4.5 million related almost exclusively to the
significant decline (an average of $56 per barrel) in crude oil prices between
the two periods.
Refinery
Services Segment
Operating
results for our refinery services segment were as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Volumes
sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
NaHS
volumes (Dry short tons "DST")
|
|
|
28,207 |
|
|
|
38,319 |
|
|
|
75,344 |
|
|
|
126,716 |
|
NaOH
volumes (DST)
|
|
|
26,898 |
|
|
|
18,404 |
|
|
|
63,561 |
|
|
|
51,066 |
|
Total
|
|
|
55,105 |
|
|
|
56,723 |
|
|
|
138,905 |
|
|
|
177,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NaHS
revenues
|
|
$ |
22,654 |
|
|
$ |
43,926 |
|
|
$ |
74,754 |
|
|
$ |
121,738 |
|
NaOH
revenues
|
|
|
6,455 |
|
|
|
13,439 |
|
|
|
33,534 |
|
|
|
38,892 |
|
Other
revenues
|
|
|
2,256 |
|
|
|
6,127 |
|
|
|
8,905 |
|
|
|
7,194 |
|
Total
external segment revenues
|
|
$ |
31,365 |
|
|
$ |
63,492 |
|
|
$ |
117,193 |
|
|
$ |
167,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
12,694 |
|
|
$ |
11,486 |
|
|
$ |
38,643 |
|
|
$ |
40,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
index price for NaOH per DST (1)
|
|
$ |
198 |
|
|
$ |
845 |
|
|
$ |
493 |
|
|
$ |
616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Raw
material and processing costs as % of segment revenues
|
|
|
33 |
% |
|
|
66 |
% |
|
|
47 |
% |
|
|
62 |
% |
Delivery
costs as a % of segment revenues
|
|
|
14 |
% |
|
|
13 |
% |
|
|
11 |
% |
|
|
14 |
% |
|
(1)
|
Source: Harriman
Chemsult Ltd.
|
Three
Months Ended September 30, 2009 Compared with Three Months Ended September 30,
2008
Refinery
services segment margin for the third quarter of 2009 was $12.7 million, an
increase of $1.2 million, or 10.5%, from the comparative period in
2008. The significant components of this fluctuation were as
follows:
|
·
|
A
decline in NaHS volumes of 26%. Macroeconomic conditions have
negatively impacted the demand for NaHS, primarily in mining and
industrial activities. As market prices and demand for copper
and molybdenum improve, we would expect demand for NaHS to
increase. Similarly, improvements in industrial activities
including the paper and pulp and tanning industries would likely improve
NaHS demand.
|
|
·
|
An
increase in NaOH sales volumes of 46%. NaOH (or caustic soda)
is a key component in the provision of our services for which we receive
the by-product NaHS. We are a very large consumer of caustic
soda, and our economies of scale and logistics capabilities allow us to
effectively market caustic soda to third
parties.
|
|
·
|
Volatile
caustic soda prices. Average index prices for caustic soda
increased throughout 2008 to a high of approximately $950 per DST in the
fourth quarter of 2008. Since that time market prices of
caustic soda have decreased to approximately $200 per DST. This
volatility affects both the cost of caustic soda used to provide our
services as well as the price at which we sell
NaHS.
|
|
·
|
Aggressive
management of production costs. Raw material and processing costs related
to providing our refinery services and supplying caustic soda as a
percentage of our segment revenues declined 33% between the
periods. The key component in the provision of our refinery
services is caustic soda. In addition, as discussed above, we
also market caustic soda. As the market price of caustic soda
has fluctuated in 2008 and 2009, we have managed our acquisition costs
through the timing of our purchases and our logistics costs related to our
caustic soda purchases. We have also taken steps to
reduce processing costs.
|
|
·
|
Slightly
higher delivery logistics costs. The costs of delivering NaHS and caustic
soda to our customers increased slightly as a percentage of segment
revenues by 1% between the two quarterly periods. We
experienced this slight increase in logistics costs as a percentage of
revenues primarily due to the change in revenues. Freight
demand and fuel prices declined in the 2009 period as economic conditions
reduced demand for transportation services and the decline in
crude oil prices reduced the cost of fuel used in transporting these
products. In 2009, we have also adjusted the modes of transportation being
used to transport NaHS and caustic soda between rail, barge and truck to
improve total logistics costs.
|
Nine
Months Ended September 30, 2009 Compared with Nine Months Ended September 30,
2008
Segment
margin for our refinery services decreased $1.6 million between the nine months
ended September 30, 2009 and the same period in 2008. The reasons for
this decline were similar to the quarterly comparison as follows:
|
·
|
NaHS
volumes declined 41%, as a result of macroeconomic
conditions.
|
|
·
|
Caustic
soda sales volumes increased 24% partly offsetting the impact of the
decline in NaHS activity.
|
|
·
|
Revenues
decreased 30% as average index prices for caustic soda in the nine months
ended September 30, 2009 ranged from approximately $900 per DST in January
to $200 per DST in September as compared to an increasing range of
approximately $450 to $950 per DST in the 2008 period. As the
majority of our NaHS sales prices fluctuate with the market price of
caustic soda, variations in market prices affect our
revenues. Raw material and processing costs as a percentage of
segment revenues declined 15% between periods due to us managing the
timing of our purchases and the influences of our ability to purchase in
bulk at favorable prices.
|
|
·
|
Delivery
costs declined due to freight demand in the market and fuel
prices.
|
Supply
and Logistics Segment
Operating
results from our supply and logistics segment were as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Supply
and logistics revenue
|
|
$ |
356,450 |
|
|
$ |
556,396 |
|
|
$ |
836,876 |
|
|
$ |
1,555,991 |
|
Crude
oil and products costs, excluding unrealized gains and losses from
derivative transactions
|
|
|
(323,951 |
) |
|
|
(521,779 |
) |
|
|
(753,217 |
) |
|
|
(1,471,254 |
) |
Operating
and segment general and administrative costs, excluding non-cash charges
for stock-based compensation and other non-cash expenses
|
|
|
(23,076 |
) |
|
|
(24,863 |
) |
|
|
(61,680 |
) |
|
|
(63,142 |
) |
Segment
margin
|
|
$ |
9,423 |
|
|
$ |
9,754 |
|
|
$ |
21,979 |
|
|
$ |
21,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
of crude oil and petroleum products -average barrels per
day
|
|
|
51,260 |
|
|
|
47,342 |
|
|
|
47,280 |
|
|
|
47,694 |
|
Three
Months Ended September 30, 2009 as Compared to Three Months Ended September 30,
2008
The
average market prices of crude oil and petroleum products declined by more than
$50 per barrel, or approximately 45%, although our segment margin declined by
only $0.3 million, or 3.4%, comparatively between the third quarters of 2009 and
2008. The price volatility had a limited impact on our segment
margin.
The
key factors affecting the two quarters were as follows:
|
·
|
Segment
margin generated by DG Marine’s inland marine barge operations (increased
segment margin by $1.7 million);
|
|
·
|
Crude
oil contango market conditions (increased segment margin by $0.9 million);
and
|
|
·
|
Reduction
in opportunities to purchase and blend crude oil and products (reduced
segment margin by $2.9 million).
|
The
inland marine transportation operations of Grifco Transportation, acquired by DG
Marine in mid-July of 2008, contributed $1.7 million more to segment margin in
the third quarter of 2009 as compared to the third quarter of
2008. These operations provided us with an additional
capability to provide transportation services of petroleum products by
barge. As part of the acquisition, DG Marine acquired six tows (a tow
consists of a push boat and two barges.) A total of four additional
tows added during the fourth quarter of 2008 and first half of 2009 generated
the segment margin increase despite declines in average charter rates for the
tows over the same period.
During
the third quarter of 2009, crude oil markets were in contango (oil prices for
future deliveries are higher than for current deliveries), providing an
opportunity for us to purchase and store crude oil as inventory for delivery in
future months. The crude oil markets were not in contango in the
third quarter of 2008 sufficiently to support the costs associated with storing
inventory. During the third quarter of 2009, we held an average of approximately
220,000 barrels of crude oil in our storage tanks and hedged this volume with
futures contracts on the NYMEX. We are accounting for the effects of
this inventory position and related derivative contracts as a fair value hedge
under accounting guidance. The effect on segment margin for the
amount excluded from effectiveness testing related to this fair value hedge was
a $0.9 million gain in the third quarter of 2009.
Offsetting
these improvements in segment margin was a decrease in the margins from our
crude oil gathering and petroleum products marketing operations. In
2009, we experienced some reductions in volumes as a result of crude oil
producers’ choices to reduce operating expenses or postpone development
expenditures that could have maintained or enhanced their existing production
levels. As a consequence of the reductions in volumes, our segment
margin from crude oil gathering declined between the quarterly periods by $1.0
million. Volatile price changes in the petroleum products markets and
robust refinery utilization in the third quarter of 2008 created blending and
sales opportunities with expanded margins in comparison to historical
rates. Relatively flat petroleum prices and reduced refinery
utilization in the third quarter of 2009 narrowed the economics of our blending
opportunities and reduced sales margins to more historical
rates. Somewhat offsetting these margin declines were the additional
opportunities to handle volumes from the heavy end of the refined barrel due to
our access to additional leased heavy products storage capacity and to barge
transportation capabilities through DG Marine. However, the net
result of these factors was a reduction of our segment margin of $1.9 million
from petroleum products and related activities.
Nine Months Ended September 30, 2009
as Compared to Nine Months Ended September 30, 2008
Segment
margin for the nine month period in 2009 was affected by the same factors as in
the third quarter, although the result was a slight increase in segment margin
of $0.4 million. For the nine-month periods, the key factors
described above had an impact as follows:
|
·
|
Acquisition
of inland marine transportation operations of Grifco in mid-July of 2008
(increased segment margin by $7.3
million);
|
|
·
|
Reduction
in opportunities to purchase and blend crude oil and petroleum
products (reduced segment margin by $9.2 million);
and
|
|
·
|
Crude
oil contango market conditions (increased segment margin by $2.3
million).
|
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.
CO2 -
Industrial Customers - 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 customers. The primary industrial applications
of CO2
by those customers include beverage carbonation and food chilling and
freezing. Based on historical data for 2004 through the third quarter
of 2009, we 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. Our industrial customers
also provide CO2 to
companies engaged in tertiary oil recovery activities.
Operating
Results - Operating results from our industrial gases segment were as
follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Revenues
from CO2
marketing
|
|
$ |
4,512 |
|
|
$ |
4,792 |
|
|
$ |
12,032 |
|
|
$ |
13,112 |
|
CO2
transportation and other costs
|
|
|
(1,619 |
) |
|
|
(1,503 |
) |
|
|
(4,298 |
) |
|
|
(4,166 |
) |
Available
cash generated by equity investees
|
|
|
- |
|
|
|
617 |
|
|
|
1,051 |
|
|
|
1,845 |
|
Segment
margin
|
|
$ |
2,893 |
|
|
$ |
3,906 |
|
|
$ |
8,785 |
|
|
$ |
10,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2
marketing - Mcf
|
|
|
80,520 |
|
|
|
83,816 |
|
|
|
73,697 |
|
|
|
78,967 |
|
Three
Months Ended September 30, 2009 Compared with Three Months Ended September 30,
2008
Segment
margin from the industrial gases segment decreased between the 2009 and 2008
third quarters due to a decline in volumes and a slight decrease in the average
sales price of CO2
to our customers. Volumes declined 4% between the two quarterly
periods as customers reduced purchases. The average sales price of
CO2
decreased $0.01 per Mcf, or 2%, due to variations in the volumes sold among
contracts with different pricing terms.
Our
industrial gases segment experienced increased costs due to inflationary
adjustments to the rates Denbury charges us to transport CO2
to our customers. Average transportation rates increased by 6.0% over
the average rates in the 2008 third quarter.
Our share
of the available cash before reserves generated by our equity investments in
each quarterly period primarily resulted from our investment in T&P
Syngas. In the third quarter of 2009, T&P Syngas performed a
scheduled turnaround at its facility that decreased its revenues and increased
its maintenance expenses. Additionally, T&P Syngas incurred
expenses related to improving its waste water treatment. These
activities were completed during the third quarter and the cost of these
activities will be paid from funds generated by T&P Syngas.
Nine
Months Ended September 30, 2009 Compared with Nine Months Ended September 30,
2008
The
decrease in margin from the industrial gases segment between the two nine-month
periods was the result of a decrease in volumes sold and a decrease in the
average sales price of CO2
to our customers. During the first nine months of 2009, volumes
declined 7% to the comparable 2008 period as customers reduced volumes while
performing maintenance activities at their facilities. Variations in
the volumes sold among contracts with different pricing terms resulted in the
average sales price of the CO2
decreasing $0.01 per Mcf, or 1%.
The
inflation adjustment to the rates we pay Denbury to transport the CO2
to our customers resulted in greater CO2
transportation costs in the first nine months of 2009 when compared to the same
2008 period. The transportation rate increase between the two periods
was 5.0%.
Our share
of the available cash before reserves generated by our equity investments in
each period primarily resulted from our investment in T&P
Syngas. As discussed above, the fluctuation between the nine-month
periods is attributable to scheduled maintenance activities.
Other
Costs, Interest, and Income Taxes
General
and administrative expenses. General
and administrative expenses consisted of the following:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
general and administrative expenses
|
|
$ |
10,128 |
|
|
$ |
9,239 |
|
|
$ |
27,188 |
|
|
$ |
26,929 |
|
Comparing
the three-month periods and the nine-month periods, the primary factor driving
the increase in general administrative expenses related to the charge recorded
for the compensation arrangement between our senior executive team and our
general partner. On December 31, 2008, our general partner and our
senior executive management team entered into a compensation arrangement whereby
our executive team may earn an interest in our incentive distribution rights
owned by our general partner. While our general partner will bear the
cash cost of this compensation with our senior executives, we record the expense
of the arrangements with an offsetting non-cash capital contribution by our
general partner. As discussed in Note 12 under Class B Membership
Interests, we estimate the fair value of the awards to our senior executives at
each reporting date and adjust the expense we have recorded based on that fair
value. Based on the fair value estimate at September 30, 2009 of
$22.9 million, we recorded expense for the third quarter of 2009 of $3.1
million, and a total of $7.6 million for the first nine months in
2009. The fair value of the awards is being recorded on an
accelerated basis due to the vesting conditions contained in the awards, so as
to match the expense recorded to the service period required for
vesting.
Reductions
in audit, tax and other professional services and further integration of the
operations we acquired in 2007 offset a portion of the increased amounts in the
three and nine month periods from the compensation arrangement.
Depreciation
and amortization expense. Depreciation and
amortization expense decreased by $4.3 million between the nine-month periods
ended September 30 primarily as a result of the amortization expense recognized
on intangible assets. For the third quarter periods, the decrease in
depreciation and amortization expense was $2.3 million, with a decline in
intangible amortization offset by depreciation on the DG Marine assets acquired
in July 2008.
We are
amortizing our intangible assets over the period during which the intangible
asset is expected to contribute to our future cash flows. The
amortization we record on these assets is greater in the initial years after the
acquisition because intangible assets such as customer relationships and trade
names are generally more valuable in the first years after an
acquisition. As such, the amount of amortization we have recorded has
declined since the intangible assets were acquired in 2007.
Interest
expense, net.
Interest
expense, net was as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Interest
expense, including commitment fees, excluding DG Marine
|
|
$ |
2,018 |
|
|
$ |
3,516 |
|
|
$ |
5,799 |
|
|
$ |
7,229 |
|
Amortization
of facility fees, excluding DG Marine facility
|
|
|
167 |
|
|
|
167 |
|
|
|
495 |
|
|
|
497 |
|
Interest
expense and commitment fees - DG Marine
|
|
|
1,254 |
|
|
|
965 |
|
|
|
3,699 |
|
|
|
965 |
|
Capitalized
interest
|
|
|
(3 |
) |
|
|
(47 |
) |
|
|
(112 |
) |
|
|
(148 |
) |
Interest
income
|
|
|
(18 |
) |
|
|
(118 |
) |
|
|
(55 |
) |
|
|
(352 |
) |
Net
interest expense
|
|
$ |
3,418 |
|
|
$ |
4,483 |
|
|
$ |
9,826 |
|
|
$ |
8,191 |
|
Our
average debt balance was $24.3 million higher in the third quarter of 2009 than
the same period in 2008, although lower market interest rates more than offset
the effect on interest expense. Our average interest rate was 2.0%
lower during the 2009 quarter, resulting in a decrease for the quarter of $1.5
million in interest expense. DG Marine incurred interest expense of
$1.3 million and $1.0 in the third quarter of 2009 and 2008, respectively, under
its credit facility.
For the
nine-month periods, our average outstanding debt balance was $151.6 million
greater in 2009 than 2008. Our average interest rate was 2.4% less in
the 2009 period than the 2008 period, resulting in lower interest
cost. For the nine month periods, DG Marine’s interest expense was
$3.7 million and $1.0 million under its credit facility,
respectively. The increase was a result of the 2009 period including
nine months whereas the 2008 period only included interest expense since the
July 2008 acquisition.
Income
tax expense. Income tax expense
relates to corporate-level income tax accruals (accrued by the Partnership) and
Texas Margin Tax on our operations in Texas. In the nine months of
2009, our activities from operations conducted in corporations increased in
relation to the prior year period, resulting in increased income tax expense. As
the majority of our operations are not conducted by corporations, income tax
expense is not expected to be significant.
Liquidity
and Capital Resources
Capital
Resources/Sources of Cash
Although
credit and access to capital continue to be negatively impacted by current
economic conditions in our business environment, recent market trends have
indicated improvements in bank lending capacity and long-term interest
rates. We anticipate that our short-term working capital needs will
be met through our current cash balances, future internally-generated funds and
funds available under our credit facility. Existing capacity in our
credit facility and $8.7 million of cash on hand, as well as the absence of any
need to access the capital markets, may allow us to take advantage of attractive
acquisition and/or growth opportunities that develop.
For the
long-term, we continue to pursue a growth strategy that requires significant
capital. We expect our long-term capital resources to include equity
and debt offerings (public and private) and other financing transactions, in
addition to cash generated from our operations. 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 and ongoing
working capital needs. Our ability to satisfy future capital needs
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. No assurance can be made that we will be able to raise the
necessary funds on satisfactory terms. If we are unable to raise the
necessary funds, we may be required to defer our growth plans until such time as
funds become available.
We
continue to monitor the credit markets and the economic outlook to determine the
extent of the impact on our business environment. While some increase
in commodity prices for copper has occurred during the first nine months of
2009, continuing weak demand in the United States for fuel has impacted refiners
to whom we sell crude oil and has reduced the availability of petroleum products
for our marketing activities due to reduced refining operating
levels. Difficulties for companies in the mining, paper and pulp
products and leather industries have reduced demand by producers of these goods
for the NaHS used in their processes. We continue to adjust to the
effects of these macro-economic factors in our operating levels and financial
decisions.
Our
consolidated balance sheet at September 30, 2009 includes total long-term debt
of $384.4 million, consisting of $49.4 million outstanding under the
non-recourse DG Marine credit facility and $335 million outstanding under our
credit facility. Outstanding letters of credit under our credit
facility at September 30, 2009 were $4.1 million. Our borrowing base
under our $500 million credit facility is a function of our EBITDA (earnings
before interest, taxes, depreciation and amortization), as defined in our credit
agreement for our most recent four calendar quarters.
Our
credit facility has provisions that allow us to increase our borrowing base for
material acquisitions. Upon the completion of four full quarters of
operations including the acquired operations, the EBITDA multiple used to
determine our borrowing base is reduced from 4.75 times to 4.25
times. In mid-August, upon reporting to our lenders our fourth full
quarter of operations including the pipeline dropdown transactions from Denbury
that occurred in May 2008, our borrowing base was calculated using our last four
quarters of EBITDA with a 4.25 multiplier, which resulted in a decrease in our
borrowing base to $419 million. This decrease in the borrowing base
resulted in approximately $80 million of remaining credit as of September 30,
2009 in addition to cash on hand and cash that we have temporarily invested in
crude oil and petroleum products inventories. We believe that this
level of credit will provide us sufficient liquidity to operate our
business. We have committed capital available under our credit
facility up to $500 million that we can access for material acquisitions that
meet criteria specified in our credit agreement with the calculation of our
borrowing base using the higher multiple and an agreed-upon amount of pro forma
EBITDA associated with the acquisition.
DG Marine
had $49.4 million of loans outstanding under its $90 million credit
facility. As of September 30, 2009, DG Marine had completed and paid
for all amounts related to the capital expenditure projects related to the
expansion of its fleet.
During
2009, as refineries have reduced production capacity, demand for transportation
services of heavy-end fuel oils by inland barges has weakened, putting pressure
on the rates DG Marine can charge for its services. In response, DG Marine
amended its credit facility to (i) adjust the definition of interest expense for
purposes of the interest coverage ratio to exclude non-cash interest expense and
interest under the subordinated loan agreement between DG Marine and Genesis;
(ii) permit Genesis to guaranty up to $7.5 million of the outstanding balance
under the DG Marine credit facility; (iii) reduce the maximum amount of the DG
Marine credit facility from $90 million to $54 million due to the completion of
its fleet expansion projects; and (iv) to provide a debt structure that would
allow for additional credit support in certain circumstances. On
October 30, 2009, Genesis loaned the remaining $8 million available under the
$25 million Subordinated Loan Agreement to DG Marine. The proceeds of
the loan were used to reduce the amount outstanding under the DG Marine credit
facility.
Uses
of Cash
Our cash
requirements include funding day-to-day operations, maintenance and expansion
capital projects, debt service, 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.
Cash Flows from Operations.
We utilize the cash flows we generate from our operations to fund our working
capital needs. Excess funds that are generated are used to repay
borrowings from our credit facilities and to fund capital
expenditures. Our operating cash flows can be impacted by changes in
items of working capital, primarily variances in the timing of payment of
accounts payable and accrued liabilities related to capital
expenditures.
Debt and Other Financing
Activities. Our sources of cash are primarily from operations
and our credit facilities. Our net borrowings under our credit
facility and the DG Marine credit facility totaled $9.1 million during the first
nine months of 2009. These borrowings related primarily to the
investment in fixed assets and the payment of liabilities accrued at year end
for such items as annual bonus payments and property tax
obligations. Additionally, funds were utilized to increase our crude
oil inventory levels due to the contango market conditions. We paid
distributions totaling $44.1 million to our limited partners and our general
partner during the first nine months of 2009. See the details of
distributions paid in “Distributions” below.
Investing. We
utilized cash flows for capital expenditures. The most significant
investing activities in the first nine months of 2009 were expenditures by DG
Marine of $15.7 million for additional barges and related costs. As of September
30, 2009, DG Marine had twenty barges and ten push boats. DG Marine’s
capital expenditures were funded through cash that was generated from operations
and by borrowings under its credit facility.
We also
completed an expansion of our Jay System that extends the pipeline to producers
operating in southern Alabama. That expansion consisted of
approximately 33 miles of pipeline and gathering connections to approximately 35
wells and includes storage capacity of 20,000 barrels. Including the
acquisition of linefill, we expended $2.7 million on this project in
2009. Our expenditures are summarized in the table
below.
Capital
Expenditures, and Business and Asset Acquisitions
A summary
of our expenditures for fixed assets and other asset acquisitions in the first
nine months of 2009 and 2008 is as follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
Capital
expenditures for property, plant and equipment:
|
|
|
|
|
|
|
Maintenance
capital expenditures:
|
|
|
|
|
|
|
Pipeline
transportation assets
|
|
|
1,201 |
|
|
|
463 |
|
Supply
and logistics assets
|
|
|
1,269 |
|
|
|
571 |
|
Refinery
services assets
|
|
|
704 |
|
|
|
856 |
|
Administrative
and other assets
|
|
|
584 |
|
|
|
1,077 |
|
Total
maintenance capital expenditures
|
|
|
3,758 |
|
|
|
2,967 |
|
|
|
|
|
|
|
|
|
|
Growth
capital expenditures:
|
|
|
|
|
|
|
|
|
Pipeline
transportation assets
|
|
|
1,762 |
|
|
|
5,463 |
|
Supply
and logistics assets
|
|
|
17,920 |
|
|
|
18,831 |
|
Refinery
services assets
|
|
|
1,326 |
|
|
|
1,844 |
|
Total
growth capital expenditures
|
|
|
21,008 |
|
|
|
26,138 |
|
Total
|
|
|
24,766 |
|
|
|
29,105 |
|
|
|
|
|
|
|
|
|
|
Capital
expenditures for asset purchases:
|
|
|
|
|
|
|
|
|
DG
Marine acquisition
|
|
|
- |
|
|
|
91,096 |
|
Free
State Pipeline acquisition
|
|
|
- |
|
|
|
75,000 |
|
Acquisition
of intangible assets
|
|
|
2,500 |
|
|
|
- |
|
Total
asset purchases
|
|
|
2,500 |
|
|
|
166,096 |
|
|
|
|
|
|
|
|
|
|
Capital
expenditures attributable to unconsolidated affiliates:
|
|
|
|
|
|
|
|
|
Faustina
project
|
|
|
83 |
|
|
|
2,210 |
|
Total
|
|
|
83 |
|
|
|
2,210 |
|
Total
capital expenditures
|
|
$ |
27,349 |
|
|
$ |
197,411 |
|
During
the remainder of 2009, we expect to expend approximately $1.4 million for
maintenance capital projects in progress or planned. We also plan to
spend $2.5 million for the first phase of a project to integrate and upgrade our
information technology systems as a result of our growth in 2007 and 2008 and to
be positioned for future growth. Capital expenditures in 2010 have
not yet been finalized, although we expect to expend an additional $6 million to
$8 million on our information systems.
Expenditures
for capital assets to grow the partnership distribution will depend on our
access to debt and equity capital discussed above in “Capital Resources -- Sources of
Cash.” We will look for opportunities to acquire assets from
other parties that meet our criteria for stable cash flows.
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 seven quarters, including the distribution to be paid for the third
quarter of 2009, as shown in the table below (in thousands, except per unit
amounts).
Distribution For
|
|
Date Paid
|
|
Per
Unit Amount
|
|
|
Limited
Partner Interests Amount
|
|
|
General
Partner Interest Amount
|
|
|
General
Partner Incentive Distribution Amount
|
|
|
Total
Amount
|
|
|
|
|
|
|
|
|
|
|
Second
quarter 2008
|
|
August
2008
|
|
$ |
0.3150 |
|
|
$ |
12,427 |
|
|
$ |
254 |
|
|
$ |
633 |
|
|
$ |
13,314 |
|
Third
quarter 2008
|
|
November
2008
|
|
$ |
0.3225 |
|
|
$ |
12,723 |
|
|
$ |
260 |
|
|
$ |
728 |
|
|
$ |
13,711 |
|
Fourth
quarter 2008
|
|
February
2009
|
|
$ |
0.3300 |
|
|
$ |
13,021 |
|
|
$ |
266 |
|
|
$ |
823 |
|
|
$ |
14,110 |
|
First
quarter 2009
|
|
May
2009
|
|
$ |
0.3375 |
|
|
$ |
13,317 |
|
|
$ |
271 |
|
|
$ |
1,125 |
|
|
$ |
14,713 |
|
Second
quarter 2009
|
|
August
2009
|
|
$ |
0.3450 |
|
|
$ |
13,621 |
|
|
$ |
278 |
|
|
$ |
1,427 |
|
|
$ |
15,326 |
|
Third
quarter 2009
|
|
November
2009 (1)
|
|
$ |
0.3525 |
|
|
$ |
13,918 |
|
|
$ |
284 |
|
|
$ |
1,729 |
|
|
$ |
15,931 |
|
|
(1)
|
This
distribution will be paid on November 13, 2009 to our general partner and
unitholders of record as of November 2,
2009.
|
See Note
9 of the Notes to the Unaudited Consolidated Financial Statements.
Non-GAAP
Reconciliation
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 costs 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 nine
months ended September 30, 2009 and 2008 is as follows (in
thousands):
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Cash
flows from operating activities
|
|
$ |
36,765 |
|
|
$ |
33,534 |
|
|
$ |
55,831 |
|
|
$ |
56,230 |
|
Adjustments
to reconcile operating cash flows to Available Cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
capital expenditures
|
|
|
(1,336 |
) |
|
|
(1,983 |
) |
|
|
(3,758 |
) |
|
|
(2,967 |
) |
Proceeds
from sales of certain assets
|
|
|
156 |
|
|
|
147 |
|
|
|
613 |
|
|
|
573 |
|
Amortization
of credit facility issuance fees
|
|
|
(487 |
) |
|
|
(427 |
) |
|
|
(1,448 |
) |
|
|
(962 |
) |
Effects
of available cash generated by equity method investees not included in
cash flows from operating activities
|
|
|
- |
|
|
|
482 |
|
|
|
251 |
|
|
|
895 |
|
Earnings
of DG Marine in excess of distributable cash
|
|
|
(1,108 |
) |
|
|
(428 |
) |
|
|
(3,982 |
) |
|
|
(428 |
) |
Other
items affecting available cash
|
|
|
(778 |
) |
|
|
(19 |
) |
|
|
415 |
|
|
|
1,703 |
|
Net
effect of changes in operating accounts not included in calculation of
Available Cash
|
|
|
(9,497 |
) |
|
|
(7,754 |
) |
|
|
19,343 |
|
|
|
10,480 |
|
Available
Cash before Reserves
|
|
$ |
23,715 |
|
|
$ |
23,552 |
|
|
$ |
67,265 |
|
|
$ |
65,524 |
|
Commitments
and Off-Balance-Sheet Arrangements
Contractual
Obligations and Commercial Commitments
There
have been no material changes to the commitments and obligations reflected in
our Annual Report on Form 10-K for the year ended December 31,
2008.
Off-Balance
Sheet Arrangements
We have
no off-balance sheet arrangements, special purpose entities, or financing
partnerships, other than as disclosed under “Contractual Obligations and
Commercial Commitments” in our Annual Report on Form 10-K for the year ended
December 31, 2008, nor do we have any debt or equity triggers based upon our
unit or commodity prices.
New
Accounting Pronouncements
See
discussion of new accounting pronouncements in Note 2, “Recent Accounting
Developments” in the accompanying unaudited 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”, sodium
hydrosulfide and caustic soda 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;
|
|
·
|
loss or bankruptcy of key
customers;
|
|
·
|
the political and economic
stability of the oil producing nations of the world;
and
|
|
·
|
general economic conditions,
including rates of inflation and interest
rates.
|
You
should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risk factors described
under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for
the year ended December 31, 2008. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
The
following should be read in conjunction with Quantitative and Qualitative
Disclosures About Market Risk included under Item 7A in our 2008 Annual Report
on Form 10-K. There have been no material changes in that information
other than as described below. Also, see Note 15 to our Unaudited
Consolidated Financial Statements for additional discussion related to
derivative instruments and hedging activities.
|
|
Sell (Short) Contracts
|
|
|
Buy (Long) Contracts
|
|
|
|
|
|
|
|
|
Futures Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil:
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
319 |
|
|
|
74 |
|
Weighted
average price per bbl
|
|
$ |
66.60 |
|
|
$ |
68.96 |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
21,246 |
|
|
$ |
5,103 |
|
Mark-to-market
change (in thousands)
|
|
|
1,341 |
|
|
|
137 |
|
Market
settlement value (in thousands)
|
|
$ |
22,587 |
|
|
$ |
5,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
Oil:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
93 |
|
|
|
- |
|
Weighted
average price per gal
|
|
$ |
1.86 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
7,259 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
122 |
|
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
7,381 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
RBOB
Gasoline:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average price per gal
|
|
$ |
1.80 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
754 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
(5 |
) |
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
749 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
#6
Fuel Oil:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
30 |
|
|
|
- |
|
Weighted
average price per gal
|
|
$ |
1.44 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
1,812 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
69 |
|
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
1,881 |
|
|
$ |
- |
|
NYMEX Option Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil- Written Calls
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
35 |
|
|
|
- |
|
Weighted
average premium received/paid
|
|
$ |
2.29 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
80 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
43 |
|
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
123 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Heating
Oil- Written Calls
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average premium received/paid
|
|
$ |
3.94 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
39 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
(3 |
) |
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
36 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Natural
Gas- Written Calls
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
- |
|
Weighted
average premium received/paid
|
|
$ |
3.48 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
35 |
|
|
$ |
- |
|
Mark-to-market
change (in thousands)
|
|
|
22 |
|
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
57 |
|
|
$ |
- |
|
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
Information
with respect to this item has been incorporated by reference from our Annual
Report on Form 10-K for the year ended December 31, 2008. There have
been no material developments in legal proceedings since the filing of such Form
10-K.
For
additional information about our risk factors, see Item 1A of our Annual Report
on Form 10-K for the year ended December 31, 2008. There have been no material
changes to the risk factors since the filing of such Form 10-K.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds.
None.
Item
3. Defaults Upon Senior Securities.
None.
Item
4. Submission of Matters to a Vote of Security
Holders.
None.
Item
5. Other Information.
None.
|
3.1
|
Certificate
of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated
by reference to Exhibit 3.1 to Registration Statement, File No.
333-11545)
|
|
3.2
|
Fourth
Amended and Restated Agreement of Limited Partnership of Genesis
(incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15,
2005)
|
|
3.3
|
Amendment
No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of
Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K for the
year ended December 31, 2007.)
|
|
3.4
|
Certificate
of Limited Partnership of Genesis Crude Oil, L.P. (“the Operating
Partnership”) (incorporated by reference to Exhibit 3.3 to Form 10-K for
the year ended December 31, 1996)
|
|
3.5
|
Fourth
Amended and Restated Agreement of Limited Partnership of the Operating
Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated
June 15, 2005)
|
|
3.6
|
Certificate
of Conversion of Genesis Energy, Inc., a Delaware corporation, into
Genesis Energy, LLC, a Delaware limited liability company (incorporated by
reference to Exhibit 3.1 to Form 8-K dated January 7,
2009.)
|
|
3.7
|
Certificate
of Formation of Genesis Energy, LLC (incorporated by reference to Exhibit
3.2 to Form 8-K dated January 7,
2009.)
|
|
3.8
|
Limited
Liability Company Agreement of Genesis Energy, LLC dated December 29, 2008
(incorporated by reference to Exhibit 3.3 to Form 8-K dated January 7,
2009.)
|
|
3.9
|
First
Amendment to Limited Liability Company Agreement of Genesis Energy, LLC
dated December 31, 2008 (incorporated by reference to Exhibit 3.4 to Form
8-K dated January 7, 2009.)
|
|
4.1
|
Form
of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to
Exhibit 4.1 to Form 10-K for the year ended December 31,
2007.)
|
|
|
*Certification
by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934.
|
|
|
*Certification
by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934.
|
|
|
*Certification
by Chief Executive Officer and Chief Financial Officer Pursuant to Rule
13a-14(b) of the Securities Exchange Act of
1934.
|
*Filed
herewith
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, LLC,
|
|
|
as
General Partner
|
|
|
|
|
|
|
Date: November
9, 2009
|
By:
|
/s/ Robert
V.
Deere
|
|
|
Robert
V. Deere
|
|
|
Chief
Financial Officer
|
-51-