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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Southern Union Company Common Stock | NYSE:SUG | NYSE | Ordinary Share |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 41.10 | 0.00 | 01:00:00 |
Delaware
(State or other jurisdiction of
incorporation or organization)
|
75-0571592
(I.R.S. Employer
Identification No.)
|
5444 Westheimer Road
Houston, Texas
(Address of principal executive offices)
|
77056-5306
(Zip Code)
|
PART I. FINANCIAL INFORMATION:
|
Page(s)
|
Glossary
|
2
|
ITEM 1. Financial Statements (Unaudited):
|
|
Condensed consolidated statement of operations.
|
3
|
Condensed consolidated balance sheet.
|
4-5
|
Condensed consolidated statement of cash flows.
|
6
|
Condensed consolidated statement of stockholders’ equity and comprehensive income.
|
7
|
|
|
Notes to condensed consolidated financial statements.
|
8
|
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
|
31
|
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
|
46
|
ITEM 4. Controls and Procedures.
|
48
|
PART II. OTHER INFORMATION:
|
|
ITEM 1. Legal Proceedings.
|
50
|
ITEM 1A. Risk Factors.
|
50
|
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.
|
51
|
ITEM 3. Defaults Upon Senior Securities.
|
51
|
ITEM 4. Reserved.
|
51
|
|
|
ITEM 5. Other Information.
|
51
|
ITEM 6. Exhibits.
|
52
|
SIGNATURES
|
57
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands, except per share amounts)
|
||||||||||||||||
Operating revenues (Note 13)
|
$ | 487,527 | $ | 438,451 | $ | 1,819,617 | $ | 1,575,339 | ||||||||
Operating expenses:
|
||||||||||||||||
Cost of gas and other energy
|
217,928 | 165,029 | 903,563 | 737,008 | ||||||||||||
Operating, maintenance and general
|
118,025 | 113,270 | 350,633 | 358,486 | ||||||||||||
Depreciation and amortization
|
57,305 | 53,486 | 170,058 | 159,316 | ||||||||||||
Revenue-related taxes
|
4,322 | 3,560 | 26,170 | 25,582 | ||||||||||||
Taxes, other than on income and revenues
|
13,540 | 12,931 | 41,764 | 40,411 | ||||||||||||
Total operating expenses
|
411,120 | 348,276 | 1,492,188 | 1,320,803 | ||||||||||||
Operating income
|
76,407 | 90,175 | 327,429 | 254,536 | ||||||||||||
Other income (expenses):
|
||||||||||||||||
Interest expense
|
(55,239 | ) | (50,234 | ) | (161,551 | ) | (146,969 | ) | ||||||||
Earnings from unconsolidated investments
|
32,336 | 24,421 | 78,456 | 63,688 | ||||||||||||
Other, net
|
352 | 2,277 | 289 | 8,371 | ||||||||||||
Total other income (expenses), net
|
(22,551 | ) | (23,536 | ) | (82,806 | ) | (74,910 | ) | ||||||||
Earnings before income taxes
|
53,856 | 66,639 | 244,623 | 179,626 | ||||||||||||
Federal and state income tax expense (Note 9)
|
16,525 | 19,720 | 75,943 | 53,170 | ||||||||||||
Net earnings
|
37,331 | 46,919 | 168,680 | 126,456 | ||||||||||||
Preferred stock dividends
|
(699 | ) | (2,171 | ) | (5,040 | ) | (6,512 | ) | ||||||||
Loss on extinguishment of preferred stock (Note 17)
|
- | - | (3,295 | ) | - | |||||||||||
Net earnings available for common stockholders
|
$ | 36,632 | $ | 44,748 | $ | 160,345 | $ | 119,944 | ||||||||
Net earnings available for common stockholders per share:
|
||||||||||||||||
Basic
|
$ | 0.29 | $ | 0.36 | $ | 1.29 | $ | 0.97 | ||||||||
Diluted
|
0.29 | 0.36 | 1.28 | 0.97 | ||||||||||||
Dividends declared on common stock per share
|
$ | 0.15 | $ | 0.15 | $ | 0.45 | $ | 0.45 | ||||||||
Weighted average shares outstanding (Note 4):
|
||||||||||||||||
Basic
|
124,484 | 124,057 | 124,458 | 124,050 | ||||||||||||
Diluted
|
125,160 | 124,568 | 125,106 | 124,273 |
September 30,
|
December 31,
|
|||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 17,122 | $ | 10,545 | ||||
Accounts receivable, net of allowances of
|
||||||||
$3,562 and $1,874, respectively
|
187,898 | 277,661 | ||||||
Accounts receivable – affiliates
|
10,425 | 10,387 | ||||||
Inventories (Note 3)
|
193,438 | 290,031 | ||||||
Deferred natural gas purchases
|
127,010 | 88,421 | ||||||
Natural gas imbalances - receivable
|
72,122 | 127,284 | ||||||
Prepayments and other assets
|
78,466 | 57,024 | ||||||
Total current assets
|
686,481 | 861,353 | ||||||
|
||||||||
Property, plant and equipment:
|
||||||||
Plant in service
|
6,862,958 | 6,260,188 | ||||||
Construction work in progress
|
130,647 | 531,710 | ||||||
|
6,993,605 | 6,791,898 | ||||||
Less accumulated depreciation and amortization
|
(1,329,387 | ) | (1,162,685 | ) | ||||
Net property, plant and equipment
|
5,664,218 | 5,629,213 | ||||||
|
||||||||
Deferred charges:
|
||||||||
Regulatory assets
|
68,345 | 72,304 | ||||||
Deferred charges
|
65,826 | 60,995 | ||||||
Total deferred charges
|
134,171 | 133,299 | ||||||
|
||||||||
Unconsolidated investments (Note 5)
|
1,419,086 | 1,340,048 | ||||||
|
||||||||
Goodwill
|
89,227 | 89,227 | ||||||
|
||||||||
Other
|
19,049 | 21,934 | ||||||
|
||||||||
Total assets
|
$ | 8,012,232 | $ | 8,075,074 | ||||
September 30,
|
December 31,
|
|||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Stockholders’ equity:
|
||||||||
Common stock, $1 par value; 200,000 shares authorized;
|
||||||||
125,666 and 125,569 shares issued, respectively | $ | 125,666 | $ | 125,569 | ||||
Preferred stock, no par value; 6,000 shares authorized;
|
||||||||
nil and 460 shares issued, respectively (Note 17) | - | 115,000 | ||||||
Premium on capital stock
|
1,917,526 | 1,905,293 | ||||||
Less treasury stock: 1,176 and 1,171
|
||||||||
shares, respectively, at cost | (29,215) | (29,109) | ||||||
Less common stock held in trust: 589
|
||||||||
and 659 shares, respectively | (10,659) | (11,769) | ||||||
Deferred compensation plans
|
10,659 | 11,769 | ||||||
Accumulated other comprehensive loss
|
(33,919 | ) | (56,505 | ) | ||||
Retained earnings
|
514,032 | 409,698 | ||||||
Total stockholders' equity
|
2,494,090 | 2,469,946 | ||||||
Long-term debt obligations (Note 7)
|
3,520,877 | 3,421,236 | ||||||
Total capitalization | 6,014,967 | 5,891,182 | ||||||
Current liabilities:
|
||||||||
Long-term debt due within one year (Note 7)
|
985 | 140,500 | ||||||
Notes payable (Note 7)
|
180,000 | 80,000 | ||||||
Accounts payable and accrued liabilities
|
199,978 | 246,394 | ||||||
Federal, state and local taxes payable
|
41,100 | 4,293 | ||||||
Accrued interest
|
57,363 | 40,061 | ||||||
Natural gas imbalances - payable
|
141,095 | 322,200 | ||||||
Derivative instruments (Notes 10 and 11)
|
74,130 | 97,008 | ||||||
Asset retirement obligations
|
28,548 | 45,971 | ||||||
Other
|
82,122 | 77,928 | ||||||
Total current liabilities
|
805,321 | 1,054,355 | ||||||
Deferred credits
|
200,935 | 223,950 | ||||||
Accumulated deferred income taxes
|
991,009 | 905,587 | ||||||
Commitments and contingencies (Note 12)
|
||||||||
Total stockholders' equity and liabilities | $ | 8,012,232 | $ | 8,075,074 |
Nine Months Ended September 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Cash flows provided by (used in) operating activities:
|
||||||||
Net earnings
|
$ | 168,680 | $ | 126,456 | ||||
Adjustments to reconcile net earnings to net cash flows
|
||||||||
provided by operating activities:
|
||||||||
Depreciation and amortization
|
170,058 | 159,316 | ||||||
Deferred income taxes
|
90,158 | 93,856 | ||||||
Provision for bad debts
|
12,586 | 14,088 | ||||||
Unrealized loss on commodity derivatives
|
12,589 | 5,597 | ||||||
Share-based compensation expense
|
6,967 | 5,537 | ||||||
Earnings from unconsolidated investments, adjusted for cash distributions
|
(72,012 | ) | (63,688 | ) | ||||
Loss on assets
|
238 | 5,491 | ||||||
Changes in operating assets and liabilities
|
(28,831 | ) | 117,760 | |||||
Net cash flows provided by operating activities
|
360,433 | 464,413 | ||||||
Cash flows used in investing activities:
|
||||||||
Additions to property, plant and equipment
|
(209,826 | ) | (316,880 | ) | ||||
Contributions to unconsolidated investments
|
(7,500 | ) | - | |||||
Plant retirements and other
|
(1,244 | ) | (2,542 | ) | ||||
Net cash flows used in investing activities
|
(218,570 | ) | (319,422 | ) | ||||
Cash flows provided by (used in) financing activities:
|
||||||||
Increase (decrease) in book overdraft
|
(11,983 | ) | 3,869 | |||||
Issuance of long-term debt
|
100,822 | 302,582 | ||||||
Renewal cost for credit facilities and issuance cost of debt
|
(7,051 | ) | (3,938 | ) | ||||
Dividends paid on common stock
|
(55,994 | ) | (55,814 | ) | ||||
Dividends paid on preferred stock
|
(7,211 | ) | (6,512 | ) | ||||
Repayment of long-term debt obligation
|
(140,831 | ) | (60,623 | ) | ||||
Net borrowings (payments) under credit facilities
|
100,000 | (321,459 | ) | |||||
Redemption of preferred stock
|
(115,000 | ) | - | |||||
Other
|
1,962 | (377 | ) | |||||
Net cash flows used in financing activities
|
(135,286 | ) | (142,272 | ) | ||||
Change in cash and cash equivalents
|
6,577 | 2,719 | ||||||
Cash and cash equivalents at beginning of period
|
10,545 | 4,318 | ||||||
Cash and cash equivalents at end of period
|
$ | 17,122 | $ | 7,037 | ||||
Accumulated
|
||||||||||||||||||||||||||||||||||||
Common
|
Preferred
|
Premium
|
Common
|
Deferred
|
Other
|
Total
|
||||||||||||||||||||||||||||||
Stock,
|
Stock,
|
on
|
Treasury
|
Stock
|
Compen-
|
Compre-
|
Stock-
|
|||||||||||||||||||||||||||||
$1 Par
|
No Par
|
Capital
|
Stock,
|
Held
|
sation
|
hensive
|
Retained
|
holders'
|
||||||||||||||||||||||||||||
Value
|
Value
|
Stock
|
at cost
|
In Trust
|
Plans
|
Loss
|
Earnings
|
Equity
|
||||||||||||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||||||||||||||
Balance December 31, 2009
|
$ | 125,569 | $ | 115,000 | $ | 1,905,293 | $ | (29,109) | $ | (11,769) | $ | 11,769 | $ | (56,505) | $ | 409,698 | $ | 2,469,946 | ||||||||||||||||||
Redemption of preferred stock (Note 17)
|
- | (115,000 | ) | 3,295 | - | - | - | - | (3,295) | (115,000 | ) | |||||||||||||||||||||||||
Comprehensive income:
|
||||||||||||||||||||||||||||||||||||
Net earnings
|
- | - | - | - | - | - | - | 168,680 | 168,680 | |||||||||||||||||||||||||||
Net change in other
|
||||||||||||||||||||||||||||||||||||
comprehensive income (Note 6)
|
- | - | - | - | - | - | 22,586 | - | 22,586 | |||||||||||||||||||||||||||
Comprehensive income
|
191,266 | |||||||||||||||||||||||||||||||||||
Preferred stock dividends
|
- | - | - | - | - | - | - | (5,040) | (5,040 | ) | ||||||||||||||||||||||||||
Common stock dividends declared
|
- | - | - | - | - | - | - | (56,011) | (56,011 | ) | ||||||||||||||||||||||||||
Share-based compensation
|
- | - | 6,967 | - | - | - | - | - | 6,967 | |||||||||||||||||||||||||||
Restricted stock issuances
|
8 | - | 452 | - | - | - | - | - | 460 | |||||||||||||||||||||||||||
Exercise of stock options and SARs
|
89 | - | 1,519 | (106) | - | - | - | - | 1,502 | |||||||||||||||||||||||||||
Contributions to Trust
|
- | - | - | - | (584) | 584 | - | - | - | |||||||||||||||||||||||||||
Disbursements from Trust
|
- | - | - | - | 1,694 | (1,694) | - | - | - | |||||||||||||||||||||||||||
Balance September 30, 2010
|
$ | 125,666 | $ | - | $ | 1,917,526 | $ | (29,215) | $ | (10,659) | $ | 10,659 | $ | (33,919) | $ | 514,032 | $ | 2,494,090 |
Transportation & Storage
|
Gathering & Processing
|
Distribution
|
Total
|
||||||||||
At September 30, 2010
|
(In thousands) | ||||||||||||
Current
|
|||||||||||||
Natural gas (1)
|
$ | 81,066 | $ | - | $ | 74,191 | $ | 155,257 | |||||
Materials and supplies
|
16,631 | 9,380 | 3,986 | 29,997 | |||||||||
NGL (2)
|
- | 8,184 | - | 8,184 | |||||||||
Total Current
|
97,697 | 17,564 | 78,177 | 193,438 | |||||||||
Non-Current
|
|||||||||||||
Natural gas (1)
|
7,272 | - | - | 7,272 | |||||||||
$ | 104,969 | $ | 17,564 | $ | 78,177 | $ | 200,710 | ||||||
At December 31, 2009
|
|||||||||||||
Current
|
|||||||||||||
Natural gas (1)
|
$ | 198,712 | $ | - | $ | 56,125 | $ | 254,837 | |||||
Materials and supplies
|
15,995 | 9,307 | 3,926 | 29,228 | |||||||||
NGL (2)
|
- | 5,966 | - | 5,966 | |||||||||
Total Current
|
214,707 | 15,273 | 60,051 | 290,031 | |||||||||
Non-Current
|
|||||||||||||
Natural gas (1)
|
8,831 | - | - | 8,831 | |||||||||
$ | 223,538 | $ | 15,273 | $ | 60,051 | $ | 298,862 |
(1)
|
Natural gas volumes held for operations in the Transportation and Storage segment at September 30, 2010 and December 31, 2009 were 20,705,000 MMBtu and 35,039,000 MMBtu, respectively. Natural gas volumes in the Distribution segment at September 30, 2010 and December 31, 2009 were 16,983,000 MMBtu and 11,742,000 MMBtu, respectively.
|
(2)
|
NGL at September 30, 2010 and December 31, 2009 were 10,484,000 gallons and 6,680,000 gallons, respectively.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Weighted average shares outstanding - Basic
|
124,484 | 124,057 | 124,458 | 124,050 | ||||||||||||
Add assumed vesting of restricted stock
|
154 | 88 | 123 | 61 | ||||||||||||
Add assumed exercise of stock options and SARs
|
522 | 423 | 525 | 162 | ||||||||||||
Weighted average shares outstanding - Diluted
|
125,160 | 124,568 | 125,106 | 124,273 |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands, except per share amounts)
|
||||||||||||||||
Options excluded
|
1,212 | 1,287 | 1,212 | 1,625 | ||||||||||||
Exercise price of options excluded
|
$ 23.62 - $28.48 | $ 22.68 - $28.48 | $ 23.62 - $28.48 | $ 16.83 - $28.48 | ||||||||||||
SARs excluded
|
402 | 386 | 402 | 386 | ||||||||||||
Exercise price ranges of SARs excluded
|
$ 24.04 - $28.48 | $ 28.07 - $28.48 | $ 24.04 - $28.48 | $ 28.07 - $28.48 | ||||||||||||
Weighted-average market price
|
$ 23.23 | $ 19.47 | $ 23.56 | $ 16.61 |
September 30,
|
December 31,
|
|||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Citrus
|
$ | 1,392,174 | $ | 1,310,765 | ||||
Other
|
26,912 | 29,283 | ||||||
$ | 1,419,086 | $ | 1,340,048 |
Three Months Ended September 30,
|
||||||||||||||||
2010
|
2009
|
|||||||||||||||
Citrus
|
Other
|
Citrus
|
Other
|
|||||||||||||
(In thousands) | ||||||||||||||||
Revenues
|
$ | 146,543 | $ | 6,237 | $ | 141,083 | $ | 5,548 | ||||||||
Operating income
|
83,124 | 3,343 | 81,599 | 3,842 | ||||||||||||
Net earnings
|
55,182 | 3,354 | 40,325 | 3,801 |
Nine Months Ended September 30,
|
||||||||||||||||
2010
|
2009
|
|||||||||||||||
Citrus
|
Other
|
Citrus
|
Other
|
|||||||||||||
(In thousands) | ||||||||||||||||
Revenues
|
$ | 401,254 | $ | 17,921 | $ | 389,306 | $ | 14,655 | ||||||||
Operating income
|
212,818 | 9,825 | 214,142 | 7,762 | ||||||||||||
Net earnings
|
131,269 | 9,624 | 104,839 | 7,632 |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Net Earnings
|
$ | 37,331 | $ | 46,919 | $ | 168,680 | $ | 126,456 | ||||||||
Changes in Other Comprehensive Income (Loss):
|
||||||||||||||||
Change in fair value of interest rate hedges, net of tax of $(1,459),
|
||||||||||||||||
$(2,474), $(5,073) and $(2,062), respectively | (2,172 | ) | (3,681 | ) | (7,547 | ) | (3,068 | ) | ||||||||
Reclassification of unrealized loss on interest rate hedges into
|
||||||||||||||||
earnings, net of tax of $2,186, $2,257, $6,740 and $5,833, | ||||||||||||||||
respectively | 3,261 | 3,388 | 10,064 | 8,767 | ||||||||||||
Change in fair value of commodity hedges, net of tax of $4,707,
|
||||||||||||||||
$(3,496), $14,320 and $1,011, respectively | 8,352 | (6,205 | ) | 25,413 | 1,794 | |||||||||||
Reclassification of unrealized gain on commodity hedges into
|
||||||||||||||||
earnings, net of tax of $(2,019), $(4,809), $(4,291) and $(12,983), |
|
|||||||||||||||
respectively | (3,584 | ) | (8,534 | ) | (7,616 | ) | (23,040 | ) | ||||||||
Reclassification of net actuarial loss and prior service credit
|
||||||||||||||||
relating to pension and other postretirement benefits into
|
||||||||||||||||
earnings, net of tax of $549, $736, $1,651 and $2,208,
|
||||||||||||||||
respectively
|
723 | 974 | 2,165 | 2,920 | ||||||||||||
Change in other comprehensive income (loss) from equity
|
||||||||||||||||
investments, net of tax of $22, $(1,646), $66 and $(1,646),
|
||||||||||||||||
respectively
|
36 | (2,661 | ) | 107 | (2,661 | ) | ||||||||||
Total other comprehensive income (loss)
|
6,616 | (16,719 | ) | 22,586 | (15,288 | ) | ||||||||||
Total comprehensive income
|
$ | 43,947 | $ | 30,200 | $ | 191,266 | $ | 111,168 |
September 30, 2010
|
December 31, 2009
|
||||||||||||||||
Carrying Value
|
Fair Value
|
Carrying Value
|
Fair Value
|
||||||||||||||
(In thousands)
|
|||||||||||||||||
Long-Term Debt Obligations:
|
|||||||||||||||||
Southern Union:
|
|||||||||||||||||
7.60% Senior Notes due 2024
|
$ | 359,765 | $ | 419,169 | $ | 359,765 | $ | 389,820 | |||||||||
8.25% Senior Notes due 2029
|
300,000 | 351,009 | 300,000 | 337,800 | |||||||||||||
7.24% to 9.44% First Mortgage Bonds
|
|||||||||||||||||
due 2020 to 2027
|
19,500 | 22,576 | 19,500 | 21,403 | |||||||||||||
6.089% Senior Notes due 2010
|
- | - | 100,000 | 100,250 | |||||||||||||
7.20% Junior Subordinated Notes due 2066 (1)
|
600,000 | 546,378 | 600,000 | 510,000 | |||||||||||||
Term Loan due 2011 (2)
|
250,000 | 249,943 | 150,000 | 150,178 | |||||||||||||
Note Payable
|
8,216 | 8,216 | 7,725 | 7,725 | |||||||||||||
1,537,481 | 1,597,291 | 1,536,990 | 1,517,176 | ||||||||||||||
Panhandle:
|
|||||||||||||||||
6.05% Senior Notes due 2013
|
250,000 | 272,418 | 250,000 | 269,733 | |||||||||||||
6.20% Senior Notes due 2017
|
300,000 | 330,834 | 300,000 | 319,455 | |||||||||||||
8.125% Senior Notes due 2019
|
150,000 | 182,532 | 150,000 | 173,111 | |||||||||||||
8.25% Senior Notes due 2010
|
- | - | 40,500 | 41,143 | |||||||||||||
7.00% Senior Notes due 2029
|
66,305 | 72,773 | 66,305 | 69,866 | |||||||||||||
7.00% Senior Notes due 2018
|
400,000 | 455,368 | 400,000 | 434,560 | |||||||||||||
Term Loans due 2012
|
815,391 | 795,988 | 815,391 | 758,108 | |||||||||||||
Net premiums on long-term debt
|
2,685 | 2,685 | 2,550 | 2,550 | |||||||||||||
1,984,381 | 2,112,598 | 2,024,746 | 2,068,526 | ||||||||||||||
Total Long-Term Debt Obligations
|
3,521,862 | 3,709,889 | 3,561,736 | 3,585,702 | |||||||||||||
Credit Facilities
|
180,000 | 182,924 | 80,000 | 78,968 | |||||||||||||
Total consolidated debt obligations
|
3,701,862 | $ | 3,892,813 | 3,641,736 | $ | 3,664,670 | |||||||||||
Less current portion of long-term debt
|
985 | 140,500 | |||||||||||||||
Less short-term debt
|
180,000 | 80,000 | |||||||||||||||
Total long-term debt
|
$ | 3,520,877 | $ | 3,421,236 |
(1)
|
Effective November 1, 2011, the Company can elect to redeem this debt obligation at par. If the Company elects to not redeem this debt obligation, the interest rate will change to a variable rate based upon the three-month LIBOR rate plus 3.0175 percent, reset quarterly.
|
(2)
|
As more fully described in the 2010 Term Loan discussion below, the term loan maturity date was extended to 2013.
|
Pension Benefits
|
Other Postretirement Benefits
|
|||||||||||||||
Three Months Ended September 30, |
Three Months Ended September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Service cost
|
$ | 767 | $ | 738 | $ | 792 | $ | 749 | ||||||||
Interest cost
|
2,510 | 2,524 | 1,410 | 1,348 | ||||||||||||
Expected return on plan assets
|
(2,337 | ) | (2,069 | ) | (1,270 | ) | (771 | ) | ||||||||
Prior service cost (credit) amortization
|
138 | 138 | (412 | ) | (317 | ) | ||||||||||
Actuarial (gain) loss amortization
|
1,997 | 2,101 | (450 | ) | (212 | ) | ||||||||||
Sub-total
|
3,075 | 3,432 | 70 | 797 | ||||||||||||
Regulatory adjustment (1)
|
52 | (125 | ) | 667 | 667 | |||||||||||
Net periodic benefit cost
|
$ | 3,127 | $ | 3,307 | $ | 737 | $ | 1,464 |
Pension Benefits
|
Other Postretirement Benefits
|
|||||||||||||||
Nine Months Ended September 30,
|
Nine Months Ended September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Service cost
|
$ | 2,302 | $ | 2,213 | $ | 2,378 | $ | 2,248 | ||||||||
Interest cost
|
7,529 | 7,572 | 4,229 | 4,043 | ||||||||||||
Expected return on plan assets
|
(7,011 | ) | (6,209 | ) | (3,581 | ) | (2,315 | ) | ||||||||
Prior service cost (credit) amortization
|
414 | 414 | (1,235 | ) | (951 | ) | ||||||||||
Actuarial (gain) loss amortization
|
5,990 | 6,304 | (1,351 | ) | (636 | ) | ||||||||||
Sub-total
|
9,224 | 10,294 | 440 | 2,389 | ||||||||||||
Regulatory adjustment (1)
|
209 | (375 | ) | 1,999 | 1,999 | |||||||||||
Net periodic benefit cost
|
$ | 9,433 | $ | 9,919 | $ | 2,439 | $ | 4,388 |
(1)
|
In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as determined by the applicable utility commission.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Income tax expense
|
$ | 16,525 | $ | 19,720 | $ | 75,943 | $ | 53,170 | ||||||||
Effective tax rate
|
31 | % | 30 | % | 31 | % | 30 | % |
Asset Derivative Instruments (1)
|
|||||||||
Balance Sheet
|
Fair Value
|
||||||||
Location
|
September 30, 2010
|
December 31, 2009
|
|||||||
(In thousands)
|
|||||||||
Cash Flow Hedges:
|
|||||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
Natural gas price swaps
|
Prepayments and other assets
|
$ | 17,335 | $ | - | ||||
Other noncurrent assets
|
3,682 | - | |||||||
Derivative instruments-liabilities
|
2,997 | - | |||||||
Deferred credits
|
- | 314 | |||||||
$ | 24,014 | $ | 314 | ||||||
Economic Hedges:
|
|||||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
Other derivative instruments
|
Prepayments and other assets
|
$ | - | $ | 5 | ||||
Derivative instruments-liabilities
|
34 | 166 | |||||||
Commodity contracts - Distribution:
|
|||||||||
Natural gas price swaps
|
Derivative instruments-liabilities
|
17 | 582 | ||||||
Deferred credits
|
86 | 15 | |||||||
$ | 137 | $ | 768 | ||||||
Other:
|
|||||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
Other derivative instruments
|
Prepayments and other assets
|
$ | 227 | $ | 162 | ||||
Total
|
$ | 24,378 | $ | 1,244 |
(1)
|
The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis. In those instances where a right of offset exists, the fair value amounts for the derivative instruments are reported in the Condensed Consolidated Balance Sheet on a net basis and disclosed herein on a gross basis.
|
Liability Derivative Instruments (1)
|
|||||||||
Balance Sheet
|
Fair Value
|
||||||||
Location
|
September 30, 2010
|
December 31, 2009
|
|||||||
(In thousands)
|
|||||||||
Cash Flow Hedges
|
|||||||||
Interest rate contracts:
|
|||||||||
Interest rate swaps
|
Derivative instruments-liabilities
|
$ | 19,897 | $ | 18,754 | ||||
Deferred credits
|
9,489 | 13,975 | |||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
Natural gas price swaps
|
Derivative instruments-liabilities
|
- | 4,126 | ||||||
$ | 29,386 | $ | 36,855 | ||||||
Economic Hedges
|
|||||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
NGL processing spread swaps
|
Prepayments and other assets
|
$ | 14,444 | $ | - | ||||
Other noncurrent assets
|
1,797 | - | |||||||
Derivative instruments-liabilities
|
12,128 | 34,477 | |||||||
Deferred credits
|
1,362 | 10,410 | |||||||
Other derivative instruments
|
Derivative instruments-liabilities
|
237 | 193 | ||||||
Commodity contracts - Distribution:
|
|||||||||
Natural gas price swaps
|
Derivative instruments-liabilities
|
44,916 | 40,206 | ||||||
Deferred credits
|
4,994 | 3,991 | |||||||
$ | 79,878 | $ | 89,277 | ||||||
Other
|
|||||||||
Commodity contracts - Gathering and Processing:
|
|||||||||
Other derivative instruments
|
Prepayments and other assets
|
$ | - | $ | 30 | ||||
Total
|
$ | 109,264 | $ | 126,162 | |||||
(1)
|
The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis. In those instances where a right of offset exists, the fair value amounts for the derivative instruments are reported in the Condensed Consolidated Balance Sheet on a net basis and disclosed herein on a gross basis.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Cash Flow Hedges: (1)
|
(In thousands)
|
|||||||||||||||
Interest rate contracts:
|
||||||||||||||||
Change in fair value - increase in
Accumulated other
|
||||||||||||||||
comprehensive loss, excluding tax expense effect
|
||||||||||||||||
of $1,459, $2,474, $5,073 and $2,062, respectively
|
$ | 3,631 | $ | 6,155 | $ | 12,620 | $ | 5,130 | ||||||||
Reclassification of unrealized loss from
Accumulated other
|
||||||||||||||||
comprehensive loss -
increase of
Interest expense,
excluding tax
|
||||||||||||||||
expense effect of $2,186, $2,257, $6,740 and $5,833, respectively
|
5,447 | 5,645 | 16,804 | 14,600 | ||||||||||||
Commodity contracts - Gathering and Processing:
|
||||||||||||||||
Change in fair value - (increase) decrease in
Accumulated other
|
||||||||||||||||
comprehensive loss,
excluding tax expense effect
|
||||||||||||||||
of $4,707, $(3,496), $14,320 and $1,011, respectively
|
13,059 | (9,701 | ) | 39,733 | 2,805 | |||||||||||
Reclassification of unrealized gain from
Accumulated other
|
||||||||||||||||
comprehensive loss -
increase of
Operating Revenues
,
|
||||||||||||||||
excluding tax expense effect of $2,019, $4,809,
|
||||||||||||||||
$4,291 and $12,983, respectively
|
5,603 | 13,343 | 11,907 | 36,023 | ||||||||||||
Economic Hedges:
|
||||||||||||||||
Commodity contracts - Gathering and Processing:
|
||||||||||||||||
Change in fair value of strategic hedges - (increase) decrease in
|
||||||||||||||||
Operating revenues (2)
|
29,180 | (1,851 | ) | 14,508 | 32,799 | |||||||||||
Change in fair value of other hedges - (increase) decrease
|
||||||||||||||||
in
Operating revenues
|
279 | (461 | ) | 465 | 20 | |||||||||||
Commodity contracts - Distribution:
|
||||||||||||||||
Change in fair value - (increase) decrease in
Deferred natural gas
|
||||||||||||||||
purchases | (13,914) | 25,682 | (6,207) | 47,403 | ||||||||||||
Other:
|
||||||||||||||||
Commodity contracts - Gathering and Processing:
|
||||||||||||||||
Change in fair value - (increase) decrease in
Operating revenues
|
54 | 595 | (96 | ) | 757 |
(1)
|
See
Note 6 – Comprehensive Income (Loss)
for additional related information.
|
(2)
|
Includes $7.7 million and $27.7 million of the cash settlement impact for previously recognized unrealized losses in the three-month and nine-month periods ended September 30, 2010, respectively. Includes $15.6 million and $44.8 million of the cash settlement impact for previously recognized unrealized gains in the three-month and nine-month periods ended September 30, 2009, respectively. Additionally, includes $29.2 million and $12.6 million of unrealized mark-to-market losses recorded in the three-month and nine-month periods ended September 30, 2010, respectively, and $15.1 million of unrealized mark-to-market gains and $6 million of unrealized mark-to-market losses recorded in the three-month and nine-month periods ended September 30, 2009, respectively.
|
Fair Value Measurements at September 30, 2010
|
||||||||||||
Using Fair Value Hierarchy
|
||||||||||||
Quoted Prices in
|
||||||||||||
Fair Value
|
Active Markets for
|
Significant Other
|
||||||||||
as of
|
Identical Assets
|
Observable Inputs
|
||||||||||
September 30, 2010
|
(Level 1)
|
(Level 2)
|
||||||||||
(In thousands)
|
||||||||||||
Assets:
|
||||||||||||
Commodity derivatives (1)
|
$ | 5,003 | $ | - | $ | 5,003 | ||||||
Long-term investments
|
865 | 865 | - | |||||||||
Total
|
$ | 5,868 | $ | 865 | $ | 5,003 | ||||||
Liabilities:
|
||||||||||||
Commodity derivatives (1)
|
$ | 60,503 | $ | 211 | $ | 60,292 | ||||||
Interest-rate derivatives (1)
|
29,386 | - | 29,386 | |||||||||
Total
|
$ | 89,889 | $ | 211 | $ | 89,678 |
(1)
|
See related information in
Note 10 – Derivative Instruments and Hedging Activities
.
|
September 30,
|
December 31,
|
|||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Current
|
$ | 6,176 | $ | 7,745 | ||||
Noncurrent
|
15,916 | 16,964 | ||||||
Total environmental liabilities
|
$ | 22,092 | $ | 24,709 |
|
13. Reportable Segments
|
·
|
items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
|
·
|
income taxes;
|
·
|
interest;
|
·
|
dividends on preferred stock; and
|
·
|
loss on extinguishment of preferred stock.
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||
September 30,
|
September 30,
|
||||||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||||||
(In thousands)
|
|||||||||||||||||
Revenues from external customers:
|
|||||||||||||||||
Transportation and Storage
|
$ | 186,563 | $ | 176,093 | $ | 560,328 | $ | 541,003 | |||||||||
Gathering and Processing
|
214,893 | 189,557 | 758,460 | 532,946 | |||||||||||||
Distribution
|
82,141 | 71,393 | 490,113 | 497,949 | |||||||||||||
Total segment operating revenues
|
483,597 | 437,043 | 1,808,901 | 1,571,898 | |||||||||||||
Corporate and other activities
|
3,930 | 1,408 | 10,716 | 3,441 | |||||||||||||
Total consolidated revenues from external
|
|||||||||||||||||
customers
|
$ | 487,527 | $ | 438,451 | $ | 1,819,617 | $ | 1,575,339 | |||||||||
Depreciation and amortization:
|
|||||||||||||||||
Transportation and Storage
|
$ | 31,191 | $ | 28,338 | $ | 91,264 | $ | 84,684 | |||||||||
Gathering and Processing
|
17,151 | 16,733 | 52,442 | 49,689 | |||||||||||||
Distribution
|
8,216 | 7,880 | 24,139 | 23,359 | |||||||||||||
Total segment depreciation and amortization
|
56,558 | 52,951 | 167,845 | 157,732 | |||||||||||||
Corporate and other activities
|
747 | 535 | 2,213 | 1,584 | |||||||||||||
Total depreciation and amortization expense
|
$ | 57,305 | $ | 53,486 | $ | 170,058 | $ | 159,316 | |||||||||
Earnings from unconsolidated investments:
|
|||||||||||||||||
Transportation and Storage
|
$ | 30,768 | $ | 22,715 | $ | 73,762 | $ | 60,483 | |||||||||
Gathering and Processing
|
1,017 | 1,338 | 3,397 | 2,364 | |||||||||||||
Corporate and other activities
|
551 | 368 | 1,297 | 841 | |||||||||||||
$ | 32,336 | $ | 24,421 | $ | 78,456 | $ | 63,688 | ||||||||||
Segment performance:
|
|||||||||||||||||
Transportation and Storage EBIT
|
$ | 112,099 | $ | 101,120 | $ | 325,770 | $ | 292,264 | |||||||||
Gathering and Processing EBIT
|
(11,366 | ) | 7,734 | 35,715 | (5,222 | ) | |||||||||||
Distribution EBIT
|
6,299 | 5,103 | 42,009 | 36,450 | |||||||||||||
Total segment EBIT
|
107,032 | 113,957 | 403,494 | 323,492 | |||||||||||||
Corporate and other activities
|
2,063 | 2,916 | 2,680 | 3,103 | |||||||||||||
Interest expense
|
55,239 | 50,234 | 161,551 | 146,969 | |||||||||||||
Federal and state income tax expense
|
16,525 | 19,720 | 75,943 | 53,170 | |||||||||||||
Net earnings
|
37,331 | 46,919 | 168,680 | 126,456 | |||||||||||||
Preferred stock dividends
|
699 | 2,171 | 5,040 | 6,512 | |||||||||||||
Loss on extinguishment of preferred stock
|
- | - | 3,295 | - | |||||||||||||
Net earnings available for common stockholders
|
$ | 36,632 | $ | 44,748 | $ | 160,345 | $ | 119,944 |
September 30,
|
December 31,
|
|||||||||||||||
2010
|
2009
|
|||||||||||||||
(In thousands)
|
||||||||||||||||
Total assets:
|
||||||||||||||||
Transportation and Storage
|
$ | 5,059,808 | $ | 5,138,042 | ||||||||||||
Gathering and Processing
|
1,670,539 | 1,666,935 | ||||||||||||||
Distribution
|
1,085,485 | 1,109,492 | ||||||||||||||
Total segment assets | 7,815,832 | 7,914,469 | ||||||||||||||
Corporate and other activities
|
196,400 | 160,605 | ||||||||||||||
Total consolidated assets
|
$ | 8,012,232 | $ | 8,075,074 | ||||||||||||
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands)
|
||||||||||||||||
Expenditures for long-lived assets:
|
||||||||||||||||
Transportation and Storage
|
$ | 58,363 | $ | 75,966 | $ | 114,620 | $ | 205,854 | ||||||||
Gathering and Processing
|
15,580 | 12,887 | 57,286 | 29,405 | ||||||||||||
Distribution
|
11,796 | 11,244 | 28,051 | 34,512 | ||||||||||||
Total segment expenditures for | ||||||||||||||||
long-lived assets
|
85,739 | 100,097 | 199,957 | 269,771 | ||||||||||||
Corporate and other activities
|
(2,185 | ) | 7,179 | 4,096 | 24,182 | |||||||||||
Total consolidated expenditures for
|
||||||||||||||||
long-lived assets (1)
|
$ | 83,554 | $ | 107,276 | $ | 204,053 | $ | 293,953 |
(1)
|
Related cash impact includes the net reduction in capital accruals totaling $
0.8 million and $8.8
million for the three-month periods ended September 30, 2010 and 2009, respectively. Related cash impact includes the net reduction in capital accruals totaling $
8.7 million and $19.2
million for the nine-month periods ended September 30, 2010 and 2009, respectively.
|
Shareholder Record Date
|
Date Paid
|
Amount Per Share
|
Amount Paid
|
|||||||
(In thousands)
|
||||||||||
September 24, 2010
|
October 8, 2010
|
$ | 0.15 | $ | 18,674 | |||||
June 25, 2010
|
July 9, 2010
|
0.15 | 18,672 | |||||||
March 26, 2010
|
April 9, 2010
|
0.15 | 18,665 | |||||||
|
16.
Other Income and Expense Items
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
EBIT:
|
||||||||||||||||
Transportation and storage segment
|
$ | 112,099 | $ | 101,120 | $ | 325,770 | $ | 292,264 | ||||||||
Gathering and processing segment
|
(11,366 | ) | 7,734 | 35,715 | (5,222 | ) | ||||||||||
Distribution segment
|
6,299 | 5,103 | 42,009 | 36,450 | ||||||||||||
Corporate and other activities
|
2,063 | 2,916 | 2,680 | 3,103 | ||||||||||||
Total EBIT
|
109,095 | 116,873 | 406,174 | 326,595 | ||||||||||||
Interest
|
55,239 | 50,234 | 161,551 | 146,969 | ||||||||||||
Earnings before income taxes
|
53,856 | 66,639 | 244,623 | 179,626 | ||||||||||||
Federal and state income taxes
|
16,525 | 19,720 | 75,943 | 53,170 | ||||||||||||
Net earnings
|
37,331 | 46,919 | 168,680 | 126,456 | ||||||||||||
Preferred stock dividends
|
699 | 2,171 | 5,040 | 6,512 | ||||||||||||
Loss on extinguishment of preferred stock
|
- | - | 3,295 | - | ||||||||||||
Net earnings available for common stockholders
|
$ | 36,632 | $ | 44,748 | $ | 160,345 | $ | 119,944 | ||||||||
·
|
Lower EBIT contribution of $19.1 million from the Gathering and Processing segment primarily resulting from a $46.7 increase in the cost of gas and other energy in the 2010 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010 and the impact of a net hedging loss of $23.9 million in the 2010 period versus a net hedging gain of $15.1 million in the 2009 period, partially offset by higher operating revenues of $64.3 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices; and
|
·
|
Higher interest expense of $5 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding.
|
·
|
Higher EBIT contribution of $11 million from the Transportation and Storage segment mainly due to higher equity earnings of $8.1 million from the Company’s unconsolidated investment in Citrus largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project and a higher contribution from Panhandle of $2.9 million primarily due to higher operating revenue of $10.5 million, partially offset by higher operating, maintenance and general expenses of $4.2 million and higher depreciation and amortization expense of $2.9 million;
|
·
|
Higher EBIT contribution of $1.2 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $4.4 million largely attributable to the impact of the new customer rates effective February 28, 2010, partially offset by higher operating, maintenance and general expenses of $2.9 primarily attributable to higher pension costs; and
|
·
|
Lower federal and state income tax expense of $3.2 million primarily due to lower pre-tax earnings of $12.8 million in 2010.
|
·
|
Higher EBIT contribution of $40.9 million from the Gathering and Processing segment primarily resulting from higher operating revenues of $230.9 million, excluding hedging gains and losses, attributable to higher market-driven realized average natural gas and NGL prices, partially offset by a $184.6 million increase in the cost of gas and other energy in the 2010 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010;
|
·
|
Higher EBIT contribution of $33.5 million from the Transportation and Storage segment primarily due to an increased contribution from Panhandle of $20.2 million mainly due to higher LNG revenues of $45.4 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010, partially offset by lower interruptible parking revenues of $21.4 million due to less favorable market conditions and the impact of a provision for repair and abandonment costs of $12.3 million in 2009 for damages to offshore assets resulting from Hurricane Ike. The Transportation and Storage segment was also favorably impacted by higher equity earnings of $13.3 million primarily due to Citrus’ higher other income of $25.5 million largely attributable to higher equity AFUDC resulting from the Florida Gas Phase VIII Expansion project, partially offset by higher income tax expense of $8.2 million; and
|
·
|
Higher EBIT contribution of $5.6 million from the Distribution segment primarily due to higher net operating revenues at Missouri Gas Energy of $13.3 million largely attributable to the impact of the new customer rates effective February 28, 2010, partially offset by the impact of a $3.5 million settlement in 2009 with an insurance company that released it from certain potential future environmental claim obligations.
|
·
|
Higher interest expense of $14.6 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding;
|
·
|
Higher federal and state income tax expense of $22.8 million primarily due to higher pre-tax earnings of $65 million in 2010; and
|
·
|
Impact of a $3.3 million loss recorded in the 2010 period related to the Company’s redemption of all of its approximately $115 million of outstanding Preferred Stock.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Operating revenues
|
$ | 186,563 | $ | 176,093 | $ | 560,328 | $ | 541,003 | ||||||||
Operating, maintenance and general
|
65,322 | 61,127 | 190,228 | 199,302 | ||||||||||||
Depreciation and amortization
|
31,191 | 28,338 | 91,264 | 84,684 | ||||||||||||
Taxes other than on income and revenues
|
8,731 | 8,398 | 26,856 | 25,636 | ||||||||||||
Total operating income
|
81,319 | 78,230 | 251,980 | 231,381 | ||||||||||||
Earnings from unconsolidated investments
|
30,768 | 22,715 | 73,762 | 60,483 | ||||||||||||
Other income, net
|
12 | 175 | 28 | 400 | ||||||||||||
EBIT
|
$ | 112,099 | $ | 101,120 | $ | 325,770 | $ | 292,264 | ||||||||
Operating information:
|
||||||||||||||||
Panhandle natural gas volumes transported (TBtu)
|
326 | 331 | 1,027 | 1,134 | ||||||||||||
Florida Gas natural gas volumes transported (TBtu) (1)
|
241 | 233 | 644 | 636 |
(1)
|
Represents 100 percent of natural gas volumes transported by Florida Gas versus the Company’s effective equity ownership interest of 50 percent.
|
·
|
Higher other income of $10.9 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the Phase VIII Expansion project;
|
·
|
Higher operating revenues of $2.8 million primarily due to certain higher rates associated with the Florida Gas rate case filing effective April 1, 2010 and higher short-term firm reservation revenues, partially offset by the provision for an estimated rate refund related to the Florida Gas rate case filing and lower transportation commodity revenues due to lower interruptible volumes;
|
·
|
Lower debt interest cost of $800,000 primarily due to higher capitalized debt AFUDC, largely attributable to higher Phase VIII Expansion project capital expenditures and lower interest expense resulting from the repayment of the $325 million 7.625% Senior Notes in August 2010, partially offset by higher interest on the $500 million 5.45% Senior Notes and the $350 million 4.00% Senior Notes issued in July 2010, and a higher rate on the $500 million construction and term loan, which was converted to a fixed rate of 9.393 percent in October 2009;
|
·
|
Higher operating expenses of $1.2 million primarily due to higher overall costs experienced in 2010 applicable to outside services costs, corporate services costs and other operating costs;
|
·
|
Higher depreciation expense of $900,000 primarily due to increased property, plant and equipment placed in service after September 30, 2009; and
|
·
|
Higher income tax expense of $4.6 million primarily due to higher pretax earnings.
|
·
|
Higher operating revenues of $10.5 million primarily due to:
|
o
|
Higher LNG revenues of $20.1 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;
|
o
|
Lower transportation reservation revenues of $5.3 million in 2010 versus 2009 primarily due to lower average rates realized on short-term firm capacity on PEPL, in addition to lower average rates realized on Trunkline; and
|
o
|
Lower interruptible parking revenues of $5.3 million primarily due to less favorable market conditions resulting in lower rates in 2010.
|
·
|
Higher operating, maintenance and general expenses of $4.2 million in 2010 versus 2009 primarily attributable to:
|
o
|
Impact of a net reduction of $3.5 million in the repair and abandonment cost provision for Hurricane Ike in the 2009 period;
|
o
|
A $1.1 million increase in administrative outside service costs primarily due to legal costs associated with ongoing litigation;
|
o
|
Higher allocated corporate services costs of $1.1 million primarily due to higher short- and long-term corporate incentive compensation;
|
o
|
A $900,000 increase in outside service costs for field operations primarily attributable to plant services related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010; and
|
o
|
Impact of a $2.8 million increase in environmental reserves in 2009 primarily attributable to estimated costs to remediate PCBs at the Company’s facilities; and
|
·
|
Increased depreciation and amortization expense of $2.9 million in 2010 versus 2009 due to a $582.4 million increase in property, plant and equipment placed in service after September 30, 2009. Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capitalized costs associated with the LNG terminal infrastructure enhancement construction project placed in service in March 2010.
|
·
|
Higher operating revenues of $19.3 million primarily due to:
|
o
|
Higher LNG revenues of $45.4 million largely attributable to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;
|
o
|
Higher transportation commodity revenues of $3.2 million primarily due to higher volumes flowing on Sea Robin in 2010 versus in 2009, the 2009 volumes having been adversely impacted by Hurricane Ike;
|
o
|
Lower interruptible parking revenues of $21.4 million primarily due to less favorable market conditions resulting in lower rates in 2010; and
|
o
|
Lower transportation reservation revenues of $9.9 million in 2010 versus 2009 primarily due to lower average rates realized on short-term firm capacity on PEPL, in addition to lower average rates realized on Trunkline;
|
·
|
Lower operating, maintenance and general expenses of $9.1 million in 2010 versus 2009 primarily attributable to:
|
o
|
Impact of a provision for repair and abandonment costs of $12.3 million recorded in 2009 for damages to offshore assets resulting from Hurricane Ike and a reduction in 2010 in the repair and abandonment provision for previous hurricane damages of $3.6 million primarily due to project scope reductions resulting from favorable weather conditions experienced and realized project efficiencies;
|
o
|
Impact of a $3.8 million increase in environmental reserves in 2009 primarily attributable to estimated costs to remediate PCBs at the Company’s facilities;
|
o
|
A $5.5 million increase in outside service costs for field operations primarily attributable to plant services related to the LNG terminal infrastructure enhancement construction project placed in service in March 2010 and higher in-line inspection costs;
|
o
|
Higher allocated corporate services costs of $3.6 million primarily due to higher short- and long-term corporate incentive compensation; and
|
o
|
A $2.6 million increase in legal costs primarily due to ongoing litigation; and
|
·
|
Increased depreciation and amortization expense of $6.6 million in 2010 versus 2009 due to a $582.4 million increase in property, plant and equipment placed in service after September 30, 2009. Depreciation and amortization expense is expected to continue to increase primarily due to significant capital additions, including capitalized costs associated with the LNG terminal infrastructure enhancement construction project placed in service in March 2010.
|
·
|
Higher other income of $25.5 million largely driven by higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project. Due to the increasing levels of capitalized project costs, AFUDC is expected to continue to trend higher until completion of the Phase VIII Expansion project;
|
·
|
Higher operating revenues of $6 million primarily due to certain higher rates associated with the Florida Gas rate case filing effective April 1, 2010 and higher short-term firm reservation revenues, partially offset by the provision for an estimated rate refund and lower transportation commodity revenues due to lower interruptible volumes;
|
·
|
Higher debt interest cost of $3.7 million primarily due to interest on the $600 million 7.90% Senior Notes issued in May 2009, the $500 million 5.45% Senior Notes and $350 million 4.00% Senior Notes issued in July 2010, and a higher rate on the $500 million construction and term loan which was converted to a fixed rate of 9.393 percent in October 2009, partially offset by higher capitalized debt AFUDC, largely attributable to higher Phase VIII Expansion project capital expenditures;
|
·
|
Higher operating expenses of $3.3 million primarily due to higher overall costs experienced in 2010 applicable to outside services costs, corporate services costs, transportation, and other operating costs;
|
·
|
Higher depreciation expense of $2.9 million primarily due to increased property, plant and equipment placed in service after September 30, 2009; and
|
·
|
Higher income tax expense of $8.2 million primarily due to higher pretax earnings.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Operating revenues, excluding impact of
|
||||||||||||||||
commodity derivative instruments
|
$ | 238,804 | $ | 174,498 | $ | 761,431 | $ | 530,499 | ||||||||
Realized and unrealized commodity derivatives
|
(23,911 | ) | 15,059 | (2,971 | ) | 2,447 | ||||||||||
Operating revenues
|
214,893 | 189,557 | 758,460 | 532,946 | ||||||||||||
Cost of gas and other energy (1)
|
(189,156 | ) | (142,455 | ) | (611,405 | ) | (426,853 | ) | ||||||||
Gross margin (2)
|
25,737 | 47,102 | 147,055 | 106,093 | ||||||||||||
Operating, maintenance and general
|
19,897 | 22,736 | 58,260 | 60,521 | ||||||||||||
Depreciation and amortization
|
17,151 | 16,733 | 52,442 | 49,689 | ||||||||||||
Taxes other than on income and revenues
|
1,388 | 1,210 | 4,353 | 3,716 | ||||||||||||
Total operating income
|
(12,699 | ) | 6,423 | 32,000 | (7,833 | ) | ||||||||||
Earnings from unconsolidated investments
|
1,017 | 1,338 | 3,397 | 2,364 | ||||||||||||
Other expense, net
|
316 | (27 | ) | 318 | 247 | |||||||||||
EBIT
|
$ | (11,366 | ) | $ | 7,734 | $ | 35,715 | $ | (5,222 | ) | ||||||
Operating Statistics:
|
||||||||||||||||
Volumes
|
||||||||||||||||
Avg natural gas processed (MMBtu/d)
|
444,316 | 357,182 | 431,544 | 395,054 | ||||||||||||
Avg NGL produced (gallons/d)
|
1,521,859 | 1,162,488 | 1,458,582 | 1,308,472 | ||||||||||||
Avg natural gas wellhead volumes (MMBtu/d)
|
536,724 | 530,558 | 536,858 | 569,649 | ||||||||||||
Natural gas sales (MMBtu) (3)
|
20,905,163 | 22,871,214 | 61,286,222 | 68,100,131 | ||||||||||||
NGL sales (gallons) (3)
|
165,018,837 | 125,247,667 | 471,467,923 | 435,737,044 | ||||||||||||
Average Pricing
|
||||||||||||||||
Realized natural gas ($/MMBtu) (4)
|
$ | 3.99 | $ | 3.08 | $ | 4.38 | $ | 3.20 | ||||||||
Realized NGL ($/gallon) (4)
|
0.92 | 0.81 | 1.03 | 0.70 | ||||||||||||
Natural Gas Daily WAHA ($/MMBtu)
|
4.01 | 3.08 | 4.39 | 3.20 | ||||||||||||
Natural Gas Daily El Paso ($/MMBtu)
|
3.94 | 3.05 | 4.33 | 3.13 | ||||||||||||
Estimated plant processing spread ($/gallon)
|
0.56 | 0.52 | 0.61 | 0.41 |
|
________________
|
(1)
|
Cost of natural gas and other energy
consists of natural gas and NGL purchase costs and producer and other fees.
|
(2)
|
Gross margin consists of
Operating revenues
less
Cost of natural gas and other energy
. The Company believes that this measure is more meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.
|
(3)
|
Volumes processed by SUGS include volumes sold under various buy-sell arrangements. For the three-month periods ended September 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $10.4 million and $8.5 million, and 2,291,000 MMBtus and 2,713,000 MMBtus, respectively. The Company’s operating revenues and related volumes for the three-month periods ended September 30, 2010 and 2009 attributable to its buy-sell arrangements for NGL totaled $29.2 million and $15.3 million, and 32,598,000 gallons and 19,923,000 gallons, respectively. For the nine-month periods ended September 30, 2010 and 2009, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $35 million and $30 million, and 7,040,000 MMBtus and 9,057,000 MMBtus, respectively. The Company’s operating revenues and related volumes for the nine-month periods ended September 30, 2010 and 2009 attributable to its buy-sell arrangements for NGL totaled $86.2 million and $41.9 million, and 90,957,000 gallons and 63,037,000 gallons, respectively.
|
(4)
|
Excludes impact of realized and unrealized commodity derivative gains and losses detailed in the above EBIT presentation.
|
·
|
Lower gross margin of $21.4 million primarily as the result of:
|
o
|
Higher operating revenues of $64.3 million largely attributable to higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.99 per MMBtu and $0.92 per gallon in the 2010 period versus $3.08 per MMBtu and $0.81 per gallon in the 2009 period, respectively;
|
o
|
A $46.7 million increase in the cost of gas and other energy in the 2010 period versus the 2009 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010;
|
o
|
Impact of a net hedging loss of $23.9 million in the 2010 period versus a net hedging gain of $15.1 million in the 2009 period (which includes the impact of $29.2 million of unrealized losses recorded in 2010); and
|
o
|
Impact of approximately $4.6 million reduction in gross margin in 2009 attributable to a fire on July 17, 2009 at the Keystone processing plant resulting in a production outage until August 1, 2009; and
|
·
|
Lower operating, maintenance and general expenses of $2.8 million primarily due to:
|
o
|
Impact of a $4.5 million net loss in 2009 versus 2010 resulting from the write-off of property and equipment damaged by the fire at the Keystone natural gas processing plant in 2009;
|
o
|
Higher benefits, labor, and allocated corporate services costs of $1.1 million primarily due to higher short-term and long-term incentive compensation;
|
o
|
Higher contract services, chemicals and lubricants, and other operating costs of $500,000 primarily associated with the Mi Vida treater, which was returned to service during the first quarter of 2010.
|
·
|
Higher gross margin of $41 million primarily as the result of:
|
o
|
Higher operating revenues of $230.9 million largely attributable to higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $4.38 per MMBtu and $1.03 per gallon in the 2010 period versus $3.20 per MMBtu and $0.70 per gallon in the 2009 period, respectively, partially offset by the impact of lower system volumes as a result of well freeze-offs that occurred in early 2010;
|
o
|
A $184.6 million increase in the cost of gas and other energy in the 2010 period versus the 2009 period due to higher market-driven natural gas and NGL purchase costs and higher fractionation fees related to the change in fractionation provider in 2010;
|
o
|
Impact of a net hedging loss of $3 million in the 2010 period versus a net hedging gain of $2.4 million in the 2009 period (which includes the impact of $12.6 million of unrealized losses recorded in 2010); and
|
o
|
Impact of approximately $4.6 million reduction in gross margin in 2009 attributable to a fire on July 17, 2009 at the Keystone processing plant resulting in a production outage until August 1, 2009;
|
·
|
Lower operating, maintenance and general expenses of $2.3 million primarily due to:
|
o
|
Impact of a $4.5 million net loss in 2009 versus 2010 resulting from the write-off of property and equipment damaged by the fire at the Keystone natural gas processing plant in 2009;
|
o
|
Higher benefits, labor, and allocated corporate services costs of $1.9 million primarily due to higher short-term and long-term incentive compensation; and
|
o
|
Higher contract services, chemicals and lubricants, and other operating costs of $1.1 million primarily associated with the Mi Vida treater, which was returned to service during the first quarter of 2010;
|
·
|
Higher equity earnings from unconsolidated investments of $1 million primarily due to increased fee-based revenues resulting from higher throughput volumes in the 2010 period versus the 2009 period at the Grey Ranch natural gas treatment facility. The Grey Ranch facility is currently expected to be idled for the majority of the fourth quarter of 2010; and
|
·
|
Higher depreciation and amortization expense of $2.8 million primarily attributable to a $59.7 million increase in property, plant and equipment placed in service after September 30, 2009.
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||
September 30,
|
September 30,
|
||||||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||||||
(In thousands)
|
|||||||||||||||||
Net operating revenues (1)
|
$ | 49,932 | $ | 45,528 | $ | 174,171 | $ | 162,962 | |||||||||
Operating, maintenance and general
|
32,229 | 29,371 | 98,106 | 96,292 | |||||||||||||
Depreciation and amortization
|
8,216 | 7,880 | 24,139 | 23,359 | |||||||||||||
Taxes other than on income and revenues
|
3,154 | 3,047 | 9,666 | 9,929 | |||||||||||||
Total operating income (loss)
|
6,333 | 5,230 | 42,260 | 33,382 | |||||||||||||
Other income (expenses), net
|
(34 | ) | (127 | ) | (251 | ) | 3,068 | ||||||||||
EBIT
|
$ | 6,299 | $ | 5,103 | $ | 42,009 | $ | 36,450 | |||||||||
Operating Information:
|
|||||||||||||||||
Natural Gas sales volumes (MMcf)
|
3,291 | 3,718 | 44,132 | 42,524 | |||||||||||||
Natural Gas transported volumes (MMcf)
|
5,316 | 5,033 | 20,072 | 18,999 | |||||||||||||
Weather – Degree Days:
(2)
|
|||||||||||||||||
Missouri Gas Energy service territories
|
25 | 43 | 3,199 | 2,996 | |||||||||||||
New England Gas Company service territories
|
32 | 80 | 3,407 | 3,827 | |||||||||||||
(1)
|
Operating revenues for the Distribution segment are reported net of
Cost of natural gas and other energy
and
Revenue-related taxes
, which are pass-through costs.
|
(2)
|
"Degree days" are a measure of the coldness of the weather experienced. A degree day is equivalent to each degree that the daily mean temperature for a day falls below 65 degrees Fahrenheit.
|
·
|
Higher net operating revenues of $4.4 million primarily due to $5.6 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues. This revenue increase was partially offset by lower revenues of $900,000 at New England Gas Company primarily due to adjustments recorded in 2009 related to certain benefit costs recovered in rates; and
|
·
|
Higher operating, maintenance and general expenses of $2.9 million primarily attributable to:
|
o
|
Higher pension costs of $1 million, which are recovered in current rates;
|
o
|
Higher legal costs of $800,000 primarily due to ongoing litigation; and
|
o
|
Higher labor costs of $400,000 largely due to new positions filled and merit and incentive increases in the 2010 period.
|
·
|
Higher net operating revenues of $11.2 million primarily due to $13.3 million of higher net operating revenues at Missouri Gas Energy largely attributable to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues. This revenue increase was partially offset by lower revenues of $1.9 million at New England Gas Company primarily due to warmer weather in the 2010 period;
|
·
|
Lower other income, net, of $3.3 million primarily due to a $3.5 million settlement in 2009 with an insurance company that released it from certain potential future environmental claim obligations; and
|
·
|
Higher operating, maintenance and general expenses of $1.8 million primarily attributable to:
|
o
|
Higher pension costs of $2.3 million, which are recovered in current rates;
|
o
|
Higher labor costs of $1.8 million largely due to new positions filled and merit and incentive increases in the 2010 period;
|
o
|
Lower provisions for uncollectible customer accounts of approximately $1.5 million primarily resulting from improved collectability on aged accounts receivables at Missouri Gas Energy; and
|
o
|
Impact of a $1.5 million settlement in 2010 for a previous environmental cost reimbursement claim made by the Company.
|
·
|
Collection in the 2009 period of a $1.8 million settlement awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin; and
|
·
|
A higher net sales margin contribution of $1.2 million from PEI Power Corporation largely due to increased electric generation attributable to higher landfill gas volumes.
|
·
|
Impact of a settlement gain of $1.9 million in March 2009 with an insurance company related to certain environmental matters;
|
·
|
Collection in the 2009 period of a $1.8 million settlement awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin; and
|
·
|
A higher net sales margin contribution of $3.5 million from PEI Power Corporation largely due to increased electric generation primarily attributable to higher landfill gas volumes.
|
·
|
Higher interest expense of $6.5 million primarily due to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding in 2010 compared to 2009 largely resulting from the Trunkline LNG infrastructure enhancement project being placed in service in March 2010;
|
·
|
Higher interest expense of $1.1 million associated with borrowings under the Company’s credit facilities primarily due to higher average rates and higher average outstanding balances in 2010 compared to 2009;
|
·
|
Lower net interest expense of $1.9 million primarily due to lower outstanding debt balances resulting from the repayment of the $100 million 6.089% Senior Notes in February 2010, the $40.5 million 8.25% Senior Notes in April 2010, and the $60.6 million 6.50% Senior Notes in July 2009, partially offset by the impact of the $150 million term loan issued in August 2009; and
|
·
|
Lower interest expense of $800,000 primarily due to the impact of lower debt issuance cost amortization in 2010 due to repayments of the related debt.
|
·
|
Higher interest expense of $12.4 million primarily due to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding in 2010 compared to 2009 largely resulting from the Trunkline LNG infrastructure enhancement project being placed in service in March 2010;
|
·
|
Higher net interest expense of $1.1 million primarily due to higher outstanding debt balances from the $150 million 8.125% Senior Notes issued in June 2009 and the $150 million term loan issued in August 2009, partially offset by lower interest expense resulting from the repayment of the $100 million 6.089% Senior Notes in February 2010, the $40.5 million 8.25% Senior Notes in April 2010, and the $60.6 million 6.50% Senior Notes in July 2009; and
|
·
|
Higher interest expense of $800,000 primarily due to the impact of higher debt issuance cost amortization in 2010 related to additional issuance cost associated with the $150 million term loan issued in August 2009 and an increase in the commitment availability of the credit facilities in February 2010 from $400 million to $550 million, and lower debt premium amortizations due to repayments of the related debt in 2009.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Income tax expense
|
$ | 16,525 | $ | 19,720 | $ | 75,943 | $ | 53,170 | ||||||||
Effective tax rate (1)
|
31 | % | 30 | % | 31 | % | 30 | % | ||||||||
(1)
|
The EITR is lower than the U.S. federal income tax statutory rate of 35 percent primarily due to the 80 percent dividends received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated Citrus affiliate, partially offset by the impact of state income taxes, net of the federal income tax benefit.
|
Nine months ended September 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Cash flows provided by (used in):
|
||||||||
Operating activities
|
$ | 360,433 | $ | 464,413 | ||||
Investing activities
|
(218,570 | ) | (319,422 | ) | ||||
Financing activities
|
(135,286 | ) | (142,272 | ) | ||||
Increase (decrease) in cash and cash equivalents
|
$ | 6,577 | $ | 2,719 |
·
|
Decreased net cash settlements of $70.8 million of commodity derivative instruments in the Gathering and Processing segment in the 2010 period versus the 2009 period;
|
·
|
A decrease of $58.7 million in the Distribution segment primarily due to the timing of cash receipts from revenues, resulting in increased accounts receivable; and
|
·
|
An increase in cash used to purchase inventories of $53.9 million in the Distribution segment in the 2010 period primarily due to higher natural gas prices.
|
Nine Months Ended
|
||||||||
September 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Transportation and Storage Segment:
|
||||||||
LNG Terminal Expansions/Enhancements
|
$ | 21,980 | $ | 75,995 | ||||
Compression Modernization
|
(256 | ) | 6,462 | |||||
Other, primarily pipeline integrity, system
|
||||||||
reliability, information technology, air
|
||||||||
emission compliance and hurricane
|
||||||||
expenditures
|
92,896 | 123,397 | ||||||
Total
|
114,620 | 205,854 | ||||||
Gathering and Processing Segment
|
57,286 | 29,405 | ||||||
Distribution Segment:
|
||||||||
Missouri Safety Program
|
8,422 | 10,259 | ||||||
Other, primarily system replacement
|
||||||||
and expansion
|
19,629 | 24,253 | ||||||
Total
|
28,051 | 34,512 | ||||||
Corporate and other activities
|
4,096 | 24,182 | ||||||
Total (1)
|
$ | 204,053 | $ | 293,953 |
(1)
|
Related cash impact includes the net reduction in capital accruals totaling $8.7 million and $19.2
million for the nine-month periods ended September 30, 2010 and 2009, respectively.
|
·
|
Borrowings of $100 million under the Company’s credit facilities in the 2010 period compared to $321.5 million in payments in 2009;
|
·
|
Payments of $115 million to redeem all of the Company’s outstanding Preferred Stock; and
|
·
|
Net repayments of $40 million of long-term debt in the 2010 period, compared to net issuances of $242 million in the 2009 period.
|
·
|
Borrowing costs associated with debt obligations could increase annually up to approximately $6 million;
|
·
|
The costs of maintaining certain contractual relationships could increase, primarily related to the potential requirement for the Company to post collateral associated with its derivative financial instruments; and
|
·
|
Regulators may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.
|
·
|
Processing plant outages;
|
·
|
Higher than anticipated fuel, flare and unaccounted-for natural gas levels;
|
·
|
Impact of commodity prices in general;
|
·
|
Decline in drilling and/or connections of new supply;
|
·
|
Reduction in available NGL take-away capacity;
|
·
|
Reduction in NGL available from wellhead supply;
|
·
|
Lower than expected recovery of NGL from the inlet natural gas stream;
|
·
|
Lower than expected receipt of natural gas volumes to be processed;
|
·
|
Limitations on NGL fractionation capacity;
|
·
|
Renegotiation of existing contracts;
|
·
|
Change in contracting practices vis-à-vis type(s) of processing contracts; and
|
·
|
Competition for new wellhead supplies.
|
Average
|
Volumes
|
Fair Value
|
|||||||||||||||
Fixed Price
|
(MMBtu/d)
(3)
|
of Assets
|
|||||||||||||||
Instrument Type
|
Index
|
(per MMBtu)
|
2010
|
2011
|
(Liabilities)
(4)
|
||||||||||||
(In thousands)
|
|||||||||||||||||
Natural Gas - Cash Flow Hedges: (1)
|
|||||||||||||||||
Receive-fixed swap
|
Gas Daily - Waha
|
$ | 5.33 | 24,863 | - | $ | 3,638 | ||||||||||
Receive-fixed swap
|
Gas Daily - Waha
|
$ | 6.12 | - | 13,813 | 9,630 | |||||||||||
Receive-fixed swap
|
Gas Daily - El Paso Permian
|
$ | 5.33 | 20,137 | - | 2,947 | |||||||||||
Receive-fixed swap
|
Gas Daily - El Paso Permian
|
$ | 6.12 | - | 11,187 | 7,799 | |||||||||||
Total
|
45,000 | 25,000 | $ | 24,014 | |||||||||||||
Processing Spread - Economic Hedges: (2)
|
|||||||||||||||||
Receive-fixed swap
|
Gas Daily - Waha (natural gas)
|
||||||||||||||||
OPIS - Mt. Belvieu (NGL)
|
$ | 5.11 | 22,100 | - | $ | (7,121 | ) | ||||||||||
Receive-fixed swap
|
Gas Daily - Waha (natural gas)
|
||||||||||||||||
OPIS - Mt. Belvieu (NGL)
|
$ | 5.51 | - | 13,813 | (9,306 | ) | |||||||||||
Receive-fixed swap
|
Gas Daily - El Paso Permian (natural gas)
|
||||||||||||||||
OPIS - Mt. Belvieu (NGL)
|
$ | 5.11 | 17,900 | - | (5,767 | ) | |||||||||||
Receive-fixed swap
|
Gas Daily - El Paso Permian (natural gas)
|
||||||||||||||||
OPIS - Mt. Belvieu (NGL)
|
$ | 5.51 | - | 11,187 | (7,537 | ) | |||||||||||
Total
|
40,000 | 25,000 | $ | (29,731 | ) |
(1)
|
The Company’s natural gas swap arrangements have been designated as cash flow hedges. The effective portion of changes in the fair value of the cash flow hedges is recorded in
Accumulated other comprehensive loss
until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in current-period earnings.
|
(2)
|
The Company’s processing spread swap arrangements, which hedge the pricing differential between NGL volumes and equivalent natural gas volumes, are treated as economic hedges. The ratio of NGL product sold per MMBtu is approximately: 33 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 16 percent natural gasoline. The change in fair value is reported in current-period earnings.
|
(3)
|
All volumes are applicable to the period October 1, 2010 to December 31, 2010 and January 1, 2011 to December 31, 2011, as applicable.
|
(4)
|
See
Part I, Item 1. Financial Statements (Unaudited),
Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment
for additional related information.
|
·
|
changes in demand for natural gas or NGL and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas or NGL available to the Company;
|
·
|
the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or NGL as well as electricity, oil, coal and commodity and other bulk materials and chemicals;
|
·
|
adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters;
|
·
|
changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;
|
·
|
the speed and degree to which additional competition, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues;
|
·
|
the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries;
|
·
|
the ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations;
|
·
|
unanticipated environmental liabilities;
|
·
|
the uncertainty of estimates, including accruals and costs of environmental remediation;
|
·
|
the impact of potential impairment charges;
|
·
|
exposure to highly competitive commodity businesses and the effectiveness of the Company's hedging program;
|
·
|
the ability to acquire new businesses and assets and integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;
|
·
|
the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects;
|
·
|
the ability to complete expansion projects on time and on budget;
|
·
|
the ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;
|
·
|
the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;
|
·
|
the performance of contractual obligations by customers, service providers and contractors;
|
·
|
exposure to customer concentrations with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers;
|
·
|
changes in the ratings of the Company’s debt securities;
|
·
|
the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets;
|
·
|
the impact of unsold pipeline capacity being greater than expected;
|
·
|
changes in interest rates and other general market and economic conditions, and in the Company’s ability to continue to access its revolving credit facility and to obtain additional financing on acceptable terms, whether in the capital markets or otherwise;
|
·
|
declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans and other postretirement benefit plans;
|
·
|
acts of nature, sabotage, terrorism or other similar acts that cause damage to the facilities or those of the Company’s suppliers' or customers' facilities;
|
·
|
market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness;
|
·
|
the availability/cost of insurance coverage and the ability to collect under existing insurance policies;
|
·
|
the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant;
|
·
|
changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;
|
·
|
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives and authorized rates of recovery of costs (including pipeline relocation costs);
|
·
|
market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts; and
|
·
|
other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC.
|
Total Number of
|
Average Price
|
|||||||
Period
|
Shares Purchased (1)
|
Paid per Share
|
||||||
July 2010
|
6,394 | $ | 22.13 | |||||
August 2010
|
53 | 23.13 | ||||||
September 2010
|
4,463 | 24.27 | ||||||
Total
|
10,910 | $ | 23.01 |
(1)
|
The total number of shares purchased includes common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans.)
|
|
2(a)
|
Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)
|
|
2(b)
|
First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
|
|
2(c)
|
Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)
|
|
2
(
d
)
|
Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
|
|
2(e)
|
First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)
|
|
3(a)
|
Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)
|
|
3(b)
|
By-Laws of Southern Union Company, as amended. (Filed as Exhibit 3(b) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference.)
|
|
3(c)
|
Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 and incorporated herein by reference.)
|
|
4(a)
|
Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)
|
|
4(b)
|
Senior Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as Trustee (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K dated February 15, 1994 and incorporated here-in by reference.)
|
|
4(c)
|
Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024. (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)
|
|
4(d)
|
Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029. (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)
|
|
4(e)
|
Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)
|
|
4(f)
|
Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)
|
4(g)
|
Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)
|
|
4(h)
|
Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)
|
|
4(i)
|
2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006. (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
|
|
4(j)
|
Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)
|
4(k)
|
Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union. Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.
|
|
10(a)
|
Sixth Amended and Restated Revolving Credit Agreement, dated as of February 26, 2010, among the Company, as borrower, and the lenders party
thereto. (Filed as Exhibit 10(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference.)
|
|
10(b)
|
Amended and Restated Credit Agreement, dated as of August 3, 2010, among the Company, as borrower, and the lenders party thereto (Filed as Exhibit 10(b) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference).
|
|
10(c)
|
First Amendment to Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of August 6, 2008. (Filed as Exhibit 10(a) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
|
|
10(d)
|
Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)
|
|
10(e)
|
Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008. (Filed as Exhibit 10(d) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)
|
|
10(f)
|
Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)
|
|
10(g)
|
Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)
|
|
10(h)
|
Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company and certain senior executive officers. (Filed as Exhibit 10(g) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)
|
|
10(i)
|
Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.) *
|
|
10(j)
|
Southern Union Company Director's Deferred Compensation Plan. (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)
|
|
10(k)
|
First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference.)
|
|
10(l)
|
Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments. (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.) *
|
|
10(m)
|
Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.) *
|
10(n)
|
Third Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on April 16, 2009 and incorporated herein by reference).*
|
|
10(o)
|
Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.) *
|
|
10(p)
|
Employment Agreement between Southern Union Company and George L. Lindemann, dated as of August 28, 2008. (Filed as Exhibit 10(f) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
|
|
10(q)
|
Employment Agreement between Southern Union Company and Eric D. Herschmann, dated as of August 28, 2008. (Filed as Exhibit 10(g) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
|
|
10(r)
|
Employment Agreement between Southern Union Company and Robert O. Bond, dated as of August 28, 2008. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
|
|
10(s)
|
Employment Agreement between Southern Union Company and Monica M. Gaudiosi, dated as of August 28, 2008. (Filed as Exhibit 10(i) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
|
10(t)
|
Second Amended and Restated Southern Union Company Executive Incentive Bonus Plan, dated March 25, 2010 (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on March 26, 2006 and incorporate herein by reference.) *
|
|
10(u)
|
Employment Agreement between Southern Union Company and Richard N. Marshall, dated as of August 28, 2008. (Filed as Exhibit 10(j) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *
|
|
10(v)
|
Form of Change in Control Severance Agreement, between Southern Union Company and certain Executives (filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 28, 2008 and incorporated herein by reference.) *
|
10(w)
|
Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(t) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)
|
10(x)
|
Certificate of Incorporation of Citrus Corp. (Filed as Exhibit 10(q) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)
|
10(y)
|
By-Laws of Citrus Corp., filed herewith. (Filed as Exhibit 10(r) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)
|
|
12
|
Ratio of earnings to fixed charges. (Filed herewith as Exhibit 12.)
|
|
14
|
Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)
|
|
|
31.1
|
Certificate by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.1
|
Certificate by Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
|
|
32.2
|
Certificate by Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
|
101.INS
|
XBRL Instance Document **
|
101.SCH
|
XBRL Taxonomy Extension Schema Document **
|
101.CAL
|
XBRL Taxonomy Calculation Linkbase Document **
|
101.DEF
|
XBRL Taxonomy Extension Definitions Document **
|
101.LAB
|
XBRL Taxonomy Label Linkbase Document **
|
101.PRE
|
XBRL Taxonomy Presentation Linkbase Document **
|
SOUTHERN UNION COMPANY
|
|
|
(Registrant)
|
Date: November 4, 2010
|
By
/s/ GEORGE E. ALDRICH
|
George E. Aldrich
Senior Vice President and Controller
(authorized officer and principal
accounting officer)
|
|
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