UNITED
STATES
|
SECURITIES
AND EXCHANGE COMMISSION
|
Washington,
D.C. 20549
|
|
FORM
10-Q
|
|
(Mark One)
|
|
þ
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
the Quarterly Period Ended September 30, 2008
|
|
OR
|
|
¨
TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d)
OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
the transition period
from to
|
|
Commission
File Number 1-14174
|
|
AGL
RESOURCES INC.
|
(Exact
name of registrant as specified in its charter)
|
|
Georgia
|
58-2210952
|
(State
or other jurisdiction of incorporation or organization)
|
(I.R.S.
Employer Identification No.)
|
|
Ten
Peachtree Place NE, Atlanta, Georgia 30309
|
(Address
and zip code of principal executive offices)
|
|
404-584-4000
|
(Registrant's
telephone number, including area code)
|
|
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes
þ
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
þ
|
Accelerated filer
¨
|
Non-accelerated
filer
¨
(Do not check if a smaller
reporting company)
|
Smaller reporting company
¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Exchange Act Rule 12b-2). Yes
¨
No
þ
|
|
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock as of the latest practicable date.
|
|
Class
|
Outstanding
as of October 22, 2008
|
Common
Stock, $5.00 Par Value
|
76,780,439
|
AGL
RESOURCES INC.
Quarterly
Report on Form 10-Q
For the
Quarter Ended September 30, 2008
AFUDC
|
Allowance
for funds used during construction, which has been authorized by
applicable state regulatory agencies to record the cost of debt and equity
funds as part of the cost of construction projects
|
AGL
Capital
|
AGL
Capital Corporation
|
AGL
Networks
|
AGL
Networks, LLC
|
Atlanta
Gas Light
|
Atlanta
Gas Light Company
|
Bcf
|
Billion
cubic feet
|
Chattanooga
Gas
|
Chattanooga
Gas Company
|
Credit
Facility
|
Credit
agreements supporting our commercial paper program
|
EBIT
|
Earnings
before interest and taxes, a non-GAAP measure that includes operating
income, other income, minority interest in SouthStar’s earnings and gain
on sales of assets and excludes interest and income tax expense; as an
indictor of our operating performance, EBIT should not be considered an
alternative to, or more meaningful than, operating income or net income as
determined in accordance with GAAP
|
EITF
|
Emerging
Issues Task Force
|
ERC
|
Environmental
remediation costs associated with our distribution operations segment
which are recoverable through rates mechanisms
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy Regulatory Commission
|
FIN
|
FASB
Interpretation Number
|
Fitch
|
Fitch
Ratings
|
Florida
Commission
|
Florida
Public Service Commission
|
FSP
|
FASB
Staff Position
|
GAAP
|
Accounting
principles generally accepted in the United States of
America
|
Georgia
Commission
|
Georgia
Public Service Commission
|
GNG
|
Georgia
Natural Gas, the name under which SouthStar does business in
Georgia
|
Golden
Triangle Storage
|
Golden
Triangle Storage, Inc.
|
Heating
Degree Days
|
A
measure of the effects of weather on our businesses, calculated when the
average daily actual temperatures are less than a baseline temperature of
65 degrees Fahrenheit.
|
Heating
Season
|
The
period from November to March when natural gas usage and operating
revenues are generally higher because more customers are connected to our
distribution systems when weather is colder
|
Jefferson
Island
|
Jefferson
Island Storage & Hub, LLC
|
LOCOM
|
Lower
of weighted average cost or current market price
|
Maryland
Commission
|
Maryland
Public Service Commission
|
Marketers
|
Marketers
selling retail natural gas in Georgia and certificated by the Georgia
Commission
|
MMBtu
|
NYMEX
equivalent contract units of 10,000 million British thermal
units
|
Moody’s
|
Moody’s
Investors Service
|
New
Jersey Commission
|
New
Jersey Board of Public Utilities
|
NYMEX
|
New
York Mercantile Exchange, Inc.
|
OCI
|
Other
comprehensive income
|
Operating
margin
|
A
non-GAAP measure of income, calculated as revenues minus cost of gas, that
excludes operation and maintenance expense, depreciation and amortization,
taxes other than income taxes, and the gain or loss on the sale of our
assets; these items are included in our calculation of operating income as
reflected in our statements of consolidated income. Operating margin
should not be considered an alternative to, or more meaningful than
operating income or net income as determined tin accordance with
GAAP
|
OTC
|
Over-the-counter
|
Piedmont
|
Piedmont
Natural Gas
|
Pivotal
Utility
|
Pivotal
Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas
and Florida City Gas
|
PGA
|
Purchased
gas adjustment
|
PP&E
|
Property,
plant and equipment
|
PRP
|
Pipeline
replacement program for Atlanta Gas Light
|
S&P
|
Standard
& Poor’s Ratings Services
|
SEC
|
Securities
and Exchange Commission
|
Sequent
|
Sequent
Energy Management, L.P.
|
SFAS
|
Statement
of Financial Accounting Standards
|
SouthStar
|
SouthStar
Energy Services LLC
|
VaR
|
Value
at risk is defined as the maximum potential loss in portfolio value over a
specified time period that is not expected to be exceeded within a given
degree of probability
|
Virginia
Natural Gas
|
Virginia
Natural Gas, Inc.
|
Virginia
Commission
|
Virginia
State Corporation Commission
|
WACOG
|
Weighted
average cost of gas
|
WNA
|
Weather
normalization adjustment
|
REFERENCED
ACCOUNTING STANDARDS
FSP
FIN 39-1
|
FASB
Staff Position 39-1 “Amendment of FIN 39”
|
FIN
46 & FIN 46R
|
FIN
46, “Consolidation of Variable Interest Entities”
|
FIN
48
|
FIN
48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS
Statement No. 109”
|
FSP
EITF 03-6-1
|
FSP
EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities”
|
FSP
EITF 06-3
|
FSP
EITF 06-3, “How Taxes Collected from Customers and Remitted to
Governmental Authorities Should be Presented in the Income Statement (That
Is, Gross versus Net Presentation)”
|
FSP
FAS 133-1
|
FSP
No. FAS 133-1, “Disclosures about Credit Derivatives and Certain
Guarantees: An Amendment of FASB Statement No. 133”
|
FSP
FAS 157-3
|
FSP
No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the
Market for That Asset Is Not Active”
|
SFAS
71
|
SFAS
No. 71, “Accounting for the Effects of Certain Types of
Regulation”
|
SFAS
133
|
SFAS
No. 133, “Accounting for Derivative Instruments and Hedging
Activities”
|
SFAS
141
|
SFAS
No. 141, “Business Combinations”
|
SFAS
157
|
SFAS
No. 157, “Fair Value Measurements”
|
SFAS
160
|
SFAS
No. 160, “Noncontrolling Interests in Consolidated Financial
Statements”
|
SFAS
161
|
SFAS
No. 161, “Disclosure about Derivative Instruments and Hedging Activities,
an amendment of SFAS 133”
|
|
|
PART
1 – Financial Information
Item
1. Financial Statements
AGL
RESOURCES INC. AND
SUBSIDIARIES
(UNAUDITED)
|
|
|
|
|
As
of
|
|
|
|
|
In
millions, except share data
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
September
30, 2007
|
|
Current
assets
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
11
|
|
|
$
|
19
|
|
|
$
|
14
|
|
Energy
marketing receivables
|
|
|
535
|
|
|
|
598
|
|
|
|
363
|
|
Inventories
|
|
|
811
|
|
|
|
551
|
|
|
|
654
|
|
Receivables
(less allowance for uncollectible accounts of $17 at Sept. 30, 2008, $14
at Dec. 31, 2007 and $15 at Sept. 30, 2007)
|
|
|
189
|
|
|
|
391
|
|
|
|
143
|
|
Energy
marketing and risk management assets
|
|
|
172
|
|
|
|
69
|
|
|
|
90
|
|
Unrecovered
PRP costs – current portion
|
|
|
40
|
|
|
|
31
|
|
|
|
27
|
|
Unrecovered
ERC – current portion
|
|
|
20
|
|
|
|
23
|
|
|
|
24
|
|
Other
current assets
|
|
|
162
|
|
|
|
115
|
|
|
|
100
|
|
Total
current assets
|
|
|
1,940
|
|
|
|
1,797
|
|
|
|
1,415
|
|
Property,
plant and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
5,377
|
|
|
|
5,177
|
|
|
|
5,142
|
|
Less
accumulated depreciation
|
|
|
1,651
|
|
|
|
1,611
|
|
|
|
1,610
|
|
Property,
plant and equipment-net
|
|
|
3,726
|
|
|
|
3,566
|
|
|
|
3,532
|
|
Deferred
debits and other assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
418
|
|
|
|
420
|
|
|
|
420
|
|
Unrecovered
PRP costs
|
|
|
202
|
|
|
|
254
|
|
|
|
261
|
|
Unrecovered
ERC
|
|
|
124
|
|
|
|
135
|
|
|
|
132
|
|
Other
|
|
|
94
|
|
|
|
86
|
|
|
|
71
|
|
Total
deferred debits and other assets
|
|
|
838
|
|
|
|
895
|
|
|
|
884
|
|
Total
assets
|
|
$
|
6,504
|
|
|
$
|
6,258
|
|
|
$
|
5,831
|
|
Current
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt
|
|
$
|
769
|
|
|
$
|
580
|
|
|
$
|
576
|
|
Energy
marketing trade payables
|
|
|
568
|
|
|
|
578
|
|
|
|
383
|
|
Accounts
payable - trade
|
|
|
181
|
|
|
|
172
|
|
|
|
131
|
|
Accrued
expenses
|
|
|
83
|
|
|
|
87
|
|
|
|
82
|
|
Accrued
PRP costs – current portion
|
|
|
43
|
|
|
|
55
|
|
|
|
47
|
|
Customer
deposits
|
|
|
39
|
|
|
|
35
|
|
|
|
39
|
|
Energy
marketing and risk management liabilities – current
portion
|
|
|
34
|
|
|
|
16
|
|
|
|
9
|
|
Deferred
purchased gas adjustment
|
|
|
14
|
|
|
|
28
|
|
|
|
15
|
|
Accrued
environmental remediation liabilities – current portion
|
|
|
16
|
|
|
|
10
|
|
|
|
11
|
|
Other
current liabilities
|
|
|
75
|
|
|
|
73
|
|
|
|
73
|
|
Total
current liabilities
|
|
|
1,822
|
|
|
|
1,634
|
|
|
|
1,366
|
|
Accumulated
deferred income taxes
|
|
|
625
|
|
|
|
566
|
|
|
|
527
|
|
Long-term
liabilities and other deferred credits (excluding long-term
debt)
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
removal costs
|
|
|
176
|
|
|
|
169
|
|
|
|
168
|
|
Accrued
PRP costs
|
|
|
152
|
|
|
|
190
|
|
|
|
204
|
|
Accrued
environmental remediation liabilities
|
|
|
89
|
|
|
|
97
|
|
|
|
88
|
|
Accrued
pension obligations
|
|
|
43
|
|
|
|
43
|
|
|
|
83
|
|
Accrued
postretirement benefit costs
|
|
|
19
|
|
|
|
24
|
|
|
|
25
|
|
Other
long-term liabilities and other deferred credits
|
|
|
150
|
|
|
|
152
|
|
|
|
158
|
|
Total
long-term liabilities and other deferred credits (excluding long-term
debt)
|
|
|
629
|
|
|
|
675
|
|
|
|
726
|
|
Commitments
and contingencies (Note 6)
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority
interest
|
|
|
29
|
|
|
|
47
|
|
|
|
41
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,675
|
|
|
|
1,675
|
|
|
|
1,548
|
|
Common
shareholders’ equity, $5 par value; 750,000,000 shares
authorized
|
|
|
1,724
|
|
|
|
1,661
|
|
|
|
1,623
|
|
Total
capitalization
|
|
|
3,399
|
|
|
|
3,336
|
|
|
|
3,171
|
|
Total
liabilities and capitalization
|
|
$
|
6,504
|
|
|
$
|
6,258
|
|
|
$
|
5,831
|
|
See
Notes to Condensed Consolidated Financial Statements
(Unaudited).
|
|
|
|
|
|
AGL
RESOURCES INC. AND
SUBSIDIARIES
(UNAUDITED)
|
|
|
Three
months ended
|
|
|
Nine
months ended
|
|
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
In
millions, except per share amounts
|
|
|
2008
|
|
|
|
2007
|
|
|
2008
|
|
|
|
2007
|
|
|
Operating
revenues
|
|
$
|
539
|
|
|
$
|
369
|
|
|
$
|
1,995
|
|
|
$
|
1,809
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
261
|
|
|
|
159
|
|
|
|
1,193
|
|
|
|
987
|
|
Operation
and maintenance
|
|
|
104
|
|
|
|
107
|
|
|
|
337
|
|
|
|
334
|
|
Depreciation
and amortization
|
|
|
38
|
|
|
|
37
|
|
|
|
112
|
|
|
|
108
|
|
Taxes
other than income taxes
|
|
|
10
|
|
|
|
11
|
|
|
|
33
|
|
|
|
31
|
|
Total
operating expenses
|
|
|
413
|
|
|
|
314
|
|
|
|
1,675
|
|
|
|
1,460
|
|
Operating
income
|
|
|
126
|
|
|
|
55
|
|
|
|
320
|
|
|
|
349
|
|
Other
income
|
|
|
2
|
|
|
|
-
|
|
|
|
6
|
|
|
|
1
|
|
Minority
interest
|
|
|
5
|
|
|
|
-
|
|
|
|
(12
|
)
|
|
|
(24
|
)
|
Interest
expense, net
|
|
|
(29
|
)
|
|
|
(34
|
)
|
|
|
(85
|
)
|
|
|
(92
|
)
|
Earnings
before income taxes
|
|
|
104
|
|
|
|
21
|
|
|
|
229
|
|
|
|
234
|
|
Income
tax expense
|
|
|
39
|
|
|
|
8
|
|
|
|
86
|
|
|
|
89
|
|
Net
income
|
|
$
|
65
|
|
|
$
|
13
|
|
|
$
|
143
|
|
|
$
|
145
|
|
Per
common share data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$
|
0.85
|
|
|
$
|
0.17
|
|
|
$
|
1.87
|
|
|
$
|
1.88
|
|
Diluted
earnings per common share
|
|
$
|
0.85
|
|
|
$
|
0.17
|
|
|
$
|
1.87
|
|
|
$
|
1.87
|
|
Cash
dividends declared per common share
|
|
$
|
0.42
|
|
|
$
|
0.41
|
|
|
$
|
1.26
|
|
|
$
|
1.23
|
|
Weighted-average
number of common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
76.4
|
|
|
|
77.0
|
|
|
|
76.2
|
|
|
|
77.4
|
|
Diluted
|
|
|
76.6
|
|
|
|
77.4
|
|
|
|
76.5
|
|
|
|
77.8
|
|
See notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Shares
held
|
|
|
|
|
|
|
Common
stock
|
|
|
Premium
on
|
|
|
Earnings
|
|
|
comprehensive
|
|
|
in
treasury
|
|
|
|
|
In
millions, except per share amount
|
|
Shares
|
|
|
Amount
|
|
|
common
stock
|
|
|
reinvested
|
|
|
loss
|
|
|
and
trust
|
|
|
Total
|
|
Balance
as of December 31, 2007
|
|
|
76.4
|
|
|
$
|
390
|
|
|
$
|
667
|
|
|
$
|
680
|
|
|
$
|
(13
|
)
|
|
$
|
(63
|
)
|
|
$
|
1,661
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
143
|
|
|
|
-
|
|
|
|
-
|
|
|
|
143
|
|
Net
realized gains from hedging activities (net of tax of $-)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
(1
|
)
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142
|
|
Dividends
on common stock ($1.26 per share)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(96
|
)
|
|
|
-
|
|
|
|
3
|
|
|
|
(93
|
)
|
Issuance
of treasury shares
|
|
|
0.4
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
-
|
|
|
|
12
|
|
|
|
7
|
|
Stock-based
compensation expense (net of tax of $1)
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
Balance
as of September 30, 2008
|
|
|
76.8
|
|
|
$
|
390
|
|
|
$
|
673
|
|
|
$
|
723
|
|
|
$
|
(14
|
)
|
|
$
|
(48
|
)
|
|
$
|
1,724
|
|
See Notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED
)
|
|
|
|
|
|
|
|
|
Nine
months ended
|
|
|
|
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
Net
income
|
|
$
|
143
|
|
|
$
|
145
|
|
Adjustments
to reconcile net income to net cash flow provided by operating
activities
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
112
|
|
|
|
108
|
|
Change
in energy marketing and risk management assets and
liabilities
|
|
|
(86
|
)
|
|
|
27
|
|
Minority
interest
|
|
|
12
|
|
|
|
24
|
|
Deferred
income taxes
|
|
|
66
|
|
|
|
8
|
|
Changes
in certain assets and liabilities
|
|
|
|
|
|
|
|
|
Gas,
unbilled and other receivables
|
|
|
202
|
|
|
|
232
|
|
Energy
marketing receivables and energy marketing trade payables,
net
|
|
|
53
|
|
|
|
15
|
|
Inventories
|
|
|
(260
|
)
|
|
|
(57
|
)
|
Gas
and trade payables
|
|
|
9
|
|
|
|
(82
|
)
|
Other
– net
|
|
|
(79
|
)
|
|
|
(34
|
)
|
Net
cash flow provided by operating activities
|
|
|
172
|
|
|
|
386
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
Property,
plant and equipment expenditures
|
|
|
(254
|
)
|
|
|
(193
|
)
|
Other
|
|
|
-
|
|
|
|
2
|
|
Net
cash flow used in investing activities
|
|
|
(254
|
)
|
|
|
(191
|
)
|
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
Net
payments and borrowings of short-term debt
|
|
|
189
|
|
|
|
49
|
|
Issuance
of variable rate gas facility revenue bonds
|
|
|
161
|
|
|
|
-
|
|
Payments
of long-term debt
|
|
|
(161
|
)
|
|
|
(86
|
)
|
Dividends
paid on common shares
|
|
|
(93
|
)
|
|
|
(92
|
)
|
Distribution
to minority interest
|
|
|
(30
|
)
|
|
|
(23
|
)
|
Issuance
of treasury shares
|
|
|
7
|
|
|
|
13
|
|
Purchase
of treasury shares
|
|
|
-
|
|
|
|
(57
|
)
|
Other
|
|
|
1
|
|
|
|
(2
|
)
|
Net
cash flow provided by (used in) financing activities
|
|
|
74
|
|
|
|
(198
|
)
|
Net
decrease in cash and cash equivalents
|
|
|
(8
|
)
|
|
|
(3
|
)
|
Cash
and cash equivalents at beginning of period
|
|
|
19
|
|
|
|
17
|
|
Cash
and cash equivalents at end of period
|
|
$
|
11
|
|
|
$
|
14
|
|
Cash
paid during the period for
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
88
|
|
|
$
|
92
|
|
Income
taxes
|
|
$
|
27
|
|
|
$
|
89
|
|
See Notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS
(UNAUDITED)
General
AGL
Resources Inc. is an energy services holding company that conducts substantially
all its operations through its subsidiaries. Unless the context requires
otherwise, references to “we,” “us,” “our,” or “the company” mean consolidated
AGL Resources Inc. and its subsidiaries (AGL Resources).
The
year-end condensed balance sheet data was derived from our audited financial
statements, but does not include all disclosures required by GAAP. We have
prepared the accompanying unaudited condensed consolidated financial statements
under the rules of the SEC. Under such rules and regulations, we have condensed
or omitted certain information and notes normally included in financial
statements prepared in conformity with GAAP. However, the condensed consolidated
financial statements reflect all adjustments of a normal recurring nature that
are, in the opinion of management, necessary for a fair presentation of our
financial results for the interim periods. For a glossary of key terms and
referenced accounting standards, see page 3. You should read these condensed
consolidated financial statements in conjunction with our consolidated financial
statements and related notes included in our Annual Report on Form 10-K for the
year ended December 31, 2007, filed with the SEC on February 7,
2008.
Due to
the seasonal nature of our business, our results of operations for the three and
nine months ended September 30, 2008 and 2007, and our financial condition as of
December 31, 2007, and September 30, 2008 and 2007, are not necessarily
indicative of the results of operations and financial condition to be expected
as of or for any other period.
Basis
of Presentation
Our
condensed consolidated financial statements include our accounts, the accounts
of our majority-owned and controlled subsidiaries and the accounts of variable
interest entities for which we are the primary beneficiary. This means that our
accounts are combined with our subsidiaries’ accounts. We have eliminated any
intercompany profits and transactions in consolidation; however, we have not
eliminated intercompany profits when such amounts are probable of recovery under
the affiliates’ rate regulation process. Certain amounts from prior periods have
been reclassified and revised to conform to the current period
presentation.
We
currently own a noncontrolling 70% financial interest in SouthStar and Piedmont
owns the remaining 30%. Our 70% interest is noncontrolling because all
significant management decisions require approval by both owners. We record the
earnings allocated to Piedmont as a minority interest in our condensed
consolidated statements of income and we record Piedmont’s portion of
SouthStar’s capital as a minority interest in our condensed consolidated balance
sheets.
We are
the primary beneficiary of SouthStar’s activities and have determined that
SouthStar is a variable interest entity as defined by FIN 46, which was revised
in December 2003, FIN 46R. We determined that SouthStar is a variable interest
entity because our equal voting rights with Piedmont are not proportional to our
contractual obligation to absorb 75% of any losses or residual returns from
SouthStar, except those losses and returns related to customers in Ohio and
Florida. Earnings related to SouthStar’s customers in Ohio and Florida are
allocated 70% to us and 30% to Piedmont. In addition, SouthStar obtains
substantially all its transportation capacity for delivery of natural gas
through our wholly owned subsidiary, Atlanta Gas Light.
Use
of Accounting Estimates
The
preparation of our financial statements in conformity with GAAP requires us to
make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses and the related disclosures of contingent
assets and liabilities. We based our estimates on historical experience and
various other assumptions that we believe to be reasonable under the
circumstances, and we evaluate our estimates on an ongoing basis. Each of our
estimates involves complex situations requiring a high degree of judgment either
in the application and interpretation of existing literature or in the
development of estimates that impact our financial statements. The most
significant estimates include our PRP accruals, environmental liability
accruals, allowance for uncollectible accounts and other contingencies, pension
and postretirement obligations, derivative and hedging activities, unbilled
revenues and provision for income taxes. Our actual results could differ from
our estimates, and such differences could be material.
Inventories
For our
distribution operations segment, we record natural gas stored underground at
WACOG. For Sequent and SouthStar, we account for natural gas inventory at the
lower of WACOG or market price.
Sequent
and SouthStar evaluate the average cost of their natural gas inventories against
market prices to determine whether any declines in market prices below the WACOG
are other than temporary. For any declines considered to be other than
temporary, we record adjustments to reduce the weighted average cost of the
natural gas inventory to market price. SouthStar recorded LOCOM adjustments of
$18 million in the three and nine months ended September 30, 2008 and did not
record LOCOM adjustments in 2007. Sequent recorded LOCOM adjustments of $34
million in the three and nine months ended September 30, 2008 and $1 million and
$4 million for the three and nine months ended September 30, 2007,
respectively.
Stock-Based
Compensation
In the
first nine months of 2008, we issued grants of approximately 258,000 stock
options and 207,000 restricted stock units, which will result in the recognition
of approximately $2 million of stock-based compensation expense in 2008. No
material share awards have been granted to employees whose compensation is
subject to capitalization. We use the Black-Scholes pricing model to determine
the fair value of the options granted. On an annual basis, we evaluate the
assumptions and estimates used to calculate our stock-based compensation
expense.
There
have been no significant changes to our stock-based compensation, as described
in Note 4 to our Consolidated Financial Statements in Item 8 of our Annual
Report on Form 10-K for the year ended December 31, 2007.
Comprehensive
Income
Our
comprehensive income includes net income plus OCI, which includes other gains
and losses affecting shareholders’ equity that GAAP excludes from net income.
Such items consist primarily of gains and losses on certain derivatives
designated as cash flow hedges and unfunded or over funded pension and
postretirement obligations. The following table illustrates our OCI
activity.
|
|
Three
months ended September 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Cash
flow hedges:
|
|
|
|
|
|
|
Net derivative unrealized gains
(losses) arising during the period
(net of taxes of $- in 2008 and
$1 in 2007)
|
|
$
|
(1
|
)
|
|
$
|
2
|
|
Less
reclassification of realized losses included in income
(net of taxes of $- in 2008 and
$1 in 2007)
|
|
|
1
|
|
|
|
1
|
|
Total
|
|
$
|
-
|
|
|
$
|
3
|
|
|
|
Nine
months ended September 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Cash
flow hedges:
|
|
|
|
|
|
|
Net
derivative unrealized gains arising during the period
(net of taxes of $2 in 2008 and
$1 in 2007)
|
|
$
|
3
|
|
|
$
|
2
|
|
Less
reclassification of realized gains included in income
(net of taxes of $3 in 2008 and
$3 in 2007)
|
|
|
(4
|
)
|
|
|
(5
|
)
|
Pension
adjustments (
net of taxes
of $- in 2007)
|
|
|
-
|
|
|
|
1
|
|
Total
|
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
Earnings
per Common Share
We
compute basic earnings per common share by dividing our income available to
common shareholders by the weighted-average number of common shares outstanding
daily. Diluted earnings per common share reflect the potential reduction in
earnings per common share that could occur when potentially dilutive common
shares are added to common shares outstanding.
We derive
our potentially dilutive common shares by calculating the number of shares
issuable under restricted stock, restricted stock units and stock options. The
future issuance of shares underlying the restricted stock and restricted share
units depends on the satisfaction of certain performance criteria. The future
issuance of shares underlying the outstanding stock options depends upon whether
the exercise prices of the stock options are less than the average market price
of the common shares for the respective periods. The following table shows the
calculation of our diluted shares, assuming restricted stock and restricted
stock units currently awarded under the plan ultimately vest and stock options
currently exercisable at prices below the average market prices are
exercised.
|
|
Three
months ended September 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Denominator for basic earnings
per share
(1)
|
|
|
76.4
|
|
|
|
77.0
|
|
Assumed
exercise of restricted stock, restricted stock units and stock
options
|
|
|
0.2
|
|
|
|
0.4
|
|
Denominator
for diluted earnings per share
|
|
|
76.6
|
|
|
|
77.4
|
|
(1)
Daily weighted-average shares outstanding.
|
|
|
|
Nine
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Denominator for basic earnings
per share
(1)
|
|
|
76.2
|
|
|
|
77.4
|
|
Assumed
exercise of restricted stock, restricted stock units and stock
options
|
|
|
0.3
|
|
|
|
0.4
|
|
Denominator
for diluted earnings per share
|
|
|
76.5
|
|
|
|
77.8
|
|
(1)
Daily weighted-average shares outstanding.
|
|
The
following table contains the weighted average shares attributable to outstanding
stock options that were excluded from the computation of diluted earnings per
share because their effect would have been anti-dilutive, as the exercise prices
were greater than the average market price:
|
|
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
(1)
|
|
Three
months ended
|
|
|
2.1
|
|
|
|
0.1
|
|
Nine
months ended
|
|
|
1.6
|
|
|
|
0.0
|
|
(1)
|
0.0
values represent amounts less than 0.1
million.
|
The
increase in the number of shares that were excluded from the computation is the
result of a significant decline
in the
market value of our common shares at September 30, 2008 as compared to September
30, 2007.
Income
Taxes
We
adopted FIN 48 on January 1, 2007, and as of September 30, 2008, December 31,
2007 or September 30, 2007, we did not have a liability for unrecognized tax
benefits.
We do not
collect income taxes from our customers on behalf of governmental
authorities. We do collect and remit state and local taxes and record these
amounts within our condensed consolidated balance sheets. Therefore, EITF No.
06-3 does not apply to us.
There
have been no significant changes to our income taxes as described in Note 8 to
our Consolidated Financial Statements in Item 8 of our Annual Report on Form
10-K for the year ended December 31, 2007.
Regulatory Assets and
Liabilities
We have
recorded regulatory assets and liabilities in our condensed consolidated balance
sheets in accordance with SFAS 71. Our regulatory assets and liabilities, and
associated liabilities for our unrecovered PRP costs, unrecovered ERC and the
associated assets and liabilities for our Elizabethtown Gas hedging program, are
summarized in the following table.
|
|
Sept.
30
|
|
|
Dec.
31
|
|
|
Sept.
30
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
Regulatory
assets
|
|
|
|
|
|
|
|
|
|
Unrecovered
PRP costs
|
|
$
|
242
|
|
|
$
|
285
|
|
|
$
|
288
|
|
Unrecovered
ERC
|
|
|
144
|
|
|
|
158
|
|
|
|
156
|
|
Unrecovered
postretirement benefit costs
|
|
|
11
|
|
|
|
12
|
|
|
|
12
|
|
Unrecovered
seasonal rates
|
|
|
10
|
|
|
|
11
|
|
|
|
10
|
|
Unrecovered
PGA
|
|
|
33
|
|
|
|
23
|
|
|
|
15
|
|
Other
|
|
|
31
|
|
|
|
24
|
|
|
|
24
|
|
Total
regulatory assets
|
|
|
471
|
|
|
|
513
|
|
|
|
505
|
|
Associated
assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Elizabethtown
Gas hedging program
|
|
|
15
|
|
|
|
4
|
|
|
|
9
|
|
Total
regulatory and associated assets
|
|
$
|
486
|
|
|
$
|
517
|
|
|
$
|
514
|
|
Regulatory
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
removal costs
|
|
$
|
176
|
|
|
$
|
169
|
|
|
$
|
168
|
|
Elizabethtown
Gas hedging program
|
|
|
15
|
|
|
|
4
|
|
|
|
9
|
|
Unamortized
investment tax credit
|
|
|
15
|
|
|
|
16
|
|
|
|
16
|
|
Deferred
PGA
|
|
|
14
|
|
|
|
28
|
|
|
|
15
|
|
Regulatory
tax liability
|
|
|
19
|
|
|
|
20
|
|
|
|
21
|
|
Other
|
|
|
21
|
|
|
|
19
|
|
|
|
18
|
|
Total regulatory
liabilities
|
|
|
260
|
|
|
|
256
|
|
|
|
247
|
|
Associated
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
PRP
costs
|
|
|
195
|
|
|
|
245
|
|
|
|
251
|
|
ERC
|
|
|
95
|
|
|
|
96
|
|
|
|
90
|
|
Total
associated liabilities
|
|
|
290
|
|
|
|
341
|
|
|
|
341
|
|
Total
regulatory and associated liabilities
|
|
$
|
550
|
|
|
$
|
597
|
|
|
$
|
588
|
|
There
have been no significant changes to our regulatory assets and liabilities as
described in Note 1 to our Consolidated Financial Statements in Item 8 of our
Annual Report on Form 10-K for the year ended December 31, 2007.
Accounting
Developments
Previously
discussed
SFAS 160
In December 2007, the FASB issued SFAS 160, which is effective for fiscal years
beginning after December 15, 2008. SFAS 160 will require us to present our
minority interest, to be referred to as a noncontrolling interest, separately
within the capitalization section of our consolidated balance sheets. We will
adopt SFAS 160 on January 1, 2009.
SFAS 161
In March 2008, the FASB issued SFAS 161, which is effective for fiscal years
beginning after November 15, 2008. SFAS 161 amends the disclosure requirements
of SFAS 133 to provide an enhanced understanding of how and why derivative
instruments are used, how they are accounted for and their effect on an entity’s
financial condition, performance and cash flows. We will adopt SFAS 161 on
January 1, 2009 which will require additional disclosures, but will not have a
financial impact to our consolidated results of operations, cash flows or
financial condition.
FSP EITF
03-6-1
The FASB issued this FSP in June 2008 and it is effective for
fiscal years beginning after December 15, 2008. This FSP classifies unvested
share-based payment grants containing nonforfeitable rights to dividends as
participating securities that will be included in the computation of earnings
per share. As of September 30, 2008, we had approximately 149,000 restricted
shares with nonforfeitable dividend rights. We will adopt FSP EITF 03-6-1 on
January 1, 2009.
Recently
issued
FSP FAS
133-1
The FASB issued this FSP in September 2008 and it is effective for
fiscal years beginning after November 15, 2008. This FSP requires more detailed
disclosures about credit derivatives, including the potential adverse effects of
changes in credit risk on the financial position, financial performance and cash
flows of the sellers of the instruments. This FSP will have no financial impact
to our consolidated results of operations, cash flows or financial condition. We
will adopt FSP FAS 133-1 on January 1, 2009.
FSP FAS
157-3
The FASB issued this FSP in October 2008 and it is effective upon
issuance including prior periods for which financial statements have not been
issued. This FSP clarifies the application of SFAS 157 in an inactive market,
including; how internal assumptions should be considered when measuring fair
value, how observable market information in a market that is not active should
be considered and how the use of market quotes should be used when assessing
observable and unobservable data. We adopted this FSP as of September 30, 2008,
which had no financial impact to our consolidated results of operations, cash
flows or financial condition.
Netting
of Cash Collateral and Derivative Assets and Liabilities under Master Netting
Arrangements
We
maintain accounts with brokers to facilitate financial derivative transactions
in support of our energy marketing and risk management activities. Based on the
value of our positions in these accounts and the associated margin requirements,
we may be required to deposit cash into these broker accounts.
On
January 1, 2008, we adopted FIN 39-1, which required that we offset cash
collateral held in these broker accounts on our condensed consolidated balance
sheets with the associated fair value of the instruments in the accounts. Prior
to the adoption of FIN 39-1, we presented such cash collateral on a gross basis
within other current assets and liabilities on our condensed consolidated
balance sheets. Our cash collateral amounts are provided in the following
table.
|
|
|
|
|
As
of
|
|
|
|
|
In
millions
|
|
Sept.
30, 2008
|
|
|
Dec.
31, 2007
|
|
|
Sept.
30, 2007
|
|
Right
to reclaim cash collateral
|
|
$
|
53
|
|
|
$
|
3
|
|
|
$
|
18
|
|
Obligations
to return cash collateral
|
|
|
(1
|
)
|
|
|
(10
|
)
|
|
|
-
|
|
Total
cash collateral
|
|
$
|
52
|
|
|
$
|
(7
|
)
|
|
$
|
18
|
|
Fair
value measurements
In
September 2006, the FASB issued SFAS 157, which establishes a framework for
measuring fair value and requires expanded disclosures regarding fair value
measurements. SFAS 157 does not require any new fair value measurements;
however, it eliminates inconsistencies in the guidance provided in previous
accounting pronouncements. The carrying value of cash and cash equivalents,
receivables, accounts payable, other current liabilities, derivative assets,
derivative liabilities and accrued interest approximate fair value. The
following table shows the carrying amounts and fair values of our long-term debt
including any current portions included in our condensed consolidated balance
sheets.
In
millions
|
|
Carrying
amount
|
|
|
Estimated
fair value
|
|
As
of September 30, 2008
|
|
$
|
1,675
|
|
|
$
|
1,671
|
|
As
of December 31, 2007
|
|
|
1,675
|
|
|
|
1,710
|
|
As
of September 30, 2007
|
|
|
1,548
|
|
|
|
1,556
|
|
SFAS 157
was effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal years. In December
2007, the FASB provided a one-year deferral of SFAS 157 for nonfinancial assets
and nonfinancial liabilities, except those that are recognized or disclosed at
fair value on a recurring basis, at least annually. We adopted SFAS 157 on
January 1, 2008, for our financial assets and liabilities, which primarily
consist of derivatives we record in accordance with SFAS 133. The adoption of
SFAS 157 primarily impacts our disclosures and did not have a material impact on
our condensed consolidated results of operations, cash flows and financial
condition. We will adopt SFAS 157 for our nonfinancial assets and liabilities on
January 1, 2009, and are currently evaluating the impact to our condensed
consolidated results of operations, cash flows and financial
condition.
Level
1
Quoted
prices are available in active markets for identical assets or liabilities as of
the reporting date. Active markets are those in which transactions for the
asset or liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. Our Level 1 items consist of financial
instruments with exchange-traded derivatives.
Level 2
Pricing
inputs are other than quoted prices in active markets included in level 1, which
are either directly or indirectly observable as of the reporting date. Level 2
includes those financial and commodity instruments that are valued using
valuation methodologies. These methodologies are primarily industry-standard
methodologies that consider various assumptions, including quoted forward prices
for commodities, time value, volatility factors, and current market and
contractual prices for the underlying instruments, as well as other relevant
economic measures. Substantially all of these assumptions are observable in the
marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace. We obtain market price data from multiple sources
in order to value some of our Level 2 transactions and this data is
representative of transactions that occurred in the market place. As we
aggregate our disclosures by counterparty, the underlying transactions for a
given counterparty may be a combination of exchange-traded derivatives and
values based on other sources. Instruments in this category include shorter
tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards
and options.
Level 3
Pricing
inputs include significant inputs that are generally less observable from
objective sources. These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair value. Level 3
instruments include those that may be more structured or otherwise tailored to
customers’ needs. We do not have any material assets or liabilities classified
as level 3.
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, 2008. As required by SFAS 157, 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 measurement requires
judgment, and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels.
|
|
Recurring
fair value measurements as of September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
millions
|
|
Quoted
prices in active markets (Level 1)
|
|
|
Significant
other observable inputs
(Level
2)
|
|
|
Significant
unobservable inputs
(Level
3)
|
|
|
Netting
of cash collateral
|
|
|
Total
carrying value
|
|
Assets:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
at wholesale services
|
|
$
|
27
|
|
|
$
|
87
|
|
|
$
|
-
|
|
|
$
|
26
|
|
|
$
|
140
|
|
Derivatives
at distribution operations
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
-
|
|
|
|
15
|
|
Derivatives
at retail energy operations
(3)
|
|
|
32
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
32
|
|
Total
assets
|
|
$
|
59
|
|
|
$
|
102
|
|
|
$
|
-
|
|
|
$
|
26
|
|
|
$
|
187
|
|
Liabilities:
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
at wholesale services
|
|
$
|
11
|
|
|
$
|
20
|
|
|
$
|
-
|
|
|
$
|
(7
|
)
|
|
$
|
24
|
|
Derivatives
at distribution operations
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
1
|
|
|
|
16
|
|
Derivatives
at retail energy operations
|
|
|
20
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(20
|
)
|
|
|
1
|
|
Total
liabilities
|
|
$
|
31
|
|
|
$
|
36
|
|
|
$
|
-
|
|
|
$
|
(26
|
)
|
|
$
|
41
|
|
(1)
Includes
$172 million of current assets and $16 million of long-term assets reflected
within our condensed consolidated balance sheet.
(2)
Includes
$34 million of current liabilities and $7 million of long-term liabilities
reflected within our condensed consolidated balance sheet.
(3)
$1
million premium associated with weather derivatives has been excluded as they
are based on intrinsic value, not fair value.
The
determination of the fair values above incorporates various factors required
under SFAS 157. These factors include not only the credit standing of the
counterparties involved and the impact of credit enhancements (such as cash
deposits, letters of credit and priority interests), but also the impact of our
nonperformance risk on our liabilities.
Derivatives
at distribution operations relate to Elizabethtown Gas and are utilized in
accordance with a directive from the New Jersey Commission to create a program
to hedge the impact of market fluctuations in natural gas prices. These
derivative products are accounted for at fair value each reporting period. In
accordance with regulatory requirements, realized gains and losses related to
these derivatives are reflected in purchased gas costs and ultimately included
in billings to customers. Unrealized gains and losses are reflected as a
regulatory asset or liability, as appropriate, in our condensed consolidated
balance sheets.
Sequent’s
and SouthStar’s derivatives include exchange-traded and OTC derivative
contracts. Exchange-traded derivative contracts, which include futures and
exchange-traded options, are generally based on unadjusted quoted prices in
active markets and are classified within level 1. Some exchange-traded
derivatives are valued using broker or dealer quotation services, or market
transactions in either the listed or OTC markets, which are classified within
level 2.
At the
beginning of 2008, we had a notional principal amount of $100 million of
interest rate swap agreements associated with our senior notes. In March 2008,
we terminated these interest rate swap agreements. We received a payment of $2
million, which included accrued interest and the fair value of the interest rate
swap agreements at the termination date. The payment was recorded as deferred
income and classified as a liability in our condensed consolidated balance
sheets. The amount will be amortized through January 2011, the remaining life of
the associated senior notes. The following table sets forth a reconciliation of
the termination of our interest rate swaps, classified as level 3 in the fair
value hierarchy.
In
millions
|
|
Nine
months ended September 30, 2008
|
|
Balance
as of January 1, 2008
|
|
$
|
(2
|
)
|
Realized
and unrealized gains
|
|
|
-
|
|
Settlements
|
|
|
2
|
|
Transfers
in or out of level 3
|
|
|
-
|
|
Balance
as of September 30, 2008
|
|
$
|
-
|
|
Change
in unrealized gains (losses) relating to instruments held as of September
30, 2008
|
|
$
|
-
|
|
Transfers
in or out of level 3 represent existing assets or liabilities that were either
previously categorized as a higher level for which the methodology inputs became
unobservable or assets and liabilities that were previously classified as level
3 for which the lowest significant input became observable during the
period.
Risk
Management
Our risk
management activities are monitored by our Risk Management Committee (RMC) which
consists of members of senior management and our Finance and Risk Management
Committee (FRMC) which consists of members from our Board of Directors. Both the
RMC and FRMC are charged with reviewing and enforcing our risk management
activities. Our risk management policies limit the use of derivative financial
instruments and physical transactions within predefined risk tolerances
associated with pre-existing or anticipated physical natural gas sales and
purchases and system use and storage. We use the following derivative financial
instruments and physical transactions to manage commodity price, interest rate,
weather and foreign currency risks:
·
|
weather
derivative contracts
|
·
|
storage
and transportation capacity
transactions
|
·
|
foreign
currency forward contracts
|
Pension
Benefits
We
sponsor two tax-qualified defined benefit retirement plans for our eligible
employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement
Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits
an eligible participant eventually will receive using information about the
participant. The following are the combined cost components of our two defined
benefit pension plans for the periods indicated:
|
|
Three
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Service
cost
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest
cost
|
|
|
7
|
|
|
|
6
|
|
Expected
return on plan assets
|
|
|
(9
|
)
|
|
|
(8
|
)
|
Amortization
of prior service cost
|
|
|
-
|
|
|
|
(1
|
)
|
Recognized
actuarial loss
|
|
|
-
|
|
|
|
2
|
|
Net
pension cost
|
|
$
|
-
|
|
|
$
|
1
|
|
|
|
Nine
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Service
cost
|
|
$
|
6
|
|
|
$
|
6
|
|
Interest
cost
|
|
|
20
|
|
|
|
18
|
|
Expected
return on plan assets
|
|
|
(25
|
)
|
|
|
(24
|
)
|
Amortization
of prior service cost
|
|
|
(1
|
)
|
|
|
(2
|
)
|
Recognized
actuarial loss
|
|
|
2
|
|
|
|
5
|
|
Net
pension cost
|
|
$
|
2
|
|
|
$
|
3
|
|
Our
employees do not contribute to the retirement plans. We fund the plans by
contributing at least the minimum amount required by applicable regulations and
as recommended by our actuary. However, we may also contribute in excess of the
minimum required amount. We calculate the minimum amount of funding using the
projected unit credit cost method. The Pension Protection Act (the Act) of 2006
contains new funding requirements for single employer defined benefit pension
plans. The Act establishes a 100% funding target for plan years beginning after
December 31, 2007. However, a delayed effective date of 2011 may apply if the
pension plan meets the following targets: 92% funded in 2008; 94% funded in
2009; and 96% funded in 2010. No contribution is required for our qualified
plans in 2008.
Postretirement Benefits
The
AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan)
covers all eligible AGL Resources employees who were employed as of September
30, 2002, if they reach retirement age while working for us. The state
regulatory commissions have approved phase-ins that defer a portion of other
postretirement benefits expense for future recovery. Effective December 8, 2003,
the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was
signed into law. This act provides for a prescription drug benefit under
Medicare (Part D), as well as a federal subsidy to sponsors of retiree health
care benefit plans that provide a benefit that is at least actuarially
equivalent to Medicare Part D.
Eligibility
for benefits under the AGL Postretirement Plan is based on age and years of
service. Following are the cost components of the AGL Postretirement Plan for
the periods indicated.
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Service
cost
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1
|
|
|
$
|
-
|
|
Interest
cost
|
|
|
1
|
|
|
|
1
|
|
|
|
4
|
|
|
|
4
|
|
Expected
return on plan assets
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
(3
|
)
|
Amortization
of prior service cost
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(3
|
)
|
|
|
(3
|
)
|
Recognized
actuarial loss
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
Net
postretirement benefit cost
|
|
$
|
(1
|
)
|
|
$
|
-
|
|
|
$
|
(2
|
)
|
|
$
|
(1
|
)
|
Employee
Savings Plan Benefits
We
sponsor the Retirement Savings Plus Plan (RSP Plan), a defined contribution
benefit plan that allows eligible participants to make contributions to their
accounts up to specified limits. Under the RSP Plan, we made $5 million in
matching contributions to participant accounts in the first nine months of 2008
and $5 million in the same period last year.
Share
Repurchase Program
In March
2001, our Board of Directors approved the purchase of up to 600,000 shares of
our common stock to be used for issuances under the Officer Incentive Plan. In
the first nine months of 2008, we purchased 10,333 shares under this plan. As of
September 30, 2008, we had purchased a total 307,567 shares, leaving 292,433
shares available for purchase.
In
February 2006, our Board of Directors authorized a plan to purchase up to 8
million shares of our outstanding common stock over a five-year period. These
purchases are intended to offset share issuances under our employee and
non-employee director incentive compensation plans and our dividend reinvestment
and stock purchase plans. Stock purchases under this program may be made in the
open market or in private transactions at times and in amounts that we deem
appropriate. There is no guarantee as to the exact number of shares that we will
purchase, and we can terminate or limit the program at any time. We will hold
the purchased shares as treasury shares. We did not purchase shares under this
program during the first nine months of 2008. As of September 30, 2008, we had
repurchased 3,049,049 shares at a weighted average price of $38.58.
Our
issuance of various securities, including long-term and short-term debt, is
subject to customary approval or authorization by state and federal regulatory
bodies, including state public service commissions, the SEC and the FERC as
granted by the Energy Policy Act of 2005. The following table provides more
information on our various debt securities.
|
|
|
|
|
|
|
|
Weighted
|
|
|
Outstanding
as of
|
|
In
millions
|
|
Year(s)
due
(1)
|
|
|
Interest
rate
(1)
|
|
|
average
interest rate
(2)
|
|
|
Sept.
30,
2008
|
|
|
Dec.
31,
2007
|
|
|
Sept.30,
2007
|
|
Short-term
debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
Facility
|
|
2008
|
|
|
|
3.5
|
%
|
|
|
3.5
|
%
|
|
$
|
485
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Commercial
paper
|
|
2008
|
|
|
|
4.6
|
|
|
|
3.5
|
|
|
|
198
|
|
|
|
566
|
|
|
|
549
|
|
SouthStar
line of credit
|
|
2008
|
|
|
|
3.5
|
|
|
|
3.5
|
|
|
|
55
|
|
|
|
-
|
|
|
|
-
|
|
Sequent
lines of credit
|
|
2008
|
|
|
|
2.8
|
|
|
|
2.7
|
|
|
|
20
|
|
|
|
1
|
|
|
|
13
|
|
Pivotal
Utility line of credit
|
|
2008
|
|
|
|
1.6
|
|
|
|
2.9
|
|
|
|
10
|
|
|
|
12
|
|
|
|
13
|
|
Capital
leases
|
|
2008
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Total
short-term debt
|
|
|
|
|
|
3.7
|
%
|
|
|
3.4
|
%
|
|
$
|
769
|
|
|
$
|
580
|
|
|
$
|
576
|
|
Long-term
debt - net of current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
notes
|
|
|
2011-2034
|
|
|
|
4.5-7.1
|
%
|
|
|
5.9
|
%
|
|
$
|
1,275
|
|
|
$
|
1,275
|
|
|
$
|
1,150
|
|
Gas
facility revenue bonds
|
|
|
2022-2033
|
|
|
|
4.2-8.1
|
|
|
|
3.5
|
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
Medium-term
notes
|
|
|
2012-2027
|
|
|
|
6.6-9.1
|
|
|
|
7.8
|
|
|
|
196
|
|
|
|
196
|
|
|
|
196
|
|
Capital
leases
|
|
2013
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
4
|
|
|
|
6
|
|
|
|
5
|
|
Interest
rate swaps
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(3
|
)
|
Total
long-term debt
|
|
|
|
|
|
|
6.0
|
%
|
|
|
5.8
|
%
|
|
$
|
1,675
|
|
|
$
|
1,675
|
|
|
$
|
1,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
debt
|
|
|
|
|
|
|
5.3
|
%
|
|
|
5.4
|
%
|
|
$
|
2,444
|
|
|
$
|
2,255
|
|
|
$
|
2,124
|
|
(1)
|
As
of September 30, 2008
|
(2)
|
For
the nine months ended September 30,
2008
|
Credit
Facility
In
September 2008, we completed a $140 million Credit Facility that expires in
September 2009, which will provide additional liquidity for working capital and
capital expenditure needs. This Credit Facility provides us the option to
request an increase in the borrowing capacity to $150 million and supplements
our existing $1.0 billion Credit Facility which expires in August
2011.
Gas
Facility Revenue Bonds
In 2008,
a portion of our gas facility revenue bonds failed to draw enough potential
buyers due to the dislocation or disruption in the auction markets as a result
of the downgrades to the bond insurers that provide credit protections for these
instruments which reduced investor demand and liquidity for these types of
investments. In March and April 2008, we tendered these bonds with a cumulative
principal amount of $161 million through commercial paper
borrowings.
In June
and September 2008, we completed a Letter of Credit Agreement for these bonds
which provided additional credit support which increased investor demand for the
bonds. As a result, these bonds with a cumulative principal amount of $161
million were successfully auctioned and issued as variable rate gas facility
bonds and reduced our commercial paper borrowings. The bonds with principal
amounts of $55 million, $47 million and $39 million now have interest rates that
reset daily and the bond with a principal amount of $20 million has an interest
rate that resets weekly. There was no change to the maturity dates on these
bonds.
SouthStar
Credit Facility
SouthStar’s
five-year $75 million unsecured credit facility expires in November 2011.
SouthStar will use this line of credit for working capital and its general
corporate needs. We do not guarantee or provide any other form of security for
the repayment of this credit facility.
Sequent
Lines of Credit
In June
2008, we extended one of Sequent’s lines of credit in the amount of $25 million
to June 2009. This line of credit bears interest at the federal funds
effective rate plus 0.75%. In September 2008, Sequent obtained a second line of
credit for $20 million that bears interest at the LIBOR Rate plus 1.0% to
September 2009. This line of credit replaced the line of credit that expired in
August 2008. Both lines of credit are used for the posting of margin deposits
for NYMEX transactions and are unconditionally guaranteed by
us.
Contractual Obligations and
Commitments
We have incurred various contractual obligations and
financial commitments in the normal course of our operating and financing
activities. Contractual obligations include future cash payments required under
existing contractual arrangements, such as debt and lease agreements. These
obligations may result from both general financing activities and from
commercial arrangements that are directly supported by related revenue-producing
activities. There were no significant changes to our contractual obligations
described in Note 7 to our Consolidated Financial Statements in Item 8 of our
Annual Report on Form 10-K for the year ended December 31, 2007.
Contingent
financial commitments, such as financial guarantees, represent obligations that
become payable only if certain predefined events occur and include the nature of
the guarantee and the maximum potential amount of future payments that could be
required of us as the guarantor. The following table illustrates our contingent
financial commitments as of September 30, 2008.
|
|
Commitments
due before
Dec.
31,
|
|
In
millions
|
|
Total
|
|
|
2008
|
|
|
2009
& thereafter
|
|
Standby
letters of credit and performance and surety bonds
|
|
$
|
48
|
|
|
$
|
8
|
|
|
$
|
40
|
|
Litigation
We are
involved in litigation arising in the normal course of business. The ultimate
resolution of such litigation will not have a material adverse effect on our
consolidated financial condition, results of operations or cash
flows.
In March
2008, Jefferson Island served discovery requests on the State of Louisiana and
sought a trial date in its pending lawsuit over its natural gas storage
expansion project at Lake Peigneur. Jefferson Island also asserted additional
claims against the State seeking to obtain a declaratory ruling that Jefferson
Island’s surface lease, under which it operates its existing two storage
caverns, authorizes the creation of the two new expansion caverns separate and
apart from the mineral lease challenged by the State. Jefferson Island
originally filed the suit against the State in the 19
th
Judicial District Court in Baton Rouge in September 2006.
In
addition, in June 2008, the State of Louisiana passed legislation restricting
water usage from the Chicot aquifer, which is a main source of fresh water
required for the expansion of our Jefferson Island capacity. We contend that
this legislation is unconstitutional and have sought to amend the pending
litigation to seek a declaration that the legislation is invalid and cannot be
enforced. Even if we are not successful on those grounds, we believe the
legislation does not materially impact the feasibility of the expansion
project.
Additional
information in the Jefferson Island Storage & Hub, LLC vs. State of
Louisiana litigation is described in Note 7 to our Consolidated Financial
Statements in Item 8 of our Annual Report on Form 10-K for the year ended
December 31, 2007. The ultimate resolution of such litigation cannot be
determined, but it is not expected to have a material adverse effect on our
consolidated financial condition, results of operations or cash
flows.
In
February 2008, the consumer affairs staff of the Georgia Commission alleged that
GNG charged its customers on variable rate plans prices for natural gas that
were in excess of the published price, that it failed to give proper notice
regarding the availability of potentially lower price plans and that it changed
its methodology for computing variable rates. GNG asserted that it fully
complied with all applicable rules and regulations, that it properly charged its
customers on variable rate plans the rates on file with the Georgia Commission,
and that, consistent with its terms and conditions of service, it routinely
switched customers who requested to move to another price plan for which they
qualified. In order to resolve this matter GNG agreed to pay $2.5 million in the
form of credits to customers, or as directed by the Georgia Commission, which
was recorded in our condensed consolidated statements of income for the nine
months ended September 30, 2008.
In
February 2008, a class action lawsuit was filed in the Superior Court of Fulton
County in the State of Georgia against GNG containing similar allegations to
those asserted by the Georgia Commission staff and seeking damages on behalf of
a class of GNG customers. This lawsuit was dismissed in September
2008.
In March
2008, a second class action suit was filed against GNG in the State Court of
Fulton County in the State of Georgia, regarding monthly service charges. This
lawsuit alleges that GNG arbitrarily assigned customer service charges rather
than basing each customer service charge on a specific credit score. GNG asserts
that no violation of law or Georgia Commission rules has occurred, that this
lawsuit is without merit and has filed motions to dismiss this class action suit
on various grounds. The ultimate resolution of this lawsuit cannot be
determined, but is not expected to have a material adverse effect on our
condensed consolidated results of operations, cash flows or financial
condition.
Review
of Compliance with FERC Regulations
We
recently conducted an internal review of our compliance with FERC interstate
natural gas pipeline capacity release rules and regulations. Independent of our
internal review, we also received data requests from FERC’s Office of
Enforcement relating specifically to compliance with FERC’s capacity release
posting and bidding requirements. We have responded to FERC’s data requests
and are fully cooperating with FERC in its investigation. As a result of this
process, we have identified certain instances of possible non-compliance. We are
committed to full regulatory compliance and we have met with the FERC
Enforcement staff to discuss with them these instances of possible
non-compliance. At this time we are unable to predict the outcome of the FERC
investigation.
We are an
energy services holding company whose principal business is the distribution of
natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee
and Virginia. We generate nearly all our operating revenues through the sale,
distribution, transportation and storage of natural gas. We are involved in
several related and complementary businesses, including retail natural gas
marketing to end-use customers primarily in Georgia; natural gas asset
management and related logistics activities for each of our utilities as well as
for nonaffiliated companies; natural gas storage arbitrage and related
activities; and the development and operation of high-deliverability natural gas
storage assets. We manage these businesses through four operating segments –
distribution operations, retail energy operations, wholesale services and energy
investments and a nonoperating corporate segment which includes intercompany
eliminations.
We
evaluate segment performance based primarily on the non-GAAP measure of EBIT,
which includes the effects of corporate expense allocations. EBIT is a non-GAAP
measure that includes operating income, other income and expenses and minority
interest. Items we do not include in EBIT are financing costs, including
interest and debt expense and income taxes, each of which we evaluate on a
consolidated level. We believe EBIT is a useful measurement of our performance
because it provides information that can be used to evaluate the effectiveness
of our businesses from an operational perspective, exclusive of the costs to
finance those activities and exclusive of income taxes, neither of which is
directly relevant to the efficiency of those operations.
You
should not consider EBIT an alternative to, or a more meaningful indicator of
our operating performance than, operating income or net income as determined in
accordance with GAAP. In addition, our EBIT may not be comparable to a similarly
titled measure of another company. The following table contains the
reconciliations of EBIT to operating income, earnings before income taxes and
net income for the three and nine months ended September 30, 2008 and
2007.
|
|
Three
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Operating
revenues
|
|
$
|
539
|
|
|
$
|
369
|
|
Operating
expenses
|
|
|
413
|
|
|
|
314
|
|
Operating
income
|
|
|
126
|
|
|
|
55
|
|
Minority
interest
|
|
|
5
|
|
|
|
-
|
|
Other
income
|
|
|
2
|
|
|
|
-
|
|
EBIT
|
|
|
133
|
|
|
|
55
|
|
Interest
expense, net
|
|
|
(29
|
)
|
|
|
(34
|
)
|
Earnings
before income taxes
|
|
|
104
|
|
|
|
21
|
|
Income
tax expense
|
|
|
39
|
|
|
|
8
|
|
Net
income
|
|
$
|
65
|
|
|
$
|
13
|
|
|
|
Nine
months ended
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Operating
revenues
|
|
$
|
1,995
|
|
|
$
|
1,809
|
|
Operating
expenses
|
|
|
1,675
|
|
|
|
1,460
|
|
Operating
income
|
|
|
320
|
|
|
|
349
|
|
Minority
interest
|
|
|
(12
|
)
|
|
|
(24
|
)
|
Other
income
|
|
|
6
|
|
|
|
1
|
|
EBIT
|
|
|
314
|
|
|
|
326
|
|
Interest
expense, net
|
|
|
(85
|
)
|
|
|
(92
|
)
|
Earnings
before income taxes
|
|
|
229
|
|
|
|
234
|
|
Income
taxes
|
|
|
86
|
|
|
|
89
|
|
Net
income
|
|
$
|
143
|
|
|
$
|
145
|
|
Balance
sheet information at December 31, 2007, is as follows:
In
millions
|
|
|
Identifiable
and total assets (1)
|
|
|
|
Goodwill
|
|
Distribution
operations
|
|
$
|
4,847
|
|
|
$
|
406
|
|
Retail
energy operations
|
|
|
282
|
|
|
|
-
|
|
Wholesale
services
|
|
|
890
|
|
|
|
-
|
|
Energy
investments
|
|
|
287
|
|
|
|
14
|
|
Corporate and intercompany
eliminations
(2)
|
|
|
(48
|
)
|
|
|
-
|
|
Consolidated
AGL Resources
|
|
$
|
6,258
|
|
|
$
|
420
|
|
(1)
|
Identifiable
assets are those assets used in each segment’s
operations.
|
(2)
|
Our
corporate segment’s assets consist primarily of cash and cash equivalents
and property, plant and equipment and reflect the effect of intercompany
eliminations.
|
Summarized
income statement information, identifiable and total assets, goodwill and
property, plant and equipment expenditures as of and for the three and nine
months ended September 30, 2008 and 2007, by segment are shown in the following
tables.
Three
months ended September 30, 2008
In
millions
|
|
Distribution
operations
|
|
|
Retail
energy
operations
|
|
|
Wholesale
services
|
|
|
Energy
investments
|
|
|
Corporate
and intercompany eliminations
(3)
|
|
|
Consolidated
AGL Resources
|
|
Operating
revenues from external parties
|
|
$
|
237
|
|
|
$
|
149
|
|
|
$
|
138
|
|
|
$
|
13
|
|
|
$
|
2
|
|
|
$
|
539
|
|
Intercompany
revenues
(1)
|
|
|
35
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(35
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
272
|
|
|
|
149
|
|
|
|
138
|
|
|
|
13
|
|
|
|
(33
|
)
|
|
|
539
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
101
|
|
|
|
154
|
|
|
|
37
|
|
|
|
3
|
|
|
|
(34
|
)
|
|
|
261
|
|
Operation
and maintenance
|
|
|
72
|
|
|
|
15
|
|
|
|
13
|
|
|
|
6
|
|
|
|
(2
|
)
|
|
|
104
|
|
Depreciation
and amortization
|
|
|
32
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
3
|
|
|
|
38
|
|
Taxes
other than income taxes
|
|
|
9
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
Total
operating expenses
|
|
|
214
|
|
|
|
170
|
|
|
|
52
|
|
|
|
10
|
|
|
|
(33
|
)
|
|
|
413
|
|
Operating
income (loss)
|
|
|
58
|
|
|
|
(21
|
)
|
|
|
86
|
|
|
|
3
|
|
|
|
-
|
|
|
|
126
|
|
Other
income
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
2
|
|
Minority
interest
|
|
|
-
|
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5
|
|
EBIT
|
|
$
|
59
|
|
|
$
|
(16
|
)
|
|
$
|
86
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
62
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
23
|
|
|
$
|
3
|
|
|
$
|
88
|
|
Three
months ended September 30, 2007
In
millions
|
|
Distribution
operations
|
|
|
Retail
energy
operations
|
|
|
Wholesale
services
|
|
|
Energy
investments
|
|
|
Corporate
and intercompany eliminations
(3)
|
|
|
Consolidated
AGL Resources
|
|
Operating
revenues from external parties
|
|
$
|
219
|
|
|
$
|
128
|
|
|
$
|
13
|
|
|
$
|
9
|
|
|
$
|
-
|
|
|
$
|
369
|
|
Intercompany
revenues
(1)
|
|
|
37
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(37
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
256
|
|
|
|
128
|
|
|
|
13
|
|
|
|
9
|
|
|
|
(37
|
)
|
|
|
369
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
83
|
|
|
|
112
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(37
|
)
|
|
|
159
|
|
Operation
and maintenance
|
|
|
79
|
|
|
|
16
|
|
|
|
10
|
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
107
|
|
Depreciation
and amortization
|
|
|
30
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
3
|
|
|
|
37
|
|
Taxes
other than income taxes
|
|
|
9
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
11
|
|
Total
operating expenses
|
|
|
201
|
|
|
|
130
|
|
|
|
12
|
|
|
|
6
|
|
|
|
(35
|
)
|
|
|
314
|
|
Operating
income (loss)
|
|
|
55
|
|
|
|
(2
|
)
|
|
|
1
|
|
|
|
3
|
|
|
|
(2
|
)
|
|
|
55
|
|
Other
income (expense)
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
Minority
interest
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
EBIT
|
|
$
|
55
|
|
|
$
|
(1
|
)
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
|
$
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
52
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
8
|
|
|
$
|
6
|
|
|
$
|
68
|
|
Nine
months ended September 30, 2008
In
millions
|
|
Distribution
operations
|
|
|
Retail
energy
operations
|
|
|
Wholesale
services
|
|
|
Energy
investments
|
|
|
Corporate
and intercompany eliminations
(3)
|
|
|
Consolidated
AGL Resources
|
|
Operating
revenues from external parties
|
|
$
|
1,146
|
|
|
$
|
701
|
|
|
$
|
104
|
|
|
$
|
43
|
|
|
$
|
1
|
|
|
$
|
1,995
|
|
Intercompany
revenues
(1)
|
|
|
147
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(147
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
1,293
|
|
|
|
701
|
|
|
|
104
|
|
|
|
43
|
|
|
|
(146
|
)
|
|
|
1,995
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
694
|
|
|
|
600
|
|
|
|
41
|
|
|
|
4
|
|
|
|
(146
|
)
|
|
|
1,193
|
|
Operation
and maintenance
|
|
|
241
|
|
|
|
50
|
|
|
|
35
|
|
|
|
16
|
|
|
|
(5
|
)
|
|
|
337
|
|
Depreciation
and amortization
|
|
|
94
|
|
|
|
3
|
|
|
|
4
|
|
|
|
4
|
|
|
|
7
|
|
|
|
112
|
|
Taxes
other than income taxes
|
|
|
27
|
|
|
|
1
|
|
|
|
2
|
|
|
|
1
|
|
|
|
2
|
|
|
|
33
|
|
Total
operating expenses
|
|
|
1,056
|
|
|
|
654
|
|
|
|
82
|
|
|
|
25
|
|
|
|
(142
|
)
|
|
|
1,675
|
|
Operating
income (loss)
|
|
|
237
|
|
|
|
47
|
|
|
|
22
|
|
|
|
18
|
|
|
|
(4
|
)
|
|
|
320
|
|
Other
income
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
|
|
|
6
|
|
Minority
interest
|
|
|
-
|
|
|
|
(12
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(12
|
)
|
EBIT
|
|
$
|
239
|
|
|
$
|
35
|
|
|
$
|
22
|
|
|
$
|
18
|
|
|
$
|
-
|
|
|
$
|
314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
and total assets
(2)
|
|
$
|
4,992
|
|
|
$
|
271
|
|
|
$
|
1,007
|
|
|
$
|
326
|
|
|
$
|
(92
|
)
|
|
$
|
6,504
|
|
Goodwill
|
|
$
|
404
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
14
|
|
|
$
|
-
|
|
|
$
|
418
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
196
|
|
|
$
|
7
|
|
|
$
|
-
|
|
|
$
|
44
|
|
|
$
|
7
|
|
|
$
|
254
|
|
Nine
months ended September 30, 2007
In
millions
|
|
Distribution
operations
|
|
|
Retail
energy
operations
|
|
|
Wholesale
services
|
|
|
Energy
investments
|
|
|
Corporate
and intercompany eliminations
(3)
|
|
|
Consolidated
AGL Resources
|
|
Operating
revenues from external parties
|
|
$
|
1,079
|
|
|
$
|
653
|
|
|
$
|
50
|
|
|
$
|
27
|
|
|
$
|
-
|
|
|
$
|
1,809
|
|
Intercompany
revenues
(1)
|
|
|
137
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(137
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
1,216
|
|
|
|
653
|
|
|
|
50
|
|
|
|
27
|
|
|
|
(137
|
)
|
|
|
1,809
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
612
|
|
|
|
508
|
|
|
|
4
|
|
|
|
-
|
|
|
|
(137
|
)
|
|
|
987
|
|
Operation
and maintenance
|
|
|
250
|
|
|
|
50
|
|
|
|
27
|
|
|
|
14
|
|
|
|
(7
|
)
|
|
|
334
|
|
Depreciation
and amortization
|
|
|
89
|
|
|
|
4
|
|
|
|
2
|
|
|
|
4
|
|
|
|
9
|
|
|
|
108
|
|
Taxes
other than income taxes
|
|
|
25
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
3
|
|
|
|
31
|
|
Total
operating expenses
|
|
|
976
|
|
|
|
563
|
|
|
|
34
|
|
|
|
19
|
|
|
|
(132
|
)
|
|
|
1,460
|
|
Operating
income (loss)
|
|
|
240
|
|
|
|
90
|
|
|
|
16
|
|
|
|
8
|
|
|
|
(5
|
)
|
|
|
349
|
|
Other
income (expense)
|
|
|
2
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
1
|
|
Minority
interest
|
|
|
-
|
|
|
|
(24
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(24
|
)
|
EBIT
|
|
$
|
242
|
|
|
$
|
67
|
|
|
$
|
16
|
|
|
$
|
7
|
|
|
$
|
(6
|
)
|
|
$
|
326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
and total assets
(2)
|
|
$
|
4,780
|
|
|
$
|
211
|
|
|
$
|
699
|
|
|
$
|
276
|
|
|
$
|
(135
|
)
|
|
$
|
5,831
|
|
Goodwill
|
|
$
|
406
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
14
|
|
|
$
|
-
|
|
|
$
|
420
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
145
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
18
|
|
|
$
|
26
|
|
|
$
|
193
|
|
(1)
|
Intercompany
revenues – Wholesale services records its energy marketing and risk
management revenue on a net basis. Wholesale services’ total operating
revenues include intercompany revenues of $289 million and $120 million
for the three months ended September 30, 2008 and 2007, respectively; and
$806 million and $473 million for the nine months ended September 30, 2008
and 2007, respectively.
|
(2)
|
Identifiable
assets are those used in each segment’s
operations.
|
(3)
|
Our
corporate segment’s assets consist primarily of cash and cash equivalents,
property, plant and equipment and reflect the effect of intercompany
eliminations.
|
Certain
expectations and projections regarding our future performance referenced in this
Management’s
Discussion
and Analysis of Financial Condition and
Results
of Operations section and elsewhere in this report, as well as in other reports
and proxy statements we file with the SEC are forward-looking statements.
Officers and other employees may also make verbal statements to analysts,
investors, regulators, the media and others that are
forward-looking.
Forward-looking
statements involve matters that are not historical facts, and because these
statements involve anticipated events or conditions, forward-looking statements
often include words such as "anticipate," "assume," “believe,” "can," "could,"
"estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may,"
“outlook,” "plan," “potential,” "predict," "project,” "seek," "should,"
"target," "will," "would," or similar expressions. Our expectations are not
guarantees and are based on currently available competitive, financial and
economic data along with our operating plans. While we believe that our
expectations are reasonable in view of currently available information, our
expectations are subject to future events, risks and uncertainties, and there
are several factors - many beyond our control - that could cause our results to
differ significantly from our expectations.
Such
events, risks and uncertainties include, but are not limited to, changes in
price, supply and demand for natural gas and related products; the impact of
changes in state and federal legislation and regulation; actions taken by
government agencies on rates and other matters; concentration of credit risk;
utility and energy industry consolidation; the impact on cost and timeliness of
construction projects by government and other approvals, development project
delays, adequacy of supply of diversified vendors, unexpected change in project
costs, including the cost of funds to finance these projects; the impact of
acquisitions and divestitures; direct or indirect effects on our business,
financial condition or liquidity resulting from a change in our credit ratings
or the credit ratings of our counterparties or competitors; interest rate
fluctuations; financial market conditions and general economic conditions;
uncertainties about environmental issues and the related impact of such issues;
the impact of changes in weather on the temperature-sensitive portions of our
business; the impact of natural disasters such as hurricanes on the supply and
price of natural gas; acts of war or terrorism; and other factors described in
detail in our filings with the SEC.
We
caution readers that, in addition to the important factors described elsewhere
in this report, the factors set forth in Item 1A, Risk Factors of our Annual
Report on Form 10-K for the year ended December 31, 2007, among others, could
cause our business, results of operations or financial condition in 2008 and
thereafter to differ significantly from those expressed in any forward-looking
statements. There also may be other factors that we cannot anticipate or that
are not described in our Form 10-K or in this report that could cause results to
differ significantly from our expectations.
Forward-looking
statements are only as of the date they are made. We do not update these
statements to reflect subsequent circumstances or events.
We are an
energy services holding company whose principal business is the distribution of
natural gas through our regulated natural gas distribution business and the sale
of natural gas to end-use customers primarily in Georgia through our retail
natural gas marketing business. For the nine months ended September 2008, our
six utilities serve 2.3 million average end-use customers, making us the largest
distributor of natural gas in the southeastern and mid-Atlantic regions of the
United States based on customer count. Although our retail natural gas marketing
business is not subject to the same regulatory framework as our utilities, it is
an integral part of the framework for providing natural gas service to end-use
customers in Georgia.
We also
engage in natural gas asset management and related logistics activities for our
own utilities as well as for non-affiliated companies; natural gas storage
arbitrage and related activities; and the development and operation of
high-deliverability underground natural gas storage assets. These businesses
allow us to be opportunistic in capturing incremental value at the wholesale
level, provide us with deepened business insight about natural gas market
dynamics and facilitate our ability, in the case of asset management, to provide
transparency to regulators as to how that value can be captured to benefit our
utility customers through profit-sharing arrangements. Given the volatile and
changing nature of the natural gas resource base in North America and globally,
we believe that participation in these related businesses strengthens our
company. We manage these businesses through four operating segments -
distribution operations, retail energy operations, wholesale services, energy
investments and a non-operating corporate segment.
Customer growth -
We
continue to see challenging economic conditions in all the areas we serve and,
as a result, have experienced lower than expected customer growth throughout
2008, a trend we expect to continue through 2009.
For the
nine months ended September 30, 2008, our consolidated utility customer growth
rate was 0.1%, compared to 1.0% for the comparable period last year. We had
anticipated customer growth in 2008 of about 0.5%. The reduction in customer
count is primarily a result of much slower growth in the residential housing
markets throughout our service territories. This trend has been offset slightly
by growth in the commercial customer segment in certain areas, primarily as a
result of conversions to natural gas from other fuel sources.
We
continue to use a variety of targeted marketing programs to attract new
customers and to retain existing ones. These programs generally emphasize
natural gas as the fuel of choice for customers and seek to expand the use of
natural gas through a variety of promotional activities.
We have
seen a 3% decline in average customer count at SouthStar for the nine months
ended September 30, 2008, as compared to the same period in 2007. This decline
reflects some of the same economic conditions that have affected our utility
businesses as well as a more competitive market for natural gas in Georgia. As a
result of recent disruptions in the credit markets, one of the smaller Marketers
in Georgia filed for bankruptcy in October 2008, after being unable to obtain
ongoing funding for working capital needs. Another Marketer assumed
responsibility for the bankrupt Marketer’s 30,000 customers, under an agreement
approved by the Georgia Commission. Our financial exposure to this Marketer is
immaterial.
Natural gas prices -
Increased
energy and transportation prices are expected to impact a significantly larger
portion of consumer household incomes as we move into the 2008/2009 winter
heating season. Although natural gas prices dropped during the third quarter of
2008, industry projections are that customers’ heating costs in the U.S. could
increase as much as 30% over last year. As a result, we may incur additional bad
debt expense during the winter season as well as lower operating margins due to
increased customer conservation in an environment of high natural gas prices.
While we expect these factors could adversely impact our results of operations,
we expect regulatory and operational mechanisms in place in most of our
jurisdictions will help mitigate our exposure to these factors.
These
risks of increased bad debt expense and decreased operating margins from
conservation are minimized at our largest utility, Atlanta Gas Light, as a
result of its straight-fixed variable rate structure. In addition, customers in
Georgia buy their natural gas from certificated marketers rather than from
Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related
to the provision of services to the certificated marketers, but that exposure is
mitigated, as we obtain security support in an amount equal to a minimum of two
times a marketer’s highest month’s estimated bill. At our other utilities, while
customer conservation could adversely impact our operating margins, we will
utilize measures to collect delinquent accounts and continue to be rigorous in
monitoring and mitigating the impact of these expenses. We do, however, expect
that our bad debt expense for the upcoming winter heating season will be higher
than the prior year.
We are
working with regulators and state agencies in each of our jurisdictions to
educate customers about these issues in advance of the winter heating season, in
particular to ensure that those qualified for the Low Income Home Energy
Assistance Program funds and other similar programs will receive that
assistance.
SouthStar
may also be affected by the conservation and bad debt trends, but its overall
exposure is partially mitigated by the high credit quality of SouthStar’s
customer base, disciplined collection practices and the unregulated pricing
structure in Georgia.
The
rising commodity prices during the first six month of 2008, along with reduced
opportunities related to the management of storage and transportation assets
throughout the first nine months of 2008 further negatively impacted SouthStar’s
operating margin by $15 million. More favorable market conditions and decreasing
natural gas prices in the first six months of 2007 as compared to rising prices
during the same time frame in 2008 enabled SouthStar to recognize higher
operating margins for year-to-date September 30, 2007 as compared to 2008.
SouthStar’s reported results were also negatively impacted during the current
year quarter by the significant decrease in natural gas prices during the three
months ended September 30, 2008 as SouthStar was required to record an $18
million LOCOM adjustment to reduce its natural gas inventory to
market.
Due to
the rising commodity price environment and the widening of transportation basis
spreads during the first six months of 2008, Sequent recorded $70 million in
losses on the financial instruments it uses to hedge its storage and
transportation positions. The natural gas market remained volatile with
significant decreases in prices and narrowing of basis spreads during the
quarter ended September 30, 2008. Consequently Sequent recognized gains on
hedging instruments of $117 million for the quarter and $47 million for the
first nine months of 2008. This is a $106 million and $30 million net increase
compared to last year’s third quarter and year-to-date periods, respectively. In
addition to the increase in hedge gains Sequent’s commercial activity improved
by $16 million and $19 million for the quarter ended and year-to-date periods
ended September 30, 2008, respectively due to more favorable business
opportunities presented by the greater volatility in the marketplace than in
2007. This improvement was due in part to increased hurricane activity, although
the market did not react as strongly as it did after hurricanes Rita and Katrina
in 2005 as there was less damage to the natural gas infrastructure and increased
onshore production.
In
addition, the decrease in forward prices caused Sequent to be subject to a LOCOM
adjustment on its natural gas inventory. The increase in the impact of the
adjustment, net of estimated hedging recoveries, was $33 million and $32 million
for the quarter and year-to-date periods, respectively. These changes resulted
in Sequent reporting operating margin that was $89 million and $17 million
higher for the current quarter and year-to-date periods ended September 30,
2008, respectively, as compared to last year.
Distribution
Operations -
Our distribution operations segment is the largest component
of our business and includes these natural gas utilities in six
states:
·
|
Atlanta
Gas Light in Georgia
|
·
|
Chattanooga
Gas in Tennessee
|
·
|
Elizabethtown
Gas in New Jersey
|
·
|
Florida
City Gas in Florida
|
·
|
Virginia
Natural Gas in Virginia
|
Each
utility operates subject to regulations of the state regulatory agencies in its
service territories with respect to rates charged to our customers, maintenance
of accounting records and various other service and safety matters. Rates
charged to our customers vary according to customer class (residential,
commercial or industrial) and rate jurisdiction. Rates are set at levels that
generally should allow us to recover all prudently incurred costs, including a
return on rate base sufficient to pay interest on debt and provide a reasonable
return for our shareholders.
We
continuously monitor the performance of our utilities to determine whether rates
need to be adjusted through the regulatory process. We have long-term fixed rate
settlements in our three largest franchises in Georgia, New Jersey and
Virginia.
With the
exception of Atlanta Gas Light and Elkton Gas, earnings in our distribution
operations segment can be affected by customer consumption patterns that are a
function of weather conditions and price levels for natural gas. Atlanta Gas
Light charges rates to its customers primarily as monthly fixed charges. In May
2008, new rates became effective for Elkton Gas which included mechanisms that
returned operating margin per customer to levels approved by the Maryland
Commission in its most recent rate decision.
Our other
jurisdictions have various regulatory mechanisms that allow us to recover our
costs, but they are not direct offsets to the potential impacts of weather and
customer consumption on earnings. In our New Jersey, Virginia and Tennessee
utilities, their respective tariffs contain WNA or similar provisions that are
designed to help stabilize operating results by increasing base rate amounts
charged to customers when weather is warmer than normal and decreasing amounts
charged when weather is colder than normal. The WNA is most effective in a
reasonable temperature range relative to normal weather using historical
averages.
Upcoming rate
cases
Beginning in 2009 through 2010, we will file rate cases in four of
our six jurisdictions. These rate case filings are required due to settlements
we reached with the applicable state authority in previous rate case or
acquisition proceedings. The expected filing dates and dates for which
current rates are effective are outlined in the chart below:
Company
|
Expected
filing
date
|
Current
rates effective until
|
Elizabethtown
Gas
|
Q1
2009
|
Q4
2009 - Q1 2010
|
Atlanta
Gas Light
|
Q4
2009
|
Q2
2010
|
Virginia
Natural Gas
|
Q1
2010
|
Q3
2011
|
Chattanooga
Gas
|
Q2
2010
|
Q1 2011
|
Virginia Natural
Gas
In July 2008, Virginia Natural Gas filed a Conservation and
Ratemaking Efficiency Plan (Conservation Plan) with the Virginia Commission. The
plan was filed pursuant to a Virginia law that allows natural gas utilities to
implement conservation programs and alternative rate designs which would allow
the utility to recover the cost of providing safe and reliable service based on
normal customer usage. On Octoer 29, 2008, Virginia Natural Gas filed with
the Virginia Commission a motion for approval of a proposed stipulation. If
the proposed stipulation is approved by the Virginia Commission, Virginia
Natural Gas will invest approximately $7 million over three years in new
conservation programs. Virginia Natural Gas will also implement an accompanying
decoupled rate design mechanism that will mitigate the impact of conservation
and declining usage and provide the utility with an opportunity to recover its
fixed costs. Hearings on the Conservation Plan and proposed stipulation were
held in October 2008, and the Virginia Commission is expected to issue a ruling
by the end of 2008.
Magnolia
Enterprise Holdings, Inc. (Magnolia)
In September 2007, we received
approval from the Georgia Commission for Atlanta Gas Light’s capacity supply
plan in Georgia. A key part of that agreement was the ability to diversify our
supply sources by gaining more access to the Elba Island liquefied natural gas
(LNG) facility. As a result, Southern Natural Gas (SNG) and our affiliate,
Magnolia filed a joint application with the FERC to obtain an undivided interest
in pipelines connecting our Georgia service territory to the Elba Island LNG
facility and for approval of the project. Under the proposed transaction,
Magnolia would purchase the undivided interest and lease the interest to SNG.
Atlanta Gas Light would then subscribe to the associated capacity from
SNG. The project is expected to be completed in 2010.
Retail Energy
Operations
-
Our retail energy operations segment consists of
SouthStar, a joint venture owned 70% by us and 30% by Piedmont. SouthStar
markets natural gas and related services to retail customers on an unregulated
basis, principally in Georgia, as well as to commercial and industrial customers
in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina.
SouthStar is the largest marketer of natural gas in Georgia with an approximate
35% market share, based on customer count.
Although
our ownership interest in the SouthStar partnership is 70%, the majority of
SouthStar's earnings in Georgia are allocated by contract 75% to us and 25% to
Piedmont. SouthStar’s earnings related to customers in Ohio and Florida are
allocated 70% to us and 30% to Piedmont. We record the earnings allocated to
Piedmont as a minority interest in our condensed consolidated statements of
income, and we record Piedmont’s portion of SouthStar’s capital as a minority
interest in our condensed consolidated balance sheets. The majority of
SouthStar’s earnings allocated to us for the three and nine months ended
September 30, 2008, were at the 75% contractual rate.
Beginning in October 2008, SouthStar
was awarded the right to supply a total of approximately 15 Bcf of natural gas
to customers of Vectren Energy Delivery of Ohio (VEDO) through March 2010. As
part of this agreement, SouthStar will manage the supply, transportation and
storage of natural gas on behalf of VEDO
.
SouthStar’s
operations are sensitive to seasonal weather, natural gas prices, and customer
growth and consumption patterns similar to those affecting our utility
operations. SouthStar’s retail pricing strategies and use of various economic
hedging strategies, such as futures, options, swaps, weather derivative
instruments and other risk management tools, help to ensure retail customer
costs are covered to mitigate the potential effect of these issues on its
operations.
Wholesale Services
-
Our wholesale services segment consists primarily of Sequent, our
subsidiary involved in asset management and optimization, storage,
transportation, producer and peaking services and wholesale marketing. Sequent
seeks asset optimization opportunities, which focus on capturing the value from
idle or underutilized assets, typically by participating in transactions to take
advantage of pricing differences between varying markets and time horizons
within the natural gas supply, storage and transportation markets to generate
earnings. These activities are generally referred to as arbitrage
opportunities.
Sequent’s
profitability is driven by volatility in the natural gas marketplace. Volatility
arises from a number of factors such as weather fluctuations or the change in
supply of, or demand for, natural gas in different regions of the country.
Sequent seeks to capture value from the price disparity across geographic
locations and various time horizons (location and seasonal spreads). In doing
so, Sequent also seeks to mitigate the risks associated with this volatility and
protect its margin through a variety of risk management and economic hedging
activities.
Sequent
provides its customers with natural gas from the major producing regions and
market hubs in the U.S. and Canada. Sequent acquires transportation and storage
capacity to meet its delivery requirements and customer obligations in the
marketplace. Sequent’s
customers
benefit from its logistics expertise and ability to deliver natural gas at
prices that are advantageous relative to other alternatives available to its
customers.
During
the third quarter of 2008, Sequent negotiated an agreement for 40,000 dekatherms
per day of transportation capacity for a period of 25 years beginning in August
2009. Upon execution of this agreement in 2009, we will include approximately
$89 million of future demand payments associated with this capacity within our
unrecorded contractual obligations and commitment disclosures. Sequent will
identify opportunities to lock-in economic value associated with this capacity
through the use of financial hedges. The hedging of the capacity may increase
our exposure to hedge gains and losses as well as potentially impact VaR. There
was no significant impact to hedge gains or losses or VaR during the
period.
Asset management
transactions
The following table provides updated information on
Sequent’s asset management agreements with its affiliated utilities, including
amended or extended agreements in 2008 with Florida City Gas, Chattanooga Gas
and Elizabethtown Gas.
|
|
|
%
of shared
|
|
|
|
|
profits
or annual fee
|
|
Virginia
Natural Gas
|
Mar
2009
|
|
(A)
|
|
Chattanooga
Gas
|
Mar
2011
|
|
|
50%
(B)
|
|
Elizabethtown
Gas
|
Mar
2011
|
|
(A)
(B)
|
|
Atlanta
Gas Light
|
Mar
2012
|
|
up
to 60%
|
(B)
|
Florida
City Gas
|
Mar
2013
|
|
|
50%
|
|
(A)
|
Shared
on a tiered structure.
|
(B)
|
Includes
aggregate annual minimum payments of $12 million
for
Chattanooga Gas, Elizabethtown Gas and Atlanta Gas
Light.
|
Storage inventory
outlook
The following graph presents the NYMEX forward natural gas prices
as of September 30, 2008, June 30, 2008 and December 31, 2007, for the period of
October 2008 through September 2009, and reflects the prices at which Sequent
could buy natural gas at the Henry Hub for delivery in the same time
period.
Sequent’s
expected natural gas withdrawals from physical salt dome and reservoir storage
are presented in the following table along with the operating revenues expected
at the time of withdrawal. Sequent’s expected operating revenues are net of the
estimated impact of regulatory sharing and reflect the amounts that are
realizable in future periods based on the inventory withdrawal schedule and
forward natural gas prices at September 30, 2008. Sequent’s storage inventory is
economically hedged with futures contracts, which results in an overall
locked-in margin, timing notwithstanding.
|
|
Withdrawal
schedule
(
in
Bcf
)
|
|
|
|
|
|
|
Salt dome
(WACOG
$6.82)
|
|
|
Reservoir
(WACOG
$6.84)
|
|
|
Expected
operating
revenues
(in
millions)
|
|
2008
|
|
|
|
|
|
|
|
|
|
Fourth
quarter
|
|
|
2
|
|
|
|
9
|
|
|
$
|
7
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
First
quarter
|
|
|
-
|
|
|
|
5
|
|
|
|
5
|
|
Total
|
|
|
2
|
|
|
|
14
|
|
|
$
|
12
|
|
If
Sequent’s optimization efforts are executed as planned, it expects operating
revenues from storage withdrawals of approximately $7 million during the three
months ending December 31, 2008 and $5 million in 2009. This could change as
Sequent adjusts its daily injection and withdrawal plans in response to changes
in market conditions in future months and as forward NYMEX prices fluctuate.
Based upon Sequent’s current projection of year-end storage positions at
December 31, 2008, a $1.00 increase in the first quarter 2009 forward NYMEX
prices could result in a $4 million reduction to Sequent’s reported operating
revenues for the year ending December 31, 2008, after regulatory sharing. A
$1.00 decrease in forward NYMEX prices would result in a $4 million positive
impact to Sequent’s reported operating revenues; however additional LOCOM
adjustments could potentially offset a portion of the positive impact.
This amount
does not include operating expenses that will be incurred to realize this
amount. For more information on Sequent’s energy marketing and risk management
activities, see Item 3, Quantitative and Qualitative Disclosures About Market
Risk - Commodity Price Risk.
Energy
Investments
-
Our energy investments segment includes a number of businesses that are
related or complementary to our primary business. The most significant of these
businesses is our natural gas storage business, Jefferson Island, which operates
a high-deliverability salt-dome storage asset in the Gulf Coast region of the
U.S. While our salt-dome storage business also can generate additional revenue
during times of peak market demand for natural gas storage services, the
majority of its storage services are covered under medium to long-term contracts
at a fixed market rate.
We are
actively pursuing litigation against the State of Louisiana to obtain a court
order or settlement confirming Jefferson Island’s right to expand its existing
facility. Jefferson Island’s litigation with the State of Louisiana is described
in further detail in
Note 6,
“Commitments and
Contingencies.” In June 2008, the State of Louisiana passed legislation
restricting water usage from the Chicot aquifer, which is a main source of fresh
water required for the expansion of the Jefferson Island capacity. We
contend that this legislation is unconstitutional and have sought to amend the
pending litigation to seek a declaration that it is invalid and cannot be
enforced. Even if we are not successful on those grounds, we believe the
legislation does not materially impact the feasibility of the expansion
project.
Through
Golden Triangle Storage, we are constructing a new salt-dome storage facility in
the Gulf Coast region of the U.S. In May 2008, Golden Triangle Storage started
construction on the first cavern. Hurricanes Gustav and Ike caused some damage
and minor delays in September 2008, but our timelines associated with
commencement of commercial operations remain on schedule. We previously
estimated based on then current prices for labor, materials and pad gas that
costs to construct the facility would be approximately $265
million. However, prices for labor, materials and pad gas have risen
significantly in the ensuing months, increasing the estimated construction cost
by approximately 10% to 20%. The actual project costs depend upon the facility’s
configuration, materials, drilling costs, financing costs and the amount and
cost of pad gas, which includes volumes of non-working natural gas used to
maintain the operational integrity of the cavern facility. The costs for the
vast majority of these items have not been fixed and are subject to continued
variability during the period of construction. Further, since we are not
able to predict whether these costs of construction will continue to increase,
moderate or decrease from current levels, we believe that there could be
continued volatility in the construction cost estimates.
We also
own and operate a telecommunications business, AGL Networks, which constructs
and operates conduit and fiber infrastructure within select metropolitan
areas.
Corporate
-
Our corporate segment includes our nonoperating business units, including
AGL Services Company and AGL Capital.
We
allocate substantially all of our corporate segment operating expenses and
interest costs to our operating segments in accordance with state regulations.
Our segment results include the impact of these allocations to the various
operating segments. Our corporate segment also includes intercompany
eliminations for transactions between our operating business
segments.
Operating margin
and EBIT
We evaluate segment performance using the measures of operating
margin and EBIT, which include the effects of corporate expense allocations. Our
operating margin and EBIT are not measures that are considered to be calculated
in accordance with GAAP. EBIT is a non-GAAP measure that includes operating
income, other income and expenses and minority interest. Items that we do not
include in EBIT are financing costs, including interest and debt expense and
income taxes, each of which we evaluate on a consolidated level. Operating
margin is also a non-GAAP measure that is calculated as operating revenues minus
cost of gas, which excludes operation and maintenance expense, depreciation and
amortization, taxes other than income taxes, and the gain or loss on the sale of
our assets; these items are included in our calculation of operating income as
reflected in our condensed consolidated statements of income.
We
believe operating margin is a better indicator than operating revenues for the
contribution resulting from customer growth in our distribution operations
segment since the cost of gas can vary significantly and is generally passed
directly to our customers. We also consider operating margin to be a better
indicator in our retail energy operations, wholesale services and energy
investments segments since it is a direct measure of gross profit before
overhead costs. We believe EBIT is a useful measurement of our operating
segments’ performance because it provides information that can be used to
evaluate the effectiveness of our businesses from an operational perspective,
exclusive of the costs to finance those activities and exclusive of income
taxes, neither of which is directly relevant to the efficiency of those
operations.
You
should not consider operating margin or EBIT an alternative to, or a more
meaningful indicator of, our operating performance than net income as determined
in accordance with GAAP. In addition, our operating margin or EBIT measures may
not be comparable to similarly titled measures from other
companies.
Seasonality
The operating revenues and EBIT of our distribution operations, retail
energy operations and wholesale services segments are seasonal. During the
heating season, natural gas usage and operating revenues are generally higher
because more customers are connected to our distribution systems and natural gas
usage is higher in periods of colder weather than in periods of warmer weather.
Occasionally in the summer, Sequent’s operating margins are impacted due to peak
usage by power generators in response to summer energy demands. Our base
operating expenses, excluding cost of gas, interest expense and certain
incentive compensation costs, are incurred relatively equally over any given
year. Thus, our operating results vary significantly from quarter to quarter as
a result of seasonality.
Seasonality
also affects the comparison of certain balance sheet items, such as receivables,
inventories and short-term debt across quarters. However, these items are
comparable when reviewing our annual results. Accordingly, we have presented the
condensed consolidated balance sheets as of September 30, 2007, to provide
comparisons of these items to December 31, 2007, and September 30,
2008.
Hedging
Changes in commodity prices subject a significant portion of our
operations to earnings variability. Our nonutility businesses principally use
physical and financial arrangements economically to hedge the risks associated
with seasonal fluctuations in market conditions, changing commodity prices and
weather. In addition, because these economic hedges may not qualify, or are not
designated, for hedge accounting treatment, our reported earnings for the
wholesale services and retail energy operations segments include the changes in
the fair values of certain derivatives. These values may change significantly
from period to period and are reflected as mark-to-market adjustments within our
operating margin.
Elizabethtown
Gas utilizes certain derivatives in accordance with a directive from the New
Jersey Commission to create a hedging program to hedge the impact of market
fluctuations in natural gas prices. These derivative products are accounted for
at fair value each reporting period. In accordance with regulatory requirements,
realized gains and losses related to these derivatives are reflected in
purchased gas costs and ultimately included in billings to customers. Unrealized
gains and losses are reflected as a regulatory asset or liability, as
appropriate, in our condensed consolidated balance sheets.
The
following table sets forth a reconciliation of our operating margin and EBIT to
our operating income, earnings before income taxes and net income, together with
other consolidated financial information for the three and nine months ended
September 30, 2008 and 2007.
|
|
Three
months ended September 30,
|
Nine
months ended September 30,
|
|
In
millions, except per share data
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Operating
revenues
|
|
$
|
539
|
|
|
$
|
369
|
|
|
$
|
170
|
|
|
$
|
1,995
|
|
|
$
|
1,809
|
|
|
$
|
186
|
|
Cost
of gas
|
|
|
261
|
|
|
|
159
|
|
|
|
102
|
|
|
|
1,193
|
|
|
|
987
|
|
|
|
206
|
|
Operating
margin
(1)
|
|
|
278
|
|
|
|
210
|
|
|
|
68
|
|
|
|
802
|
|
|
|
822
|
|
|
|
(20
|
)
|
Operating
expenses
|
|
|
152
|
|
|
|
155
|
|
|
|
(3
|
)
|
|
|
482
|
|
|
|
473
|
|
|
|
9
|
|
Operating
income
|
|
|
126
|
|
|
|
55
|
|
|
|
71
|
|
|
|
320
|
|
|
|
349
|
|
|
|
(29
|
)
|
Other
income
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
|
|
6
|
|
|
|
1
|
|
|
|
5
|
|
Minority
interest
|
|
|
5
|
|
|
|
-
|
|
|
|
5
|
|
|
|
(12
|
)
|
|
|
(24
|
)
|
|
|
12
|
|
EBIT
(1)
|
|
|
133
|
|
|
|
55
|
|
|
|
78
|
|
|
|
314
|
|
|
|
326
|
|
|
|
(12
|
)
|
Interest
expense, net
|
|
|
29
|
|
|
|
34
|
|
|
|
(5
|
)
|
|
|
85
|
|
|
|
92
|
|
|
|
(7
|
)
|
Earnings
before income taxes
|
|
|
104
|
|
|
|
21
|
|
|
|
83
|
|
|
|
229
|
|
|
|
234
|
|
|
|
(5
|
)
|
Income
tax expense
|
|
|
39
|
|
|
|
8
|
|
|
|
31
|
|
|
|
86
|
|
|
|
89
|
|
|
|
(3
|
)
|
Net
income
|
|
$
|
65
|
|
|
$
|
13
|
|
|
$
|
52
|
|
|
$
|
143
|
|
|
$
|
145
|
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.85
|
|
|
$
|
0.17
|
|
|
$
|
0.68
|
|
|
$
|
1.87
|
|
|
$
|
1.88
|
|
|
$
|
(0.01
|
)
|
Diluted
|
|
$
|
0.85
|
|
|
$
|
0.17
|
|
|
$
|
0.68
|
|
|
$
|
1.87
|
|
|
$
|
1.87
|
|
|
$
|
-
|
|
Weighted-average
number of common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
76.4
|
|
|
|
77.0
|
|
|
|
(0.6
|
)
|
|
|
76.2
|
|
|
|
77.4
|
|
|
|
(1.2
|
)
|
Diluted
|
|
|
76.6
|
|
|
|
77.4
|
|
|
|
(0.8
|
)
|
|
|
76.5
|
|
|
|
77.8
|
|
|
|
(1.3
|
)
|
(1)
|
These
are non-GAAP measurements.
|
Selected
weather, customer and volume metrics, which we consider to be some of the key
performance indicators for our operating segments, for the three and nine months
ended September 30, 2008 and 2007, are presented in the following tables. We
measure the effects of weather on our business through heating degree days.
Generally, increased heating degree days result in greater demand for gas on our
distribution systems. However, extended and unusually mild weather during the
heating season can have a significant negative impact on demand for natural gas.
Our marketing and customer retention initiatives are measured by our customer
metrics which can be impacted by natural gas prices, economic conditions and
competition from alternative fuels. Volume metrics for distribution operations
and retail energy operations present the effects of weather and our customer’s
demand for natural gas. Wholesale services’ daily physical sales represent the
daily average natural gas volumes sold to its customers.
Weather
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
degree days (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
months ended
September
30,
|
|
|
2008
vs. normal colder
|
|
|
2008
vs. 2007 colder
|
|
|
|
|
Normal
|
|
|
2008
|
|
|
2007
|
|
|
(warmer)
|
|
|
(warmer)
|
|
|
Florida
|
|
|
336
|
|
|
|
215
|
|
|
|
281
|
|
|
|
(36
|
)%
|
|
|
(23
|
)%
|
Georgia
|
|
|
1,587
|
|
|
|
1,654
|
|
|
|
1,489
|
|
|
|
4
|
%
|
|
|
11
|
%
|
Maryland
|
|
|
3,032
|
|
|
|
2,828
|
|
|
|
3,063
|
|
|
|
(7
|
)%
|
|
|
(8
|
)%
|
New
Jersey
|
|
|
3,031
|
|
|
|
2,918
|
|
|
|
3,172
|
|
|
|
(4
|
)%
|
|
|
(8
|
)%
|
Tennessee
|
|
|
1,807
|
|
|
|
1,888
|
|
|
|
1,753
|
|
|
|
4
|
%
|
|
|
8
|
%
|
Virginia
|
|
|
2,052
|
|
|
|
1,880
|
|
|
|
2,090
|
|
|
|
(8
|
)%
|
|
|
(10
|
)%
|
(1)
Obtained
from weather stations relevant to our service areas at the National Oceanic and
Atmospheric Administration, National Climatic Data Center. Normal represents
ten-year averages from October 1999 through September 2008.
|
|
Three
months ended
|
|
|
|
|
|
|
Nine
months ended
|
|
|
|
|
|
Customers
|
|
September
30,
|
|
|
|
|
|
|
September
30,
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
2007
|
|
|
%
Change
|
|
|
|
2008
|
|
|
|
2007
|
|
|
%
Change
|
|
Distribution
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average end-use customers
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlanta
Gas Light
|
|
|
1,536
|
|
|
|
1,539
|
|
|
|
(0.2
|
)%
|
|
|
1,564
|
|
|
|
1,564
|
|
|
|
-
|
|
Chattanooga
Gas
|
|
|
60
|
|
|
|
60
|
|
|
|
-
|
|
|
|
61
|
|
|
|
61
|
|
|
|
-
|
|
Elizabethtown
Gas
|
|
|
272
|
|
|
|
271
|
|
|
|
0.4
|
%
|
|
|
273
|
|
|
|
272
|
|
|
|
0.4
|
%
|
Elkton
Gas
|
|
|
6
|
|
|
|
6
|
|
|
|
-
|
|
|
|
6
|
|
|
|
6
|
|
|
|
-
|
|
Florida
City Gas
|
|
|
103
|
|
|
|
104
|
|
|
|
(1.0
|
)%
|
|
|
104
|
|
|
|
104
|
|
|
|
-
|
|
Virginia
Natural Gas
|
|
|
268
|
|
|
|
265
|
|
|
|
1.1.
|
%
|
|
|
271
|
|
|
|
269
|
|
|
|
0.7
|
%
|
Total
|
|
|
2,245
|
|
|
|
2,245
|
|
|
|
-
|
|
|
|
2,279
|
|
|
|
2,276
|
|
|
|
0.1
|
%
|
Operation
and maintenance per customer
|
|
$
|
32
|
|
|
$
|
35
|
|
|
|
(9
|
)%
|
|
$
|
106
|
|
|
$
|
110
|
|
|
|
(4
|
)%
|
EBIT
per customer
|
|
$
|
26
|
|
|
$
|
24
|
|
|
|
8
|
%
|
|
$
|
105
|
|
|
$
|
106
|
|
|
|
(1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
customers in Georgia
(in
thousands)
|
|
|
518
|
|
|
|
535
|
|
|
|
(3
|
)%
|
|
|
529
|
|
|
|
543
|
|
|
|
(3
|
)%
|
Market
share in Georgia
|
|
|
34
|
%
|
|
|
35
|
%
|
|
|
(1
|
)%
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
-
|
|
Volumes
|
|
Three
months ended September 30,
|
|
|
|
|
|
Nine
months ended September 30,
|
|
|
|
|
In
billion cubic feet (Bcf)
|
|
2008
|
|
|
2007
|
|
|
%
change
|
|
|
2008
|
|
|
2007
|
|
|
%
change
|
|
Distribution
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm
|
|
|
20.0
|
|
|
|
20.1
|
|
|
|
(1
|
)%
|
|
|
146.8
|
|
|
|
148.9
|
|
|
|
(1
|
)%
|
Interruptible
|
|
|
24.1
|
|
|
|
25.1
|
|
|
|
(4
|
)%
|
|
|
78.1
|
|
|
|
80.9
|
|
|
|
(3
|
)%
|
Total
|
|
|
44.1
|
|
|
|
45.2
|
|
|
|
(2
|
)%
|
|
|
224.9
|
|
|
|
229.8
|
|
|
|
(2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Georgia
firm
|
|
|
3.5
|
|
|
|
3.5
|
|
|
|
-
|
|
|
|
27.0
|
|
|
|
27.1
|
|
|
|
-
|
|
Ohio
and Florida
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
-
|
|
|
|
3.3
|
|
|
|
3.1
|
|
|
|
6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily
physical sales (Bcf/day)
|
|
|
2.6
|
|
|
|
2.3
|
|
|
|
13
|
%
|
|
|
2.5
|
|
|
|
2.3
|
|
|
|
9
|
%
|
Third
quarter 2008 compared to third quarter 2007
Segment
information
Operating revenues, operating margin, operating expenses and
EBIT information for each of our segments are contained in the following table
for the three months ended September 30, 2008 and 2007.
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
272
|
|
|
$
|
171
|
|
|
$
|
113
|
|
|
$
|
59
|
|
Retail
energy operations
|
|
|
149
|
|
|
|
(5
|
)
|
|
|
16
|
|
|
|
(16
|
)
|
Wholesale
services
|
|
|
138
|
|
|
|
101
|
|
|
|
15
|
|
|
|
86
|
|
Energy
investments
|
|
|
13
|
|
|
|
10
|
|
|
|
7
|
|
|
|
3
|
|
Corporate
(2)
|
|
|
(33
|
)
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Consolidated
|
|
$
|
539
|
|
|
$
|
278
|
|
|
$
|
152
|
|
|
$
|
133
|
|
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
256
|
|
|
$
|
173
|
|
|
$
|
118
|
|
|
$
|
55
|
|
Retail
energy operations
|
|
|
128
|
|
|
|
16
|
|
|
|
18
|
|
|
|
(1
|
)
|
Wholesale
services
|
|
|
13
|
|
|
|
12
|
|
|
|
11
|
|
|
|
1
|
|
Energy
investments
|
|
|
9
|
|
|
|
9
|
|
|
|
6
|
|
|
|
3
|
|
Corporate
(2)
|
|
|
(37
|
)
|
|
|
-
|
|
|
|
2
|
|
|
|
(3
|
)
|
Consolidated
|
|
$
|
369
|
|
|
$
|
210
|
|
|
$
|
155
|
|
|
$
|
55
|
|
(1)
|
These
are non-GAAP measures. A reconciliation of operating margin and EBIT to
our operating income, (loss) earnings before income taxes and net income
is located in “Results of Operations”
herein.
|
(2)
|
Includes
intercompany eliminations.
|
For the
third quarter of 2008, net income increased by $52 million and earnings per
share increased by $0.68 per basic and diluted share compared to same period
last year. The variance between the two quarters was primarily the result of the
effects of changes in forward natural gas prices on the operating margins at
retail energy operations and wholesale services as discussed in more detail
below.
Operating margin
Our operating margin for the third quarter of 2008 increased by $68
million or 32% compared to the same period last year. This increase was
primarily due to increased operating margins at wholesale services and energy
investments partially offset by decreased operating margins at distribution
operations and retail energy operations.
Distribution
operations’ operating margin decreased by $2 million or 1% compared to last
year. The following table indicates the significant changes in distribution
operations’ operating margin for the three months ended September 30, 2008
compared to 2007.
In
millions
|
|
|
|
Operating
margin for third quarter of 2007
|
|
$
|
173
|
|
Reduced
customer growth and usage
|
|
|
(3
|
)
|
Higher
PRP revenues at Atlanta Gas Light
|
|
|
2
|
|
Other
|
|
|
(1
|
)
|
Operating
margin for third quarter of 2008
|
|
$
|
171
|
|
Retail
energy operations’ operating margin decreased by $21 million or 131%. The
following table indicates the significant changes in retail energy operations’
operating margin for the three months ended September 30, 2008 compared to
2007.
In
millions
|
|
|
|
Operating
margin for third quarter of 2007
|
|
$
|
16
|
|
Inventory
LOCOM
|
|
|
(18
|
)
|
Decrease
in average number of customers and other
|
|
|
(2
|
)
|
Lower
operating margins in Ohio
|
|
|
(1
|
)
|
Operating
margin for third quarter of 2008
|
|
$
|
(5
|
)
|
Wholesale
services’ operating margin increased $89 million compared to the third quarter
of 2007 primarily due to gains on the instruments used to hedge its storage and
transportation positions as a result of a significant decrease in forward NYMEX
natural gas prices and the narrowing of transportation basis spreads in the
current period compared to moderate price declines experienced in 2007. These
gains were partially offset by a larger required LOCOM adjustment in the current
period. The following table indicates the significant changes in wholesale
services’ operating margin for the three months ended September 30, 2008 and
2007.
In
millions
|
|
2008
|
|
|
2007
|
|
Gain
on storage hedges
|
|
$
|
105
|
|
|
$
|
12
|
|
Commercial
activity
|
|
|
18
|
|
|
|
2
|
|
Gain
(loss) on transportation hedges
|
|
|
12
|
|
|
|
(1
|
)
|
Inventory
LOCOM, net of hedging recoveries
|
|
|
(34
|
)
|
|
|
(1
|
)
|
Operating
margin
|
|
$
|
101
|
|
|
$
|
12
|
|
For more
information on Sequent’s expected operating revenues from its storage inventory
in the remainder of 2008 and in 2009 and discussion of the increased commercial
activity as compared to last year, see the description of wholesale services’
business in this section beginning on page 21.
Operating
Expenses
Our operating expenses for the third quarter of 2008 decreased
$3 million or 2% as compared to the third quarter of 2007. The following table
indicates the significant changes in our operating expenses.
In
millions
|
|
|
|
|
Operating
expenses for third quarter of 2007
|
|
$
|
155
|
|
Increased
bad debt expenses at distribution operations due to higher natural gas
prices
|
|
|
3
|
|
Decreased
pension expenses at distribution operations, primarily due to updated
actuarial expense estimates
|
|
|
(4
|
)
|
Decreased
incentive compensation program expenses at distribution
operations
|
|
|
(3
|
)
|
Increased
incentive compensation costs at wholesale services due to increased
earnings
|
|
|
3
|
|
Decreased
operating costs at retail energy operations due to slightly lower outside
services and marketing costs
|
|
|
(2
|
)
|
Operating
expenses for third quarter of 2008
|
|
$
|
152
|
|
Interest Expense
Interest expense decreased by $5 million or 15% for the three months
ended September 30, 2008, primarily due to the decrease in short-term interest
rates partially offset by higher average debt outstanding as indicated in the
following table.
|
|
Three
months ended September 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Average
debt outstanding (1)
|
|
$
|
2,225
|
|
|
$
|
1,997
|
|
|
$
|
228
|
|
Average
rate
|
|
|
5.2
|
%
|
|
|
6.2
|
%
|
|
|
(1.0
|
)%
|
(1) Daily
average of all outstanding debt.
Nine
months 2008 compared to nine months 2007
Segment
information
Operating revenues, operating margin, operating expenses and
EBIT information for each of our segments are contained in the following table
for the nine months ended September 30, 2008 and 2007.
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
1,293
|
|
|
$
|
599
|
|
|
$
|
362
|
|
|
$
|
239
|
|
Retail
energy operations
|
|
|
701
|
|
|
|
101
|
|
|
|
54
|
|
|
|
35
|
|
Wholesale
services
|
|
|
104
|
|
|
|
63
|
|
|
|
41
|
|
|
|
22
|
|
Energy
investments
|
|
|
43
|
|
|
|
39
|
|
|
|
21
|
|
|
|
18
|
|
Corporate
(2)
|
|
|
(146
|
)
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
Consolidated
|
|
$
|
1,995
|
|
|
$
|
802
|
|
|
$
|
482
|
|
|
$
|
314
|
|
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
1,216
|
|
|
$
|
604
|
|
|
$
|
364
|
|
|
$
|
242
|
|
Retail
energy operations
|
|
|
653
|
|
|
|
145
|
|
|
|
55
|
|
|
|
67
|
|
Wholesale
services
|
|
|
50
|
|
|
|
46
|
|
|
|
30
|
|
|
|
16
|
|
Energy
investments
|
|
|
27
|
|
|
|
27
|
|
|
|
19
|
|
|
|
7
|
|
Corporate
(2)
|
|
|
(137
|
)
|
|
|
-
|
|
|
|
5
|
|
|
|
(6
|
)
|
Consolidated
|
|
$
|
1,809
|
|
|
$
|
822
|
|
|
$
|
473
|
|
|
$
|
326
|
|
|
(1) These
are non-GAAP measures. A reconciliation of operating margin and EBIT to
our operating income, earnings before income taxes and net income is
located in “Results of Operations”
herein.
|
|
(2) Includes
intercompany eliminations.
|
For the
nine months ended September 30, 2008, net income decreased by $2 million and
basic earnings per share was down $0.01 compared to the same period last year.
This variance was primarily the result of changes in forward natural gas prices
on the operating margins at retail energy operations and wholesale services and
reduced natural gas usage at distribution operations and retail energy
operations as discussed in more detail below.
Operating margin
Our operating margin for the nine months ended September 30, 2008,
decreased by $20 million or 2% compared to the same period last year. This
decrease was primarily due to decreased operating margins at retail energy
operations and distribution operations partially offset by increased operating
margins at wholesale services and energy investments.
Distribution
operations’ operating margin decreased by $5 million or 1% compared to the same
period last year. The following table indicates the significant changes in
distribution operations’ operating margin for the nine months ended September
30, 2008 compared to 2007.
In
millions
|
|
|
|
Operating
margin for the first nine months of 2007
|
|
$
|
604
|
|
Customer
growth and lower natural gas usage
|
|
|
(4
|
)
|
Revision
in estimated unbilled natural gas volumes at Elizabethtown
Gas
|
|
|
(3
|
)
|
Lower
natural gas storage carrying costs at Atlanta Gas Light
|
|
|
(2
|
)
|
Higher
PRP revenues at Atlanta Gas Light
|
|
|
4
|
|
Operating
margin for the first nine months of 2008
|
|
$
|
599
|
|
Retail
energy operations’ operating margin decreased by $44 million or 30%. The
following table indicates the significant changes in retail energy operations’
operating margin for the nine months ended September 30, 2008 compared to
2007.
In
millions
|
|
|
|
Operating
margin for the first nine months of 2007
|
|
$
|
145
|
|
Lower
contributions from the management of storage and transportation assets
largely due to rising commodity prices in 2008
|
|
|
(15
|
)
|
Inventory
LOCOM adjustment
|
|
|
(18
|
)
|
Retail
pricing settlement with Georgia Commission
|
|
|
(3
|
)
|
Colder
weather
|
|
|
5
|
|
Lower
number of customers and usage
|
|
|
(3
|
)
|
Ohio
and Florida margins
|
|
|
(2
|
)
|
Loss
on weather derivatives
|
|
|
(7
|
)
|
Other
|
|
|
(1
|
)
|
Operating
margin for the first nine months of 2008
|
|
$
|
101
|
|
Wholesale
services’ operating margin increased $17 million or 37% compared to the first
nine months of 2007 primarily due to stronger commercial activity and gains on
the instruments used to hedge its storage positions resulting from falling
natural gas prices. These gains were partially offset by a $34 million LOCOM
adjustment in the current period as compared to a $2 million LOCOM adjustment
(net of hedging recoveries) last year. The following table indicates the
significant changes in wholesale services’ operating margin for the nine months
ended September 30, 2008 and 2007.
In
millions
|
|
2008
|
|
|
2007
|
|
Commercial
activity
|
|
$
|
50
|
|
|
$
|
31
|
|
Gain
on storage hedges
|
|
|
46
|
|
|
|
15
|
|
Gain
on transportation hedges
|
|
|
1
|
|
|
|
2
|
|
Inventory
LOCOM, net of hedging recoveries
|
|
|
(34
|
)
|
|
|
(2
|
)
|
Operating
margin
|
|
$
|
63
|
|
|
$
|
46
|
|
The
increase of $30 million in gains associated with storage and transportation
hedge positions was primarily due to larger decreases in forward NYMEX prices
during the current period compared to those experienced in 2007. For more
information on Sequent’s expected operating revenues from its storage inventory
in the remainder of 2008 and in 2009 and discussion of the increased commercial
activity as compared to last year, see the description of wholesale services’
business in this section beginning on page 21.
Energy
investments’ operating margin increased $12 million or 44% primarily due to
higher operating margins at AGL Networks of $10 million due to a network
expansion project and $2 million at Jefferson Island as a result of increased
interruptible operating margins.
Operating
Expenses
Our operating expenses for the nine months ended September 30,
2008, increased $9 million or 2% as compared to the same period of 2007. The
following table indicates the significant changes in our operating
expenses.
In
millions
|
|
|
|
|
Operating
expenses for the first nine months of 2007
|
|
$
|
473
|
|
Increased
operating costs at wholesale services due to continued commercial
expansion and incentive compensation costs associated with
earnings
|
|
|
11
|
|
Increased
depreciation expenses at distribution operations due to PP&E placed
into service
|
|
|
5
|
|
Increased
bad debt expenses primarily at Elizabethtown Gas and Virginia Natural Gas
in distribution operations due to higher natural gas prices and decline in
the economy
|
|
|
5
|
|
Increased
bad debt expenses at retail energy operations due to higher natural gas
prices
|
|
|
2
|
|
Increased
operating costs due to AGL Networks expansion project
|
|
|
2
|
|
Decreased
operating costs at retail energy operations due to lower compensation,
marketing, outside services and other costs
|
|
|
(3
|
)
|
Decreased
operating costs at distribution operations due to lower costs related to
benefits and incentives, marketing, customer service and outside services
offset by higher fuel costs and property taxes
|
|
|
(8
|
)
|
Decreased
pension expenses at distribution operations primarily due to updated
actuarial expense estimate
|
|
|
(4
|
)
|
Lower
corporate costs
|
|
|
(1
|
)
|
Operating
expenses for the first nine months of 2008
|
|
$
|
482
|
|
Interest Expense
The decrease in interest expense of
$7
million or 8% for the nine months ended September 30, 2008, was primarily due to
the decrease in short-term interest rates partially offset by higher average
debt outstanding as indicated in the following table.
|
|
Nine
months ended September 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Average
debt outstanding (1)
|
|
$
|
2,046
|
|
|
$
|
1,899
|
|
|
$
|
147
|
|
Average
rate
|
|
|
5.5
|
%
|
|
|
6.2
|
%
|
|
|
(0.7
|
)%
|
(1) Daily
average of all outstanding debt.
Our
primary sources of liquidity are cash provided by operating activities, short
term borrowings under our commercial paper program (which is supported by our
Credit Facilities) and borrowings under lines of credit. Additionally from time
to time, we raise funds from the public debt and equity capital markets through
our existing shelf registration statement to fund our liquidity and capital
resource needs. We believe these sources will continue to allow us to meet our
needs for working capital, construction expenditures, anticipated debt
redemptions, interest payments on debt obligations, dividend payments, common
share repurchases and other cash needs.
Our
issuance of various securities, including long-term and short-term debt, is
subject to customary approval or authorization by state and federal regulatory
bodies including state public service commissions and the SEC. Furthermore,
a substantial portion of our consolidated assets, earnings and cash flow is
derived from the operation of our regulated utility subsidiaries, whose legal
authority to pay dividends or make other distributions to us is subject to
regulation.
We will continue to evaluate our need
to increase available liquidity based on our view of working capital
requirements, including the impact of changes in natural gas prices, liquidity
requirements established by rating agencies and other factors. See Item 1A,
“Risk Factors,” of our Annual Report on Form 10-K for the year ended December
31, 2007, for additional information on items that could impact our liquidity
and capital resource requirements. The following table provides a summary of our
operating, investing and financing activities.
|
|
Nine
months ended Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Net
cash provided by (used in):
|
|
|
|
|
|
|
Operating
activities
|
|
$
|
172
|
|
|
$
|
386
|
|
Investing
activities
|
|
|
(254
|
)
|
|
|
(191
|
)
|
Financing
activities
|
|
|
74
|
|
|
|
(198
|
)
|
Net
decrease in cash and cash equivalents
|
|
$
|
(8
|
)
|
|
$
|
(3
|
)
|
Cash Flow from
Operating Activities
In the first nine months of 2008, our net cash flow
provided from operating activities was $172 million, a decrease of $214 million
or 55% from the same period in 2007. This was primarily a result of increased
working capital requirements, principally driven by rising natural gas prices
during the first half of 2008. In addition, as a result of the increase in
natural gas prices, our margin requirements for our energy marketing and risk
management activities were higher than in the prior year which included
approximately $114 million of cash received upon settlement of derivative
positions versus $58 million in the current period.
Cash Flow from
Investing Activities
Our investing activities consisted of PP&E
expenditures of $254 million for the nine months ended September 30, 2008 and
$193 million for the same period in 2007. The increase of $61 million or 32% in
PP&E expenditures was primarily due to a $51 million increase at
distribution operations, which included higher spending for the pipeline
replacement program and expenditures for Virginia Natural Gas’ Hampton Roads
pipeline project connecting its northern and southern systems.
Additionally,
our retail energy operations’ PP&E expenditures increased $4 million as a
result of its purchase of information technology assets in support of its
transition to a new customer care and call center vendor. Our energy
investments’ PP&E expenditures increased $26 million primarily from
increased expenditures at Golden Triangle Storage as we began construction on
our planned natural gas storage facility and from increased telecommunication
expenditures at AGL Networks on its Phoenix network expansion. These PP&E
expenditure increases were partially offset by decreased expenditures at our
corporate segment of $19 million primarily due to decreased spending primarily
on information technology.
Cash Flow from
Financing Activities
Our financing activities are primarily composed of
borrowings and payments of short-term debt, payments of medium-term notes,
borrowings of senior notes, distributions to minority interests, cash dividends
on our common stock issuances, and purchases and issuances of treasury shares.
Our capitalization and financing strategy is intended to ensure that we are
properly capitalized with the appropriate mix of equity and debt securities.
This strategy includes active management of the percentage of total debt
relative to total capitalization, appropriate mix of debt with fixed to floating
interest rates (our variable-rate debt target is 20% to 45% of total debt), as
well as the term and interest rate profile of our debt securities. As of
September 30, 2008, our variable-rate debt was 38% of our total debt, compared
to 39% as of September 30, 2007.
We also
work to maintain or improve our credit ratings to manage our existing financing
costs effectively and enhance our ability to raise additional capital on
favorable terms. Factors we consider important in assessing our credit ratings
include our balance sheet leverage, capital spending, earnings, cash flow
generation, available liquidity and overall business risks. We do not have any
trigger events in our debt instruments that are tied to changes in our specified
credit ratings or our stock price and have not entered into any agreements that
would require us to issue equity based on credit ratings or other trigger
events. The following table summarizes our credit ratings as of September 30,
2008, and reflects no change from December 31, 2007.
|
|
S&P
|
|
|
Moody’s
|
|
|
Fitch
|
|
Corporate
rating
|
|
A-
|
|
|
|
|
|
|
|
Commercial
paper
|
|
A-2
|
|
|
P-2
|
|
|
F-2
|
|
Senior
unsecured
|
|
BBB+
|
|
|
Baa1
|
|
|
A-
|
|
Ratings
outlook
|
|
Stable
|
|
|
Stable
|
|
|
Stable
|
|
A credit
rating is not a recommendation to buy, sell or hold securities. The highest
investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is
AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is
Baa3 and Fitch is BBB-. Our credit ratings may be subject to revision or
withdrawal at any time by the assigning rating organization, and each rating
should be evaluated independently of any other rating. We cannot ensure that a
rating will remain in effect for any given period of time or that a rating will
not be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances so warrant. If the rating agencies downgrade our ratings,
particularly below investment grade, it may significantly limit our access to
the commercial paper market and our borrowing costs would increase. In addition,
we would likely be required to pay a higher interest rate in future financings,
and our potential pool of investors and funding sources would
decrease.
Our debt
instruments and other financial obligations include provisions that, if not
complied with, could require early payment, additional collateral support or
similar actions. Our most important default events include maintaining covenants
with respect to a maximum leverage ratio, insolvency events, nonpayment of
scheduled principal or interest payments, and acceleration of other financial
obligations and change of control provisions. Our Credit Facility’s financial
covenant requires us to maintain a ratio of total debt to total capitalization
of no greater than 70%; however, our goal is to maintain this ratio at levels
between 50% and 60%. Our ratio of total debt to total capitalization calculation
contained in our debt covenant includes minority interest, standby letters of
credit, surety bonds and the exclusion of other comprehensive income pension
adjustments. If these items were included, our debt-to-equity calculation would
increase by 1-2%. Our debt and equity capitalization ratios, as of the dates
indicated, are summarized in the following table.
|
|
Sept.
30, 2008
|
|
|
Dec.
31, 2007
|
|
|
Sept.
30, 2007
|
|
Short-term
debt
|
|
|
19
|
%
|
|
|
15
|
%
|
|
|
15
|
%
|
Long-term
debt
|
|
|
40
|
|
|
|
43
|
|
|
|
42
|
|
Total
debt
|
|
|
59
|
|
|
|
58
|
|
|
|
57
|
|
Common
shareholders’ equity
|
|
|
41
|
|
|
|
42
|
|
|
|
43
|
|
Total
capitalization
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
We
believe that accomplishing our capitalization objectives and maintaining
sufficient cash flow are necessary to maintain our investment-grade credit
ratings and to allow us access to capital at reasonable costs. We currently
comply with all existing debt provisions and covenants. For more information on
our debt, see
Note 5
“Debt.”
Short-term debt
Our
short-term debt is composed of borrowings under our commercial paper program,
Credit Facilities, lines of credit at Sequent, SouthStar and Pivotal Utility,
and the current portion of our capital leases. In June 2008, we extended one of
Sequent’s lines of credit to June 2009. In September 2008, Sequent obtained a
second line of credit for $20 million that bears interest at the LIBOR Rate plus
1.0% to September 2009. This line of credit replaced the line of credit that
expired in August 2008. Both lines of credit are used for the posting of margin
deposits for NYMEX transactions and are unconditionally guaranteed by
us.
In
September 2008, we completed a $140 million Credit Facility that expires in
September 2009, which will provide additional liquidity for working capital and
capital expenditure needs. This $140 million Credit Facility allows for the
option to request an increase in the borrowing capacity to $150 million and
supplements our existing $1.0 billion Credit Facility which expires in August
2011. More information on our short-term debt as of September 30, 2008, which we
consider one of our primary sources of liquidity, is presented in the following
table:
In
millions
|
|
Capacity
|
|
|
Outstanding
|
|
Credit Facilities
(1)
|
|
$
|
1,140
|
|
|
$
|
683
|
|
SouthStar
line of credit
|
|
|
75
|
|
|
|
55
|
|
Sequent
lines of credit
|
|
|
45
|
|
|
|
20
|
|
Pivotal
Utility line of credit
|
|
|
20
|
|
|
|
10
|
|
Total
|
|
$
|
1,280
|
|
|
$
|
768
|
|
(1)
|
Supported
by our $1.0 billion and $140 million Credit Facilities, and
includes
$198 million of commercial paper
borrowings.
|
Our
short-term debt financing generally increases between June and December because
our payments for natural gas and pipeline capacity are generally made to
suppliers prior to the collection of accounts receivable from our customers. We
typically reduce short-term debt balances in the spring because a significant
portion of our current assets are converted into cash at the end of the heating
season. As of September 30, 2008, our outstanding short-term borrowings
increased by $193 million or 34% as compared to the same time last year,
primarily a result of increased working capital requirements, primarily for the
higher cost of natural gas inventories and increased PP&E expenditures of
$61 million.
As of
September 30, 2008 we had $485 million outstanding under our $1.0 billion Credit
Facility. In the third quarter 2008 due to disruption in the credit markets, we
were unable to issue commercial paper at acceptable interest rates and relied
upon our Credit Facility for our liquidity and capital resource needs. We expect
to repay the amounts outstanding under our Credit Facility with commercial paper
borrowings. As of September 30, 2007 and December 31, 2007, we had no
outstanding borrowings under the Credit Facility. Our exposure to financial
institutions that experienced difficulty during the disruption in the credit
markets was limited.
The
availability of borrowings and unused availability under our Credit Facilities
is limited and subject to conditions specified within the Credit Facilities,
which we currently meet. These conditions include:
·
|
the
maintenance of a ratio of total debt to total capitalization of no greater
than 70%; however, our goal is to maintain this ratio at levels between
50% and 60%. As of September 30, 2008, our ratio of total debt of 59% to
total capitalization was within our targeted and required
ranges
|
·
|
the
continued accuracy of representations and warranties contained in the
agreement
|
Long-term debt
Our long-term
debt matures more than one year from the balance sheet date and consists of
medium-term notes, senior notes, gas facility revenue bonds, and capital
leases.
In 2008,
a portion of our gas facility revenue bonds failed to draw enough potential
buyers due to the dislocation or disruption in the auction markets as a result
of the downgrades to the bond insurers which reduced investor demand and
liquidity for these types of investments. Three of these bonds with principal
amounts of $55 million, $47 million and $20 million had interest rates that were
adjusted every 35-days, and one of the bonds with a principal amount of $39
million had an interest rate which was reset daily. In March and April 2008, we
tendered these bonds with a cumulative principal amount of $161 million through
commercial paper borrowings.
In June
and September 2008, we completed Letter of Credit Agreements for these bonds
which provided credit support and enhanced investor demand. As a result, these
bonds were successfully issued as variable rate gas facility revenue bonds and
reduced our commercial paper borrowings. The bonds with principal amounts of $55
million, $47 million and $39 million now have interest rates that reset daily
and the bond with a principal amount of $20 million has an interest rate that
resets weekly. There was no change to the maturity dates on these bonds.
Currently, these bonds have potential buyers; however, should these bonds fail
to draw buyers, we would be required to either draw on the Letter of Credit
Agreements or tender these bonds with commercial paper. For more information on
the maturity of the gas facility revenue bonds see Note 6 to our Consolidated
Financial Statements in Item 8 of our Annual Report on Form 10-K for the year
ended December 31, 2007.
Share repurchases
In February
2006, our Board of Directors authorized a plan to purchase up to 8 million
shares of our outstanding common stock over a five-year period. For the nine
months ended September 30, 2008, we did not purchase any shares of our common
stock under this plan. During the same period in 2007, we purchased
approximately 1.4 million shares of our common stock at a weighted average cost
of $39.82 per share and an aggregate cost of $57 million. We hold the purchased
shares as treasury shares.
Contractual
Obligations and Commitments
We have incurred various contractual
obligations and financial commitments in the normal course of our operating and
financing activities. Contractual obligations include future cash payments
required under existing contractual arrangements, such as debt and lease
agreements. These obligations may result from both general financing activities
and from commercial arrangements that are directly supported by related revenue
producing activities. We also have incurred various financial commitments in the
normal course of business. Contingent financial commitments represent
obligations that become payable only if certain predefined events occur, such as
financial guarantees, and include the nature of the guarantee and the maximum
potential amount of future payments that could be required of us as the
guarantor.
In recent
months, declines in the investment markets have negatively impacted our pension
plan assets. In order to comply with the funding requirements from the Pension
Protection Act of 2006, we anticipate that we will be required to make a
contribution to our pension plan in 2009. The decline in investment values could
also result in a charge to other comprehensive income for the increased
difference between investment values and the pension liabilities at our next
measurement date of December 31, 2008, as well as an increase in the amount of
pension expense we would recognize in 2009 and beyond. We are currently unable
to determine these amounts since actual asset performance through the end of the
year and the discount rate at year-end can significantly impact the
determination of these amounts. The following tables illustrate our expected
future contractual obligations and commitments as of September 30,
2008.
|
|
|
|
|
|
|
|
2009
&
|
|
|
2011
&
|
|
|
2013
&
|
|
In
millions
|
|
Total
|
|
|
2008
|
|
|
2010
|
|
|
2012
|
|
|
thereafter
|
|
Recorded
contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$
|
1,675
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
315
|
|
|
$
|
1,356
|
|
Short-term
debt
|
|
|
769
|
|
|
|
769
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
PRP costs
(1)
|
|
|
195
|
|
|
|
7
|
|
|
|
102
|
|
|
|
63
|
|
|
|
23
|
|
Environmental remediation
liabilities
(1)
|
|
|
105
|
|
|
|
3
|
|
|
|
34
|
|
|
|
39
|
|
|
|
29
|
|
Total
|
|
$
|
2,744
|
|
|
$
|
780
|
|
|
$
|
139
|
|
|
$
|
417
|
|
|
$
|
1,408
|
|
(1)
|
Includes
charges recoverable through rate rider
mechanisms.
|
|
|
|
|
|
|
|
|
2009
&
|
|
|
2011
&
|
|
|
2013
&
|
|
In
millions
|
|
Total
|
|
|
2008
|
|
|
2010
|
|
|
2012
|
|
|
thereafter
|
|
Unrecorded
contractual obligations and commitments
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline charges, storage
capacity and gas supply
(2)
|
|
$
|
1,751
|
|
|
$
|
164
|
|
|
$
|
736
|
|
|
$
|
402
|
|
|
$
|
449
|
|
Interest
charges
(3)
|
|
|
1,135
|
|
|
|
26
|
|
|
|
204
|
|
|
|
161
|
|
|
|
744
|
|
Operating
leases
|
|
|
136
|
|
|
|
7
|
|
|
|
50
|
|
|
|
34
|
|
|
|
45
|
|
Standby
letters of credit, performance / surety bonds
|
|
|
48
|
|
|
|
8
|
|
|
|
40
|
|
|
|
-
|
|
|
|
-
|
|
Asset management
agreements
(4)
|
|
|
43
|
|
|
|
3
|
|
|
|
24
|
|
|
|
16
|
|
|
|
-
|
|
Total
|
|
$
|
3,113
|
|
|
$
|
208
|
|
|
$
|
1,054
|
|
|
$
|
613
|
|
|
$
|
1,238
|
|
(1)
|
In
accordance with generally accepted accounting principles, these items are
not reflected in our condensed consolidated balance
sheet.
|
(2)
|
Charges
recoverable through a PGA mechanism or alternatively billed to Marketers.
Also includes SouthStar’s gas commodity purchase commitments of 11.6 Bcf
at floating gas prices calculated using forward natural gas prices as of
September 30, 2008, and valued at $90 million. Additionally, includes
amounts associated with a subsidiary of NUI which entered into two
long-term agreements for the firm transportation and storage of natural
gas during 2003 with annual aggregate demand charges of approximately $5
million. As a result of our acquisition of NUI and in accordance with SFAS
141, we valued the contracts at fair value and established a long-term
liability of $38 million for the excess liability. This excess liability
is being amortized to our condensed consolidated statements of income over
the remaining lives of the contracts of $2 million annually through
November 2023 and $1 million annually from November 2023 to November
2028.
|
(3)
|
Floating
rate debt is based on the interest rate as of September 30, 2008, and the
maturity of the underlying debt instrument. As of September 30, 2008, we
have $32 million of accrued interest on our condensed consolidated balance
sheet.
|
(4)
|
Represent
fixed-fee or guaranteed minimum payments for Sequent’s asset management
agreements between its affiliated
utilities.
|
The
preparation of our financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses and the related disclosures of contingent assets and liabilities. We
base our estimates on historical experience and various other assumptions that
we believe to be reasonable under the circumstances. We evaluate our estimates
on an ongoing basis, and our actual results may differ from these estimates. Our
critical accounting policies used in the preparation of our condensed
consolidated financial statements include the following:
·
|
Pipeline
Replacement Program
|
·
|
Environmental
Remediation Liabilities
|
·
|
Derivatives
and Hedging Activities
|
·
|
Allowance
for Uncollectible Accounts and other
Contingencies
|
·
|
Pension
and Other Postretirement Plans
|
Each of
our critical accounting policies and estimates involves complex situations
requiring a high degree of judgment either in the application and interpretation
of existing literature or in the development of estimates that impact our
financial statements. There have been no significant changes to our critical
accounting policies from those disclosed in our Annual Report on Form 10-K for
the year ended December 31, 2007.
Previously
discussed
SFAS 160
In December 2007, the FASB issued SFAS 160, which is effective for fiscal years
beginning after December 15, 2008. SFAS 160 will require us to present our
minority interest, to be referred to as a noncontrolling interest, separately
within the capitalization section of our consolidated balance sheets. We will
adopt SFAS 160 on January 1, 2009.
SFAS
161
In March 2008, the
FASB issued SFAS 161, which is effective for fiscal years beginning after
November 15, 2008. SFAS 161 amends the disclosure requirements of SFAS 133 to
provide an enhanced understanding of how and why derivative instruments are
used, how they are accounted for and their effect on an entity’s financial
condition, performance and cash flows. We will adopt SFAS 161 on January 1, 2009
which will require additional disclosures, but will not have a financial impact
to our consolidated results of operations, cash flows or financial
condition
.
FSP EITF
03-6-1
The FASB issued this FSP in June 2008 and is effective for fiscal
years beginning after December 15, 2008. This FSP classifies unvested
share-based payment grants containing nonforfeitable rights to dividends as
participating securities that will be included in the computation of earnings
per share. As of September 30, 2008, we had approximately 149,000 restricted
shares with nonforfeitable dividend rights, which potentially could be included
in our basic earnings per share calculation. We will adopt FSP EITF 03-6-1 on
January 1, 2009.
Recently
issued
FSP FAS
133-1
The FASB issued this FSP in September 2008 and it is effective for
fiscal years beginning after November 15, 2008. This FSP requires more detailed
disclosures about credit derivatives, including the potential adverse effects of
changes in credit risk on the financial position, financial performance and cash
flows of the sellers of the instruments. This FSP will have no financial impact
to our consolidated results of operations, cash flows or financial condition. We
will adopt FSP FAS 133-1 on January 1, 2009.
FSP FAS
157-3
The FASB issued this FSP in October 2008 and it is effective upon
issuance including prior periods for which financial statements have not been
issued. This FSP clarifies the application of SFAS 157 in an inactive market,
including; how internal assumptions should be considered when measuring fair
value, how observable market information in a market that is not active should
be considered and how the use of market quotes should be used when assessing
observable and unobservable data. We adopted this FSP as of September 30, 2008,
which had no financial impact to our consolidated results of operations, cash
flows or financial condition.
About
Market Risk
We are
exposed to risks associated with commodity prices, interest rates and credit.
Commodity price risk is defined as the potential loss that we may incur as a
result of changes in the fair value of natural gas. Interest rate risk results
from our portfolio of debt and equity instruments that we issue to provide
financing and liquidity for our business. Credit risk results from the extension
of credit throughout all aspects of our business but is particularly
concentrated at Atlanta Gas Light in distribution operations and in wholesale
services.
Commodity
Price Risk
Retail Energy
Operations
SouthStar’s use of derivatives is governed by a risk
management policy, approved and monitored by its Risk and Asset Management
Committee, which prohibits the use of derivatives for speculative
purposes.
Energy marketing and risk management
assets and liabilities
SouthStar routinely utilizes various types of
financial and other instruments to mitigate certain commodity price and weather
risk inherent in the natural gas industry. These instruments include a variety
of exchange-traded and OTC energy contracts, such as forward contracts, futures
contracts, options contracts and financial swap agreements.
We have
designated a portion of SouthStar’s derivative transactions as cash flow hedges
in accordance with SFAS 133. We record derivative gains or losses arising from
cash flow hedges in OCI and reclassify them into earnings in the same period as
the underlying hedged item occurs and is recorded in earnings. We record any
hedge ineffectiveness, defined as when the gains or losses on the hedging
instrument do not offset and are greater than the losses or gains on the hedged
item, in cost of gas in our condensed consolidated statement of income in the
period in which the ineffectiveness occurs. SouthStar currently has minimal
hedge ineffectiveness. We have not designated the remainder of SouthStar’s
derivative instruments as hedges under SFAS 133 and, accordingly we record
changes in their fair value in earnings in the period of change.
SouthStar
experienced an increase of $2 million in the net fair value of derivative
instruments utilized in its energy marketing and risk management activities in
the first nine months of 2008 compared to $6 million decrease for the same
period last year. The following tables illustrate the change in the net fair
value of the derivative instruments and energy-trading contracts during the
three and nine months ended September 30, 2008 and 2007, and provide details of
the net fair value of contracts outstanding as of September 30,
2008.
|
Three
months ended Sept. 30,
|
In
millions
|
|
2008
|
|
|
2007
|
|
Net
fair value of contracts outstanding at beginning of period
|
|
$
|
8
|
|
|
$
|
3
|
|
Contracts
realized or otherwise settled during period
|
|
|
6
|
|
|
|
6
|
|
Change
in net fair value of contracts
|
|
|
(2
|
)
|
|
|
2
|
|
Net
fair value of contracts outstanding at end of period
|
|
|
12
|
|
|
|
11
|
|
Netting
of cash collateral
|
|
|
20
|
|
|
|
10
|
|
Cash
collateral and net fair value of contracts outstanding at end of
period
|
|
$
|
32
|
|
|
$
|
21
|
|
|
|
Nine
months ended Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Net
fair value of contracts outstanding at beginning of period
|
|
$
|
10
|
|
|
$
|
17
|
|
Contracts
realized or otherwise settled during period
|
|
|
(10
|
)
|
|
|
(15
|
)
|
Change
in net fair value of contracts
|
|
|
12
|
|
|
|
9
|
|
Net
fair value of contracts outstanding at end of period
|
|
|
12
|
|
|
|
11
|
|
Netting
of cash collateral
|
|
|
20
|
|
|
|
10
|
|
Cash
collateral and net fair value of contracts outstanding at end of
period
|
|
$
|
32
|
|
|
$
|
21
|
|
The
sources of SouthStar’s net fair value at September 30, 2008, are as
follows:
In
millions
|
|
Prices
actively quoted
(1)
|
|
|
Prices
provided by other external sources
|
|
Mature
through 2008
|
|
$
|
8
|
|
|
$
|
(1
|
)
|
Mature
through 2009
|
|
|
4
|
|
|
|
-
|
|
Mature
through 2010
|
|
|
1
|
|
|
|
-
|
|
(1)
|
Valued
using NYMEX futures prices.
|
The
following tables include the cash collateral fair values and average values of
SouthStar’s energy marketing and risk management assets and liabilities as of
September 30, 2008, December 31, 2007 and September 30, 2007. SouthStar bases
the average values on monthly averages for the nine months ended September 30,
2008 and 2007.
|
|
Average
values at Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Asset
(1)
|
|
$
|
13
|
|
|
$
|
10
|
|
Liability
(1)
|
|
|
5
|
|
|
|
4
|
|
(1)
Average values represent only the derivative instruments and excludes netting of
cash collateral amounts.
|
|
Cash
collateral and fair values at
|
|
In
millions
|
|
Sept.
30,
2008
|
|
|
Dec.
31,
2007
|
|
|
Sept.
30,
2007
|
|
Asset
|
|
$
|
33
|
|
|
$
|
13
|
|
|
$
|
21
|
|
Liability
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
Value at Risk
A 95%
confidence interval is used to evaluate VaR exposure. A 95% confidence interval
means that over the holding period, an actual loss in portfolio value is not
expected to exceed the calculated VaR more than 5% of the time. We calculate VaR
based on the variance-covariance technique. This technique requires several
assumptions for the basis of the calculation, such as price distribution, price
volatility, confidence interval and holding period. Our VaR may not be
comparable to a similarly titled measure of another company because, although
VaR is a common metric in the energy industry, there is no established industry
standard for calculating VaR or for the assumptions underlying such
calculations. SouthStar’s portfolio of positions for the three months ended
September 30, 2008 and 2007, had quarterly average 1-day holding period VaRs of
less than $100,000 and its high, low and period end 1-day holding period VaR
were immaterial.
Wholesale
Services
Sequent routinely utilizes various types of financial and other
instruments to mitigate certain commodity price risks inherent in the natural
gas industry. These instruments include a variety of exchange-traded and OTC
energy contracts, such as forward contracts, futures contracts, options
contracts and financial swap agreements.
Energy marketing and risk management
assets and liabilities
The following tables include the cash collateral,
fair values and average values of Sequent’s energy marketing and risk management
assets and liabilities as of September 30, 2008, December 31, 2007 and September
30, 2007. Sequent bases the average values on monthly averages for the nine
months ended September 30, 2008 and 2007.
|
|
Average
values at Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Asset
(1)
|
|
$
|
72
|
|
|
$
|
61
|
|
Liability
(1)
|
|
|
48
|
|
|
|
17
|
|
(1)
Average values represent only the derivative instruments and excludes netting of
cash collateral amounts.
|
|
Cash
collateral and fair values at
|
|
In
millions
|
|
Sept.
30,
2008
|
|
|
Dec.
31,
2007
|
|
|
Sept.
30,
2007
|
|
Asset
|
|
$
|
140
|
|
|
$
|
61
|
|
|
$
|
68
|
|
Liability
|
|
|
24
|
|
|
|
13
|
|
|
|
7
|
|
At
September 30, 2008, Sequent’s commodity-related derivative financial instruments
represented purchases (long) of 708 Bcf and sales (short) of 697 Bcf, with
approximately 90% and 94% scheduled to mature in less than two years and the
remaining 10% and 6% in three to nine years, respectively.
Sequent
experienced a change in the net fair value of its outstanding contracts of $26
million during the first nine months of 2008 compared to a $59 million decrease
during the same period last year due to changes in the fair value of derivative
instruments utilized in its energy marketing and risk management activities and
contract settlements.
The
following tables illustrate the change in the net fair value of Sequent’s
derivative instruments and energy trading contracts during the three and nine
months ended September 30, 2008 and 2007, and provide details of the net fair
value of contracts outstanding as of September 30, 2008.
|
|
Three
months ended Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Net
fair value of contracts outstanding at beginning of period
|
|
$
|
(96
|
)
|
|
$
|
51
|
|
Contracts
realized or otherwise settled during period
|
|
|
60
|
|
|
|
(17
|
)
|
Change
in net fair value of contracts
|
|
|
119
|
|
|
|
26
|
|
Net
fair value of contracts outstanding at end of period
|
|
|
83
|
|
|
|
60
|
|
Netting
of cash collateral
|
|
|
33
|
|
|
|
1
|
|
Cash
collateral and net fair value of contracts outstanding at end of
period
|
|
$
|
116
|
|
|
$
|
61
|
|
|
|
Nine
months ended Sept. 30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
Net
fair value of contracts outstanding at beginning of period
|
|
$
|
57
|
|
|
$
|
119
|
|
Contracts
realized or otherwise settled during period
|
|
|
(48
|
)
|
|
|
(99
|
)
|
Change
in net fair value of contracts
|
|
|
74
|
|
|
|
40
|
|
Net
fair value of contracts outstanding at end of period
|
|
|
83
|
|
|
|
60
|
|
Netting
of cash collateral
|
|
|
33
|
|
|
|
1
|
|
Cash
collateral and net fair value of contracts outstanding at end of
period
|
|
$
|
116
|
|
|
$
|
61
|
|
The
sources of Sequent’s net fair value at September 30, 2008, are as
follows:
In
millions
|
|
Prices
actively quoted
(1)
|
|
|
Prices
provided by other external sources
(2)
|
|
Mature
through 2008
|
|
$
|
27
|
|
|
$
|
56
|
|
Mature
2009 – 2010
|
|
|
(11
|
)
|
|
|
9
|
|
Mature
2011 – 2013
|
|
|
-
|
|
|
|
2
|
|
Total
net fair value
|
|
$
|
16
|
|
|
$
|
67
|
|
(1)
|
Valued
using NYMEX futures prices and other quoted
sources.
|
(2)
|
Valued
using basis transactions that represent the cost to transport the
commodity
from
a NYMEX delivery point to the contract delivery point. These transactions
are
based
on quotes obtained either through electronic trading platforms or directly
from brokers.
|
Due to
the $62 million lower net fair value of contracts outstanding at the beginning
of the year in 2008 as compared to the prior period, the amount of contracts
that were realized or otherwise settled by Sequent during the nine months ended
September 30, 2008 decreased by $51 million as compared to 2007. Additionally,
as a result of decreases in forward natural gas prices during the nine months
ended September 30, 2008, compared to the prior year’s more modest price
declines, the change in fair value was an increase of $34 million. These changes
resulted in the net fair value of its contracts being $23 million more than last
year.
Value at Risk
Sequent’s open
exposure is managed in accordance with established policies that limit market
risk and require daily reporting of potential financial exposure to senior
management, including the chief risk officer. Because Sequent generally manages
physical gas assets and economically protects its positions by hedging in the
futures markets, its open exposure is generally immaterial, permitting Sequent
to operate within relatively low VaR limits. Sequent employs daily risk testing,
using both VaR and stress testing, to evaluate the risks of its open
positions.
Sequent’s
management actively monitors open commodity positions and the resulting VaR.
Sequent continues to maintain a relatively matched book, where its total buy
volume is close to sell volume with minimal open commodity risk. Based on a 95%
confidence interval and employing a 1-day holding period for all positions,
Sequent’s portfolio of positions for the three and nine months ended September
30, 2008 and 2007 had the following VaRs.
|
|
Three
months ended September 30,
|
|
|
Nine
months ended September 30,
|
|
In
millions
|
|
|
2008
|
|
|
|
2007
|
|
|
|
2008
|
|
|
|
2007
|
|
Period
end
|
|
$
|
1.9
|
|
|
$
|
1.0
|
|
|
$
|
1.9
|
|
|
$
|
1.0
|
|
Average
|
|
|
1.8
|
|
|
|
1.4
|
|
|
|
1.7
|
|
|
|
1.4
|
|
High
|
|
|
2.4
|
|
|
|
2.3
|
|
|
|
2.9
|
|
|
|
2.3
|
|
Low
|
|
|
1.0
|
|
|
|
0.9
|
|
|
|
0.8
|
|
|
|
0.9
|
|
Interest
Rate Risk
Interest
rate fluctuations expose our variable-rate debt to changes in interest expense
and cash flows. Our policy is to manage interest expense using a combination of
fixed-rate and variable-rate debt. Based on $929 million of variable-rate debt,
which includes $768 million of our variable-rate short-term debt and $161
million of variable-rate gas facility revenue bonds outstanding at September 30,
2008, a 100 basis point change in market interest rates from 4.06% to 5.06%
would have resulted in an increase in pretax interest expense of $9 million on
an annualized basis.
At the
beginning of 2008, we had a notional principal amount of $100 million of
interest rate swap agreements associated with our senior notes. In March 2008,
we terminated these interest rate swap agreements. We received a payment of $2
million, which included accrued interest and the fair value of the interest rate
swap agreements at the termination date which was recorded as a liability in our
condensed consolidated balance sheets and will be amortized through January
2011, which is the remaining life of the associated senior notes.
Credit
Risk
Wholesale
Services
Sequent has established credit policies to determine and monitor
the creditworthiness of counterparties, as well as the quality of pledged
collateral. Sequent also utilizes master netting agreements whenever possible to
mitigate exposure to counterparty credit risk. When Sequent is engaged in more
than one outstanding derivative transaction with the same counterparty and it
has a legally enforceable netting agreement with that counterparty, the “net”
mark-to-market exposure represents the netting of the positive and negative
exposures with that counterparty and a reasonable measure of Sequent’s credit
risk. Sequent also uses other netting agreements with certain counterparties
with whom it conducts significant transactions. Master netting agreements enable
Sequent to net certain assets and liabilities by counterparty. Sequent also nets
across product lines and against cash collateral provided the master netting and
cash collateral agreements include such provisions.
Additionally,
Sequent may require counterparties to pledge additional collateral when deemed
necessary. Sequent conducts credit evaluations and obtains appropriate internal
approvals for its counterparty’s line of credit before any transaction with the
counterparty is executed. In most cases, the counterparty must have a minimum
long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally,
Sequent requires credit enhancements by way of guaranty, cash deposit or letter
of credit for counterparties that do not meet the minimum long-term debt rating
threshold.
Sequent,
which provides services to marketers and utility and industrial customers, also
has a concentration of credit risk as measured by its 30-day receivable exposure
plus forward exposure. As of September 30, 2008, Sequent’s top 20 counterparties
represented approximately 60% of the total counterparty exposure of $425
million, derived by adding together the top 20 counterparties’ exposures and
dividing by the total of Sequent’s counterparties’ exposures.
As of
September 30, 2008, Sequent’s counterparties, or the counterparties’ guarantors,
had a weighted-average S&P equivalent credit rating of A-, which is
consistent with the rating at December 31, 2007 and September 30, 2007. The
S&P equivalent credit rating is determined by a process of converting the
lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to
1, with 9 being the equivalent to AAA/Aaa by S&P and Moody’s and 1 being D
or Default by S&P and Moody’s. A counterparty that does not have an external
rating is assigned an internal rating based on the strength of the financial
ratios for that counterparty. To arrive at the weighted average credit rating,
each counterparty’s assigned internal ratio is multiplied by the counterparty’s
credit exposure and summed for all counterparties. The sum is divided by the
aggregate total counterparties’ exposures, and this numeric value is then
converted to an S&P equivalent. There were no credit defaults with Sequent’s
counterparties as a result of the disruption in the credit markets.
The
following table shows Sequent’s third-party commodity receivable and payable
positions as of September 30, 2008 and 2007 and December 31, 2007.
|
|
Gross
receivables
|
|
|
Gross
payables
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
September
30,
|
|
|
September
30,
|
|
|
December
31,
|
|
|
September
30,
|
|
In
millions
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
Netting
agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade
|
|
$
|
446
|
|
|
$
|
437
|
|
|
$
|
256
|
|
|
$
|
338
|
|
|
$
|
356
|
|
|
$
|
231
|
|
Counterparty
is non-investment grade
|
|
|
10
|
|
|
|
24
|
|
|
|
13
|
|
|
|
16
|
|
|
|
18
|
|
|
|
28
|
|
Counterparty
has no external rating
|
|
|
76
|
|
|
|
134
|
|
|
|
94
|
|
|
|
212
|
|
|
|
204
|
|
|
|
124
|
|
No
netting agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade
|
|
|
3
|
|
|
|
3
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
Amount
recorded on balance sheet
|
|
$
|
535
|
|
|
$
|
598
|
|
|
$
|
363
|
|
|
$
|
568
|
|
|
$
|
578
|
|
|
$
|
383
|
|
Sequent
has certain trade and credit contracts that have explicit minimum credit rating
requirements. These credit rating requirements typically give counterparties the
right to suspend or terminate credit if our credit ratings are downgraded to
non-investment grade status. Under such circumstances, Sequent would need to
post collateral to continue transacting business with some of its
counterparties. Posting collateral would have a negative effect on our
liquidity. If such collateral were not posted, Sequent’s ability to continue
transacting business with these counterparties would be impaired. If, at
September 30, 2008, our credit ratings had been downgraded to non-investment
grade status, the required amounts to satisfy potential collateral demands under
such agreements between Sequent and its counterparties would have totaled $15
million.
There
have been no other significant changes to our credit risk related to our other
segments, as described in Item 7A ”Quantitative and Qualitative Disclosures
about Market Risk” of our Annual Report on Form 10-K for the year ended December
31, 2007.
(a)
Evaluation of
disclosure controls and procedures
.
Under the supervision and
with the participation of our management, including our principal executive
officer and principal financial officer, we conducted an evaluation of our
disclosure controls and procedures, as such term is defined in Rule 13a-15(e)
promulgated under the Securities Exchange Act of 1934, as amended (the Exchange
Act), as of September 30, 2008, the end of the period covered by this report.
Based on this evaluation, our principal executive officer and our principal
financial officer concluded that our disclosure controls and procedures were
effective as of September 30, 2008, in providing a reasonable level of assurance
that information we are required to disclose in reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported within
the time periods in SEC rules and forms, including a reasonable level of
assurance that information required to be disclosed by us in such reports is
accumulated and communicated to our management, including our principal
executive officer and our principal financial officer, as appropriate to allow
timely decisions regarding required disclosure.
(b)
Changes in
internal control over financial reporting
.
There were no changes in our
internal control over financial reporting during our most recent fiscal quarter
that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
The
nature of our business ordinarily results in periodic regulatory proceedings
before various state and federal authorities and litigation incidental to the
business. For information regarding pending federal and state regulatory
matters, see “
Note 6
- Commitments and Contingencies”
contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated
Financial Statements (Unaudited).” With regard to other legal proceedings, we
are a party, as both plaintiff and defendant, to a number of other suits, claims
and counterclaims on an ongoing basis. Management believes that the outcome of
all such other litigation in which it is involved will not have a material
adverse effect on our consolidated financial statements. There have been no
significant changes in the litigation which was described in Note 7 to our
Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K
for the year ended December 31, 2007. We believe the ultimate resolution of such
litigation will not have a material adverse effect on our consolidated financial
condition, results of operations or cash flows.
The
following table sets forth information regarding purchases of our common stock
by us and any affiliated purchasers during the three months ended September 30,
2008. Stock repurchases may be made in the open market or in private
transactions at times and in amounts that we deem appropriate. However, there is
no guarantee as to the exact number of additional shares that may be
repurchased, and we may terminate or limit the stock repurchase program at any
time. We will hold the repurchased shares as treasury shares.
Period
|
|
Total
number of shares purchased (1) (2) (3)
|
|
|
Average
price paid per share
|
|
|
Total
number of shares purchased as part of publicly announced plans or programs
(3)
|
|
|
Maximum
number of shares that may yet be purchased under the publicly announced
plans or programs (3)
|
|
July
2008
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
4,950,951
|
|
August
2008
|
|
|
89
|
|
|
|
32.92
|
|
|
|
-
|
|
|
|
4,950,951
|
|
September
2008
|
|
|
2,108
|
|
|
|
32.87
|
|
|
|
-
|
|
|
|
4,950,951
|
|
Total
third quarter
|
|
|
2,197
|
|
|
$
|
32.87
|
|
|
|
-
|
|
|
|
|
|
(1)
|
The
total number of shares purchased includes an aggregate of 2,197 shares
surrendered to us to satisfy tax withholding obligation in connection with
the vesting of shares of restricted stock and the exercise of stock
options.
|
(2)
|
On
March 20, 2001, our Board of Directors approved the purchase of up to
600,000 shares of our common stock in the open market to be used for
issuances under the Officer Incentive Plan (Officer Plan). We did not
purchase any shares for such purposes in the third quarter of 2008. As of
September 30, 2008, we had purchased a total 307,567 of the 600,000 shares
authorized for purchase, leaving 292,433 shares available for purchase
under this program.
|
(3)
|
On
February 3, 2006, we announced that our Board of Directors had authorized
a plan to repurchase up to a total of 8 million shares of our common
stock, excluding the shares remaining available for purchase in connection
with the Officer Plan as described in note (2) above, over a five-year
period.
|
3.1
|
Amended
and Restated Articles of Incorporation filed November 2, 2005 with the
Secretary of State of the state of Georgia (Exhibit 3.1, AGL Resources
Inc. Form 8-K dated November 2,
2005).
|
3.2
|
Bylaws,
as amended on October 31, 2007 (Exhibit 3.2, AGL Resources Inc. Form 8-K
dated October 31, 2007).
|
4.1
|
Specimen
form of Common Stock certificate (Exhibit 4.1, AGL Resources Inc. Form
10-K for the fiscal year ended September 30,
1999).
|
10.1
|
Letter
of Credit and Security Agreement dated as of September 4, 2008 by and
among Pivotal Utility Holdings, Inc. as borrower, AGL Resources Inc. as
Guarantor, Bank of America, N.A. as Administrative Agent, The Bank of
Tokyo-Mitsubishi UFJ, LTD. as Syndication Agent and Bank of America, N.A.
as Issuing Bank.
|
10.2
|
Credit
Agreement as of September 30, 2008 by and among AGL Resources Inc., AGL
Capital Corporation, Wachovia Bank, N.A. as Administrative Agent, Wachovia
Capital Markets, LLC as sole lead arranger and sole lead bookrunner.
SunTrust Bank, NA, The Bank of Tokyo-Mitsubishi UFJ, LTD., Calyon New
York Brand and The Royal Bank of Scotland PLC. as Co-Documentation
Agents (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 30,
2008).
|
31.1
|
Certification
of John W. Somerhalder II pursuant to Rule 13a -
14(a).
|
31.2
|
Certification
of Andrew W. Evans pursuant to Rule 13a -
14(a).
|
32.1
|
Certification
of John W. Somerhalder II pursuant to 18 U.S.C. Section
1350.
|
32.2
|
Certification
of Andrew W. Evans pursuant to 18 U.S.C. Section
1350.
|
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.
AGL
RESOURCES INC.
(Registrant)
Date:
October 30,
2008
/s/ Andrew W.
Evans
Executive
Vice President and Chief Financial Officer
Atlanta Gas Light (NYSE:ATG)
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