UNITED
STATES
|
SECURITIES
AND EXCHANGE COMMISSION
|
Washington,
D.C. 20549
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|
FORM
10-Q
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(Mark One)
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|
þ
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
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For
the Quarterly Period Ended March 31, 2009
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OR
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¨
TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
the transition period
from to
|
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Commission
File Number 1-14174
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AGL
RESOURCES INC.
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(Exact
name of registrant as specified in its charter)
|
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Georgia
|
58-2210952
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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Ten
Peachtree Place NE, Atlanta, Georgia 30309
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(Address
and zip code of principal executive offices)
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404-584-4000
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(Registrant's
telephone number, including area code)
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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 has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T
(§232.405 of this chapter) during the preceding 12 months (or for such
shorter period that the registrant was required to submit and post such
files). Yes
¨
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.
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|
Class
|
Outstanding
as of April 23, 2009
|
Common
Stock, $5.00 Par Value
|
77,170,946
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AGL
RESOURCES INC.
Quarterly
Report on Form 10-Q
For the
Quarter Ended March 31, 2009
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Page(s)
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3
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Item
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Number
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4-38
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1
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4-21
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4
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5
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6
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7
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8
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9 –
21
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9 –
11
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11
– 12
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12
– 15
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16
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17
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18
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18
– 19
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20
– 21
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2
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22
– 35
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22
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22
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23
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23
– 24
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24
– 25
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25
– 26
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27
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27
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27
– 31
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31
– 34
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34
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34
– 35
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3
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35
– 38
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4
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38
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39
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1
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39
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2
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39
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6
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39
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40
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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
Facilities
|
Credit
agreements supporting our commercial paper program
|
EBIT
|
Earnings
before interest and taxes, a non-GAAP measure that includes operating
income, other income and gain on sales of assets and excludes interest
expense, and income tax expense; as an indicator of our operating
performance, EBIT should not be considered an alternative to, or more
meaningful than, operating income, net income, or net income attributable
to AGL Resources Inc. 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
|
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
|
GNGC
|
Georgia
Natural Gas Company, our wholly-owned subsidiary
|
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 through 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
|
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 condensed consolidated statements of income. Operating
margin should not be considered an alternative to, or more meaningful
than, operating income, net income, or net income attributable to AGL
Resources Inc. as determined in 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
|
PP&E
|
Property,
plant and equipment
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PRP
|
Pipeline
replacement program for Atlanta Gas Light
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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.
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WACOG
|
Weighted
average cost of gas
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WNA
|
Weather
normalization adjustment
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REFERENCED
ACCOUNTING STANDARDS
FIN
46 & FIN 46R
|
FIN
46, “Consolidation of Variable Interest Entities”
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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 132(R)-1
|
FSP
No. FAS 132(R)-1,"Employers' Disclosures about Postretirement Benefit
Plan Assets"
|
FSP
FAS 133-1
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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”
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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”
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SFAS
141
|
SFAS
No. 141, “Business Combinations”
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SFAS
157
|
SFAS
No. 157, “Fair Value Measurements”
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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)
|
|
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As
of
|
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|
|
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In
millions, except share data
|
|
March
31,
2009
|
|
|
December
31, 2008
|
|
|
March
31, 2008
|
|
Current
assets
|
|
|
|
|
|
|
|
|
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Cash
and cash equivalents
|
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$
|
21
|
|
|
$
|
16
|
|
|
$
|
20
|
|
Receivables
|
|
|
|
|
|
|
|
|
|
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Gas,
unbilled and other receivables
|
|
|
458
|
|
|
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472
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|
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480
|
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Energy
marketing receivables
|
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326
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549
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624
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Less
allowance for uncollectible accounts
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(20
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)
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(16
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)
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(18
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)
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Total
receivables
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|
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764
|
|
|
|
1,005
|
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1,086
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Inventory,
net (Note 1)
|
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|
348
|
|
|
|
663
|
|
|
|
356
|
|
Derivative
financial instruments – current portion (Note 2 and Note
3)
|
|
|
202
|
|
|
|
207
|
|
|
|
56
|
|
Unrecovered
pipeline replacement program costs – current portion (Note
1)
|
|
|
42
|
|
|
|
41
|
|
|
|
35
|
|
Unrecovered
environmental remediation costs – current portion (Note 1)
|
|
|
16
|
|
|
|
18
|
|
|
|
21
|
|
Other
current assets
|
|
|
38
|
|
|
|
92
|
|
|
|
52
|
|
Total
current assets
|
|
|
1,431
|
|
|
|
2,042
|
|
|
|
1,626
|
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Long-term
assets and other deferred debits
|
|
|
|
|
|
|
|
|
|
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|
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Property,
plant and equipment
|
|
|
5,592
|
|
|
|
5,500
|
|
|
|
5,222
|
|
Less
accumulated depreciation
|
|
|
1,706
|
|
|
|
1,684
|
|
|
|
1,612
|
|
Property,
plant and equipment-net
|
|
|
3,886
|
|
|
|
3,816
|
|
|
|
3,610
|
|
Goodwill
|
|
|
418
|
|
|
|
418
|
|
|
|
420
|
|
Unrecovered
pipeline replacement program costs (Note 1)
|
|
|
177
|
|
|
|
196
|
|
|
|
236
|
|
Unrecovered
environmental remediation costs (Note 1)
|
|
|
121
|
|
|
|
125
|
|
|
|
130
|
|
Derivative
financial instruments (Note 2 and Note 3)
|
|
|
48
|
|
|
|
38
|
|
|
|
11
|
|
Other
|
|
|
76
|
|
|
|
75
|
|
|
|
73
|
|
Total
long-term assets and other deferred debits
|
|
|
4,726
|
|
|
|
4,668
|
|
|
|
4,480
|
|
Total
assets
|
|
$
|
6,157
|
|
|
$
|
6,710
|
|
|
$
|
6,106
|
|
Current
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt (Note 6)
|
|
$
|
403
|
|
|
$
|
866
|
|
|
$
|
369
|
|
Energy
marketing trade payables
|
|
|
342
|
|
|
|
539
|
|
|
|
711
|
|
Accounts
payable - trade
|
|
|
193
|
|
|
|
202
|
|
|
|
166
|
|
Accrued
expenses
|
|
|
151
|
|
|
|
113
|
|
|
|
125
|
|
Customer
deposits
|
|
|
58
|
|
|
|
50
|
|
|
|
34
|
|
Derivative
financial instruments – current portion (Note 2 and Note
3)
|
|
|
43
|
|
|
|
50
|
|
|
|
37
|
|
Accrued
pipeline replacement program costs – current portion (Note
1)
|
|
|
43
|
|
|
|
49
|
|
|
|
55
|
|
Deferred
natural gas costs
|
|
|
33
|
|
|
|
25
|
|
|
|
38
|
|
Accrued
environmental remediation liabilities – current portion (Note
1)
|
|
|
20
|
|
|
|
17
|
|
|
|
13
|
|
Other
current liabilities
|
|
|
62
|
|
|
|
72
|
|
|
|
58
|
|
Total
current liabilities
|
|
|
1,348
|
|
|
|
1,983
|
|
|
|
1,606
|
|
Long-term
liabilities and other deferred credits
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (Note 6)
|
|
|
1,675
|
|
|
|
1,675
|
|
|
|
1,516
|
|
Accumulated
deferred income taxes
|
|
|
586
|
|
|
|
571
|
|
|
|
570
|
|
Accumulated
removal costs
|
|
|
194
|
|
|
|
178
|
|
|
|
173
|
|
Accrued
pension obligations (Note 4)
|
|
|
188
|
|
|
|
199
|
|
|
|
43
|
|
Accrued
pipeline replacement program costs (Note 1)
|
|
|
126
|
|
|
|
140
|
|
|
|
176
|
|
Accrued
environmental remediation liabilities (Note 1)
|
|
|
85
|
|
|
|
89
|
|
|
|
92
|
|
Accrued
postretirement benefit costs (Note 4)
|
|
|
45
|
|
|
|
46
|
|
|
|
22
|
|
Derivative
financial instruments (Note 2 and Note 3)
|
|
|
8
|
|
|
|
6
|
|
|
|
5
|
|
Other
long-term liabilities and other deferred credits
|
|
|
139
|
|
|
|
139
|
|
|
|
149
|
|
Total
long-term liabilities and other deferred credits
|
|
|
3,046
|
|
|
|
3,043
|
|
|
|
2,746
|
|
Commitments
and contingencies (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
(Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
AGL
Resources Inc. common shareholders’ equity, $5 par value; 750,000,000
shares authorized
|
|
|
1,734
|
|
|
|
1,652
|
|
|
|
1,722
|
|
Noncontrolling
interest
|
|
|
29
|
|
|
|
32
|
|
|
|
32
|
|
Total
equity
|
|
|
1,763
|
|
|
|
1,684
|
|
|
|
1,754
|
|
Total
liabilities and equity
|
|
$
|
6,157
|
|
|
$
|
6,710
|
|
|
$
|
6,106
|
|
See
Notes to Condensed Consolidated Financial Statements
(Unaudited).
|
|
|
|
|
|
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
|
|
Three
months ended March 31,
|
In
millions, except per share amounts
|
|
2009
|
|
|
2008
|
|
Operating
revenues
|
|
$
|
995
|
|
|
$
|
1,012
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
589
|
|
|
|
657
|
|
Operation
and maintenance
|
|
|
125
|
|
|
|
119
|
|
Depreciation
and amortization
|
|
|
39
|
|
|
|
36
|
|
Taxes
other than income taxes
|
|
|
12
|
|
|
|
12
|
|
Total
operating expenses
|
|
|
765
|
|
|
|
824
|
|
Operating
income
|
|
|
230
|
|
|
|
188
|
|
Other
income
|
|
|
2
|
|
|
|
1
|
|
Interest
expense, net
|
|
|
(25
|
)
|
|
|
(30
|
)
|
Earnings
before income taxes
|
|
|
207
|
|
|
|
159
|
|
Income
tax expense
|
|
|
72
|
|
|
|
54
|
|
Net
income
|
|
|
135
|
|
|
|
105
|
|
Less
net income attributable to the noncontrolling interest (Note
5)
|
|
|
16
|
|
|
|
16
|
|
Net
income attributable to AGL Resources Inc.
|
|
$
|
119
|
|
|
$
|
89
|
|
Per
common share data (Note 1)
|
|
|
|
|
|
|
|
|
Basic
earnings per common share attributable to AGL Resources Inc. common
shareholders
|
|
$
|
1.55
|
|
|
$
|
1.17
|
|
Diluted
earnings per common share attributable to AGL Resources Inc. common
shareholders
|
|
$
|
1.55
|
|
|
$
|
1.16
|
|
Cash
dividends declared per common share
|
|
$
|
0.43
|
|
|
$
|
0.42
|
|
Weighted
average number of common shares outstanding (Note 1)
|
|
|
|
|
|
|
|
|
Basic
|
|
|
76.7
|
|
|
|
76.0
|
|
Diluted
|
|
|
76.8
|
|
|
|
76.3
|
|
See Notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
|
|
AGL
Resources Inc. Shareholders
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
Premium
on common
|
|
|
Earnings
|
|
|
Accumulated
other comprehensive
|
|
|
Shares
held in treasury and
|
|
|
Noncontrolling
|
|
|
|
|
In
millions, except per share amount
|
|
Shares
|
|
|
Amount
|
|
|
stock
|
|
|
reinvested
|
|
|
loss
|
|
|
trust
|
|
|
interest
|
|
|
Total
|
|
Balance
as of December 31, 2008
|
|
|
76.9
|
|
|
$
|
390
|
|
|
$
|
676
|
|
|
$
|
763
|
|
|
$
|
(134
|
)
|
|
$
|
(43
|
)
|
|
$
|
32
|
|
|
$
|
1,684
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
119
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16
|
|
|
|
135
|
|
Other
comprehensive loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(7
|
)
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(11
|
)
|
Dividends
on common stock ($0.43 per share)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(33
|
)
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(32
|
)
|
Distributions
to noncontrolling interest
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(15
|
)
|
|
|
(15
|
)
|
Issuance
of treasury shares
|
|
|
0.3
|
|
|
|
-
|
|
|
|
(6
|
)
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
1
|
|
Stock-based
compensation expense (net of taxes) (Note 5)
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
Balance
as of March 31, 2009
|
|
|
77.2
|
|
|
$
|
390
|
|
|
$
|
671
|
|
|
$
|
847
|
|
|
$
|
(141
|
)
|
|
$
|
(33
|
)
|
|
$
|
29
|
|
|
$
|
1,763
|
|
See Notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED
)
|
|
|
|
Components
of other comprehensive loss
(net
of taxes)
|
|
|
|
|
|
|
|
|
Cash
flow hedges
|
|
|
|
|
In
millions
|
|
Net
income
|
|
Derivative
financial instruments unrealized (losses) gains arising during the
period
|
|
|
Reclassification
of derivative financial instruments realized losses (gains) included in
net income
|
|
|
Other
comprehensive loss
|
|
|
Comprehensive
income (Note 5)
|
Three months ended March 31,
2009
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AGL
Resources
|
|
$
|
119
|
|
$
|
(9
|
)
|
|
$
|
2
|
|
|
$
|
(7
|
)
|
|
$
|
112
|
|
Noncontrolling
interest
|
|
|
16
|
|
|
(5
|
)
|
|
|
1
|
|
|
|
(4
|
)
|
|
|
12
|
|
Consolidated
|
|
$
|
135
|
|
$
|
(14
|
)
|
|
$
|
3
|
|
|
$
|
(11
|
)
|
|
$
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
2008
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AGL
Resources
|
|
$
|
89
|
|
$
|
2
|
|
|
$
|
(4
|
)
|
|
$
|
(2
|
)
|
|
$
|
87
|
|
Noncontrolling
interest
|
|
|
16
|
|
|
1
|
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
15
|
|
Consolidated
|
|
$
|
105
|
|
$
|
3
|
|
|
$
|
(6
|
)
|
|
$
|
(3
|
)
|
|
$
|
102
|
|
See Notes
to Condensed Consolidated Financial Statements (Unaudited).
AGL
RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED
)
|
|
|
|
|
|
|
|
|
Three
months ended
|
|
|
|
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
Net
income
|
|
$
|
135
|
|
|
$
|
105
|
|
Adjustments
to reconcile net income to net cash flow provided by operating
activities
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
39
|
|
|
|
36
|
|
Change
in derivative financial instrument assets and liabilities
|
|
|
(10
|
)
|
|
|
36
|
|
Deferred
income taxes
|
|
|
(10
|
)
|
|
|
(18
|
)
|
Changes
in certain assets and liabilities
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
315
|
|
|
|
195
|
|
Accrued
expenses
|
|
|
38
|
|
|
|
38
|
|
Energy
marketing receivables and energy marketing trade payables,
net
|
|
|
26
|
|
|
|
107
|
|
Gas,
unbilled and other receivables
|
|
|
18
|
|
|
|
(71
|
)
|
Gas
and trade payables
|
|
|
(9
|
)
|
|
|
(6
|
)
|
Other
– net
|
|
|
69
|
|
|
|
89
|
|
Net
cash flow provided by operating activities
|
|
|
611
|
|
|
|
511
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
Payments
to acquire, property, plant and equipment
|
|
|
(97
|
)
|
|
|
(80
|
)
|
Net
cash flow used in investing activities
|
|
|
(97
|
)
|
|
|
(80
|
)
|
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
Net
payments and borrowings of short-term debt
|
|
|
(463
|
)
|
|
|
(324
|
)
|
Dividends
paid on common shares
|
|
|
(32
|
)
|
|
|
(31
|
)
|
Distribution
to noncontrolling interest
|
|
|
(15
|
)
|
|
|
(30
|
)
|
Payments
of long-term debt
|
|
|
-
|
|
|
|
(47
|
)
|
Issuance
of treasury shares
|
|
|
1
|
|
|
|
2
|
|
Net
cash flow used in financing activities
|
|
|
(509
|
)
|
|
|
(430
|
)
|
Net
increase in cash and cash equivalents
|
|
|
5
|
|
|
|
1
|
|
Cash
and cash equivalents at beginning of period
|
|
|
16
|
|
|
|
19
|
|
Cash
and cash equivalents at end of period
|
|
$
|
21
|
|
|
$
|
20
|
|
Cash
paid during the period for
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
29
|
|
|
$
|
34
|
|
Income
taxes
|
|
$
|
16
|
|
|
$
|
2
|
|
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 statement of financial position 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, 2008, filed with the SEC on February 5,
2009.
Due to
the seasonal nature of our business, our results of operations for the three
months ended March 31, 2009 and 2008, and our financial condition as of December
31, 2008, and March 31, 2009 and 2008, 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.
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 financial accounting
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
allowance for 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.
Energy
Marketing Receivables and Payables
Our
wholesale services segment provides services to retail marketers and utility and
industrial customers. These customers, also known as counterparties, utilize
netting agreements, which enable wholesale services to net receivables and
payables
by
counterparty. Wholesale services also nets across product lines and against cash
collateral, provided the master netting and cash collateral agreements include
such provisions. The amounts due from or owed to wholesale services’
counterparties are netted and recorded on our condensed consolidated statements
of financial position as energy marketing receivables and energy marketing
payables.
Wholesale
services has some 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,
wholesale services 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, wholesale
services ability to continue transacting business with these counterparties
would be impaired.
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
$6 million in the three months ended March 31, 2009 and did not record LOCOM
adjustments in the three months ended March 31, 2008. Sequent recorded LOCOM
adjustments of $8 million in the three months ended March 31, 2009 and did not
record LOCOM adjustments for the three months ended March 31, 2008.
Regulatory Assets and
Liabilities
We have
recorded regulatory assets and liabilities in our condensed consolidated
statements of financial position 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 derivative financial instruments, are summarized in the
following table.
|
|
Mar.
31
|
|
|
Dec.
31
|
|
|
Mar.
31
|
In
millions
|
|
2009
|
|
|
2008
|
|
|
2008
|
Regulatory
assets
|
|
|
|
|
|
|
|
|
Unrecovered
PRP costs
|
|
$
|
219
|
|
|
$
|
237
|
|
|
$
|
271
|
|
Unrecovered
ERC
|
|
|
137
|
|
|
|
143
|
|
|
|
151
|
|
Unrecovered
postretirement benefit costs
|
|
|
11
|
|
|
|
11
|
|
|
|
12
|
|
Unrecovered
seasonal rates
|
|
|
-
|
|
|
|
11
|
|
|
|
-
|
|
Unrecovered
natural gas costs
|
|
|
-
|
|
|
|
19
|
|
|
|
18
|
|
Elizabethtown
Gas derivative financial instruments
|
|
|
-
|
|
|
|
-
|
|
|
|
16
|
|
Other
|
|
|
28
|
|
|
|
30
|
|
|
|
24
|
|
Total
regulatory assets
|
|
|
395
|
|
|
|
451
|
|
|
|
492
|
|
Associated
assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Elizabethtown
Gas derivative financial instruments
|
|
|
29
|
|
|
|
23
|
|
|
|
-
|
|
Total
regulatory and associated assets
|
|
$
|
424
|
|
|
$
|
474
|
|
|
$
|
492
|
|
Regulatory
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
removal costs
|
|
$
|
194
|
|
|
$
|
178
|
|
|
$
|
173
|
|
Deferred
natural gas costs
|
|
|
33
|
|
|
|
25
|
|
|
|
38
|
|
Elizabethtown
Gas derivative financial instruments
|
|
|
29
|
|
|
|
23
|
|
|
|
-
|
|
Deferred
seasonal rates
|
|
|
22
|
|
|
|
-
|
|
|
|
22
|
|
Regulatory
tax liability
|
|
|
18
|
|
|
|
19
|
|
|
|
20
|
|
Unamortized
investment tax credit
|
|
|
14
|
|
|
|
14
|
|
|
|
15
|
|
Other
|
|
|
19
|
|
|
|
22
|
|
|
|
20
|
|
Total regulatory
liabilities
|
|
|
329
|
|
|
|
281
|
|
|
|
288
|
|
Associated
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
PRP
costs
|
|
|
169
|
|
|
|
189
|
|
|
|
231
|
|
ERC
|
|
|
95
|
|
|
|
96
|
|
|
|
95
|
|
Elizabethtown
Gas derivative financial instruments
|
|
|
-
|
|
|
|
-
|
|
|
|
16
|
|
Total
associated liabilities
|
|
|
264
|
|
|
|
285
|
|
|
|
342
|
|
Total
regulatory and associated liabilities
|
|
$
|
593
|
|
|
$
|
566
|
|
|
$
|
630
|
|
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, 2008.
Income Taxes
As a
result of our adoption of SFAS 160, income tax expense and our effective tax
rate are determined from earnings before income tax less net income attributable
to the noncontrolling interest. For more information on our adoption of SFAS
160, see
Note 5
.
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, 2008.
Earnings
per Common Share
We
compute basic earnings per common share by dividing our net income attributable
to our common shareholders by the daily weighted-average number of common shares
outstanding. 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 adopted FSP EITF
03-6-1 on January 1, 2009, which provides guidance on the computation of
earnings per share when a company has unvested share awards outstanding that
have the nonforfeitable right to receive dividends. The effects of this FSP were
immaterial to our calculation of earnings per share.
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, for the periods presented, 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 March 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Denominator for basic earnings
per share
(1)
|
|
|
76.7
|
|
|
|
76.0
|
|
Assumed
exercise of restricted stock, restricted stock units and stock
options
|
|
|
0.1
|
|
|
|
0.3
|
|
Denominator
for diluted earnings per share
|
|
|
76.8
|
|
|
|
76.3
|
|
(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:
|
|
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Three
months ended
|
|
|
2.2
|
|
|
|
1.6
|
|
The
increase of 0.6 million shares which were excluded from the computation of
diluted earnings per share and considered anti-dilutive was a result of a
decline in the average market value of our common shares at March 31, 2009 as
compared to March 31, 2008.
The
carrying value of cash and cash equivalents, receivables, accounts payable,
short-term debt, other current liabilities, derivative financial instrument
assets, derivative financial instrument 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 statements of financial position.
In
millions
|
|
Carrying
amount
|
|
|
Estimated
fair value
|
|
As
of March 31, 2009
|
|
$
|
1,676
|
|
|
$
|
1,633
|
|
As
of December 31, 2008
|
|
|
1,676
|
|
|
|
1,647
|
|
As of March 31, 2008
(1)
|
|
|
1,678
|
|
|
|
1,734
|
|
(1)
|
Includes
$161 million of gas facility revenue bonds which we repurchased with
proceeds from our commercial paper program in March and April
2008.
|
We
estimate the fair value of our long-term debt using a discounted cash flow
technique that incorporates a market interest yield curve with adjustments for
duration, optionality and risk profile. In determining the market interest
yield curve, we considered our currently assigned ratings for unsecured debt of
BBB+ by S&P, Baa1 by Moody’s and A- by Fitch.
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. We adopted SFAS
157 for our nonfinancial assets and liabilities on January 1, 2009, which had no
impact to our condensed consolidated results of operations, cash flows and
financial condition.
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 March 31, 2009. 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.
Our
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.
The
determination of the fair values in the following table 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
effect of our nonperformance risk on our liabilities. For more information on
our derivative financial instruments, see Note 3.
|
|
Recurring
fair values
Commodity
derivative financial instruments
|
|
|
|
March
31, 2009
|
|
|
December
31, 2008
|
|
|
March
31, 2008
|
|
In
millions
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets
(1)
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
Quoted
prices in active markets (Level 1)
|
|
$
|
39
|
|
|
$
|
(198
|
)
|
|
$
|
52
|
|
|
$
|
(117
|
)
|
|
$
|
28
|
|
|
$
|
(34
|
)
|
Significant
other observable inputs (Level 2)
|
|
|
163
|
|
|
|
(19
|
)
|
|
|
154
|
|
|
|
(28
|
)
|
|
|
39
|
|
|
|
(44
|
)
|
Netting
of
cash
collateral
|
|
|
48
|
|
|
|
166
|
|
|
|
35
|
|
|
|
89
|
|
|
|
-
|
|
|
|
36
|
|
Total carrying
value
(2)
|
|
$
|
250
|
|
|
$
|
(51
|
)
|
|
$
|
241
|
|
|
$
|
(56
|
)
|
|
$
|
67
|
|
|
$
|
(42
|
)
|
(1)
$4
million premium associated with weather derivatives has been excluded as
they are based on intrinsic value, not fair value. For more information
see Note 3.
(2)
There
were no significant unobservable inputs (level 3) for any of the periods
presented.
|
|
Netting
of Cash Collateral with Derivative Assets and Liabilities under Master Netting
Arrangements
We
maintain accounts with exchange 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. We
are required to offset this cash collateral with the associated fair value of
the derivative financial instruments. Our cash collateral amounts are provided
in the following table.
|
|
|
|
|
As
of
|
|
|
|
|
In
millions
|
|
Mar.
31, 2009
|
|
|
Dec.
31, 2008
|
|
|
Mar.
31, 2008
|
|
Right
to reclaim cash collateral
|
|
$
|
214
|
|
|
$
|
128
|
|
|
$
|
37
|
|
Obligations
to return cash collateral
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(1
|
)
|
Total
cash collateral
|
|
$
|
214
|
|
|
$
|
124
|
|
|
$
|
36
|
|
Derivative
Financial Instruments
Our use
of derivative financial instruments and physical transactions is limited to
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, automobile fuel price and foreign currency
risks:
·
|
weather
derivative contracts
|
·
|
storage
and transportation capacity
transactions
|
·
|
foreign
currency forward contracts
|
Our
derivative financial instruments do not contain any material credit-risk-related
or other contingent features that could cause us to make accelerated payments
over and above collateral we post in the normal course of business when our
financial instruments are in net liability positions. For information on our
energy marketing receivables and payables, which do have
credit-risk-related or other contingent features refer to Note 1. Our risk
management activities are monitored by our Risk Management Committee (RMC),
which consists of members of senior management. The RMC is charged with
reviewing and enforcing our risk management activities and
policies.
We
adopted SFAS 161 on January 1, 2009, which amends the disclosure requirements of
SFAS 133 and requires specific disclosures regarding how and why we use
derivative instruments; the accounting for derivative instruments and related
hedged items; and how derivative instruments and related hedged items affect our
financial position, results of operations and cash flows. As SFAS 161 only
requires additional disclosures concerning derivatives and hedging activities,
this standard did not have an impact on our financial position, results of
operations or cash flows.
We
adopted FSP FAS 133-1 on January 1, 2009. 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 had no financial impact to our
results of operations, cash flows or financial condition.
Interest
Rate Derivative Financial Instruments
To
maintain an effective capital structure, our policy is to borrow funds using a
mix of fixed-rate and variable-rate debt. We have previously entered into
interest rate swap agreements for the purpose of managing the appropriate mix of
risk associated with our fixed-rate and variable-rate debt obligations. We
designated these interest rate swaps as fair value hedges in accordance with
SFAS 133 and recorded the gain or loss on fair value hedges in earnings in the
period of change, together with the offsetting loss or gain on the hedged item
attributable to
the
interest rate risk being hedged. As of March 31, 2009, December 31, 2008 and
March 31, 2008, we did not have any interest rate swap agreements.
Commodity
Derivative Financial Instruments
All
activities associated with commodity price risk management activities and
derivative instruments are included as a component of cash flows from operating
activities in our condensed consolidated statements of cash flows. Our
derivatives not designated as hedges under SFAS 133, are included within
operating cash flows as a source (use) of cash totaling $(10) million in 2009
and $36 million in 2008.
Distribution
Operations
In accordance with a directive from the New Jersey Commission,
Elizabethtown Gas enters into derivative financial instruments to hedge the
impact of market fluctuations in natural gas prices. Pursuant to SFAS 133, such
derivative transactions are accounted for at fair value each reporting period in
our condensed consolidated statements of financial position. In accordance
with regulatory requirements realized gains and losses related to these
derivatives are reflected in natural gas costs and ultimately included in
billings to customers. However, these derivative financial instruments are not
designated as hedges in accordance with SFAS 133. For more information on our
regulatory assets and liabilities see Note 1.
Retail Energy
Operations
SouthStar uses
commodity-related derivative financial instruments (futures, options and swaps)
to manage exposures arising from changing commodity prices. SouthStar’s
objective for holding these derivatives is to utilize the most effective method
to reduce or eliminate the impact of this exposure. We have designated a portion
of SouthStar’s derivative transactions, consisting of financial swaps to manage
the commodity risk associated with forecasted purchases and sales of natural
gas, as cash flow hedges under 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 settlement of the underlying hedged item. SouthStar currently
has minimal 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. This cash flow hedge ineffectiveness is recorded in cost of gas in
our condensed consolidated statements of income in the period in which it
occurs. 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 within cost of gas in our condensed consolidated statements of
income in the period of change. For more information on SouthStar’s gains and
losses reported within comprehensive income that affects equity, see our
condensed consolidated statements of comprehensive income. SouthStar has hedged
its exposures to commodity risk to varying degrees in the markets in which it
serves retail, commercial and industrial customers.
Approximately
80% of SouthStar’s purchase instruments and 56% of its sales instruments are
scheduled to mature in 2009 and the remaining 20% and 44%, respectively, in less
than 2 years.
SouthStar
also enters into both exchange and OTC derivative transactions to hedge
commodity price risk. Credit risk is mitigated for exchange transactions through
the backing of the NYMEX member firms. For OTC transactions, SouthStar utilizes
master netting arrangements to reduce overall credit risk. As of March 31, 2009,
SouthStar’s maximum exposure to any single OTC counterparty was $6
million.
Wholesale
Services
Sequent uses derivative
financial instruments to reduce our exposure to the risk of changes in the
prices of natural gas. The fair value of these derivative financial instruments
reflects the estimated amounts that we would receive or pay to terminate or
close the contracts at the reporting date, taking into account the current
unrealized gains or losses on open contracts. We use external market quotes and
indices to value substantially all the derivative financial instruments we
use.
We
mitigate substantially all the commodity price risk associated with Sequent’s
natural gas portfolio by locking in the economic margin at the time we enter
into natural gas purchase transactions for our stored natural gas. We purchase
natural gas for storage when the difference in the current market price we pay
to buy and transport natural gas plus the cost to store the natural gas is less
than the market price we can receive in the future, resulting in a positive net
operating margin. We use NYMEX futures contracts and other OTC derivatives to
sell natural gas at that future price to substantially lock in the operating
margin we will ultimately realize when the stored natural gas is actually sold.
These futures contracts meet the definition of derivatives under SFAS 133 and
are accounted for at fair value in our condensed consolidated statements of
financial position, with changes in fair value recorded in our condensed
consolidated statements of income in the period of change. However, these
futures contracts are not designated as hedges in accordance with SFAS
133.
The
purchase, transportation, storage and sale of natural gas are accounted for on a
weighted average cost or accrual basis, as appropriate rather than on the fair
value basis we utilize for the derivatives used to mitigate the commodity price
risk associated with our storage portfolio. This difference in accounting can
result in volatility in our reported earnings, even though the economic margin
is essentially unchanged from the date the transactions were consummated.
Approximately 95% of Sequent’s purchase instruments and 96% of its sales
instruments are scheduled to mature in less than 2 years and the remaining 5%
and 4%, respectively, in 3 to 9 years.
The
changes in fair value of Sequent’s derivative instruments utilized in its energy
marketing and risk management activities and contract settlements decreased the
net fair value of its contracts outstanding by $75 million during both the three
months ended March 31, 2009 and the three months ended March 31,
2008.
Weather
Derivative Financial Instruments
In 2009
and 2008, SouthStar entered into weather derivative contracts as economic hedges
of operating margins in the event of warmer-than-normal and colder-than-normal
weather in the heating season, primarily from November through March. SouthStar
accounts for these contracts using the intrinsic value method under the
guidelines of EITF 99-02, and accordingly these derivative financial instruments
are not designated as derivatives or hedges under SFAS 133. SouthStar recorded a
net payable for this hedging activity of less than $1 million at March 31, 2009
and at March 31, 2008 and a current asset of $4 million at December 31, 2008. In
the three months ended March 31, 2009 and 2008, SouthStar recognized $4 million
and $5 million of losses on its weather derivative financial instruments, which
were reflected in cost of gas on our condensed consolidated statements of
income.
Quantitative
Disclosures Related to Derivative Financial Instruments
As of
March 31, 2009, our derivative financial instruments were comprised of both long
and short commodity positions, whereby a long position is a contract to purchase
the commodity, and a short position is a contract to sell the commodity. As of
March 31, 2009, we had net long commodity contracts outstanding in the following
quantities:
|
|
Commodity
contracts (in Bcf)
|
|
Hedge
designation under SFAS 133
|
|
Distribution
operations
|
|
|
Retail
energy operations
|
|
|
Wholesale
services
|
|
|
Consolidated
|
|
Cash
flow
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
9
|
|
Not
designated
|
|
|
11
|
|
|
|
13
|
|
|
|
199
|
|
|
|
223
|
|
Total
|
|
|
11
|
|
|
|
22
|
|
|
|
199
|
|
|
|
232
|
|
Derivative
Financial Instruments on the
Condensed
Consolidated Statements of
Income
The
following table presents the gain or (loss) on derivative financial
instruments in our condensed consolidated statements of income for the three
months ended March 31, 2009.
|
|
Three
months ended
March
31, 2009
|
|
In
millions
|
|
Retail
energy operations
|
|
|
Wholesale
services
|
|
|
|
|
|
|
|
|
Designated
as cash flow hedges under SFAS 133
|
|
|
|
|
|
|
Commodity
contracts – loss reclassified from OCI into cost of gas for settlement of
hedged item
|
|
$
|
(4
|
)
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Not
designated as hedges under SFAS 133:
|
|
|
|
|
|
|
|
|
Commodity
contracts – fair value adjustments recorded in operating revenues
(1)
|
|
|
-
|
|
|
|
20
|
|
Commodity
contracts – fair value adjustments recorded in cost of gas
(2)
|
|
|
(1
|
)
|
|
|
-
|
|
Total
(losses) gains on derivative financial instruments
|
|
$
|
(5
|
)
|
|
$
|
20
|
|
(1)
Associated with the fair value of existing derivative financial instruments at
March 31, 2009.
(2)
Excludes $4 million of losses recorded in cost of gas associated with weather
derivatives accounted for in accordance with EITF 99-02.
In
accordance with regulatory requirements, any realized gains and losses on
derivative financial instruments used in our distribution operations
segment are reflected in deferred natural gas costs within our condensed
consolidated statements of financial position. In the three months ended March
31, 2009, Elizabethtown Gas recognized $13 million of losses on its derivative
financial instruments and less than $1 million in gains for the same period in
2008.
The
following amounts (pre-tax) represent the expected recognition in our condensed
consolidated statements of income of the deferred losses recorded in OCI
associated with retail energy operations’ derivative financial instruments,
based upon the fair values of these financial instruments as of March 31,
2009:
In
millions
|
|
Retail
energy operations
|
|
Designated
as hedges under SFAS 133
|
|
|
|
Commodity
contracts – expected net loss reclassified from OCI into cost of gas for
settlement of hedged item:
|
|
|
|
Next
twelve months
|
|
$
|
(27
|
)
|
Thereafter
|
|
|
-
|
|
Total
|
|
$
|
(27
|
)
|
Derivative F
inancial Instruments on the
Statements of Financial
Position
The
following table presents the fair value and statements of financial position
classification of our derivative financial instruments by operating segment as
of March 31, 2009.
|
|
|
As
of March 31, 2009
|
|
In
millions
|
Statements
of financial position location
(1)
|
|
Distribution
operations
|
|
|
Retail
energy operations
|
|
|
Wholesale
services
|
|
|
Consolidated
(
2
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated
as cash flow hedges under SFAS 133:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
commodity contracts
|
Derivative
financial instruments assets and liabilities – current
portion
|
|
$
|
-
|
|
|
$
|
12
|
|
|
$
|
-
|
|
|
$
|
12
|
|
Noncurrent
commodity contracts
|
Derivative
financial instruments assets and liabilities
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
Liability
Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
commodity contracts
|
Derivative
financial instruments assets and liabilities – current
portion
|
|
|
-
|
|
|
|
(32
|
)
|
|
|
-
|
|
|
|
(32
|
)
|
Noncurrent
commodity contracts
|
Derivative
financial instruments assets and liabilities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
|
-
|
|
|
|
(20
|
)
|
|
|
-
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not
designated as hedges under SFAS 133:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
commodity contracts
|
Derivative
financial instruments assets and liabilities – current
portion
|
|
|
23
|
|
|
|
3
|
|
|
|
520
|
|
|
|
546
|
|
Noncurrent
commodity contracts
|
Derivative
financial instruments assets and liabilities
|
|
|
6
|
|
|
|
-
|
|
|
|
85
|
|
|
|
91
|
|
Liability
Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
commodity contracts
|
Derivative
financial instruments assets and liabilities – current
portion
|
|
|
(23
|
)
|
|
|
(5
|
)
|
|
|
(535
|
)
|
|
|
(563
|
)
|
Noncurrent
commodity contracts
|
Derivative
financial instruments assets and liabilities
|
|
|
(6
|
)
|
|
|
-
|
|
|
|
(63
|
)
|
|
|
(69
|
)
|
Total
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
7
|
|
|
|
5
|
|
Total
derivative financial instruments
|
|
|
$
|
-
|
|
|
$
|
(22
|
)
|
|
$
|
7
|
|
|
$
|
(15
|
)
|
(1)
|
These
amounts are netted within our condensed consolidated statements of
financial position. Some of our derivative financial instruments have
asset positions which are presented as a liability in our condensed
consolidated statements of financial position, and we have derivative
instruments that have liability positions which are presented as an asset
in our condensed consolidated statements of financial
position.
|
(2)
|
As
required by SFAS 161, the fair value amounts above are presented on a
gross basis. Additionally, the amounts above do not include
$214 million of cash collateral held on deposit in broker margin
accounts as of March 31, 2009. As a result, the amounts above will differ
from the amounts presented on our condensed consolidated statements of
financial position, and the fair value information presented for our
financial instruments in
Note
2
.
|
FSP
FAS 132(R)-1
This FSP
requires additional disclosures relating to postretirement benefit plan assets
to provide transparency regarding the types of assets and the associated risks
within the types of plan assets. The required disclosures include:
·
|
How
investment allocation decisions are made, including information that
provides an understanding of investment policies and
strategies,
|
·
|
The
major categories of plan assets,
|
·
|
Inputs
and valuation techniques used to measure the fair value of plan assets,
including those measurements using significant unobservable inputs, on
changes in plan assets for the period,
and
|
·
|
Significant
concentrations of risk within plan
assets.
|
This FSP
is effective for fiscal years ending after December 15, 2009 and requires
additional disclosures in our notes to condensed consolidated financial
statements, but will not have a material impact on our financial position,
results of operations or cash flows.
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. Following are the combined cost components of our two defined
pension plans for the periods indicated.
|
|
Three
months ended
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest
cost
|
|
|
7
|
|
|
|
7
|
|
Expected
return on plan assets
|
|
|
(7
|
)
|
|
|
(8
|
)
|
Amortization
of prior service cost
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Recognized
actuarial loss
|
|
|
2
|
|
|
|
1
|
|
Net
pension benefit cost
|
|
$
|
3
|
|
|
$
|
1
|
|
Our
employees do not contribute to these 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
contained 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. In December 2008, the Worker, Retiree and Employer
Recovery Act of 2008 allowed us to measure our 2008 and 2009 funding target at
92%. During the first three months of 2009, we made a $14 million contribution
to our qualified plans. We expect to make additional contributions to our
pension plans of $18 million during the remainder of 2009. In 2008, we did not
make a contribution, as one was not required for our pension plans.
Postretirement Benefits
The
Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources
Inc. (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. Eligibility for benefits under the AGL Postretirement Plan is
based on age and years of service. 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. Medicare-eligible
participants in the AGL Postretirement Plan receive prescription drug benefits
through a Medicare Part D plan offered by a third party and to which we
subsidize participant premiums. Medicare-eligible retirees who opt out of the
AGL Postretirement Plan are eligible to receive a cash subsidy which may be used
towards eligible prescription drug expenses.
Following
are the cost components of the AGL Postretirement Plan for the periods
indicated.
|
|
Three
months ended
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$
|
-
|
|
|
$
|
-
|
|
Interest
cost
|
|
|
1
|
|
|
|
1
|
|
Expected
return on plan assets
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Amortization
of prior service cost
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Recognized
actuarial loss
|
|
|
1
|
|
|
|
-
|
|
Net
postretirement benefit cost
|
|
$
|
-
|
|
|
$
|
(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 $2 million in
matching contributions to participant accounts in the first three months of 2009
and $2 million in the same period last year.
Noncontrolling
Interests
We
currently own a noncontrolling 70% financial interest in SouthStar, a joint
venture with Piedmont who owns the remaining 30%. Our 70% interest is
noncontrolling because all significant management decisions require approval by
both owners. Although our ownership interest in the SouthStar partnership is
70%, under an amended and restated joint venture agreement executed in March
2004, SouthStar's earnings are allocated 75% to us and 25% to Piedmont except
for earnings related to customers in Ohio and Florida, which are allocated 70%
to us and 30% to Piedmont.
We are
the primary beneficiary of SouthStar’s activities and have determined that
SouthStar is a variable interest entity as defined by FIN 46R which requires us
to consolidate the variable interest entity. The assets, liabilities, and
noncontrolling interests of a consolidated variable interest entity are
accounted for in our condensed consolidated financial statements as if the
entity were consolidated based on voting interests.
The
Company determined that SouthStar was a variable interest entity because its
equal voting rights with Piedmont are not proportional to its economic
obligation to absorb 75% of any losses or residual returns from SouthStar,
except those losses and returns related to customers in Ohio and Florida. In
addition, SouthStar obtains substantially all its transportation capacity for
delivery of natural gas through our wholly-owned subsidiary, Atlanta Gas
Light.
On
January 1, 2009, we adopted SFAS 160, and applied the presentation and
disclosure requirements retrospectively for all periods presented. SFAS 160 does
not change the requirements of FIN 46R and provides that the noncontrolling
interest should be reported as a separate component of equity on our condensed
consolidated statements of financial position.
Additionally, prior to adoption of SFAS
160, we recorded our earnings allocated to Piedmont as a component of earnings
before income taxes in our condensed consolidated statements of income. SFAS 160
requires that any net income attributable to the noncontrolling interest be
presented separately in our condensed consolidated statements of income. As a
result, net income from noncontrolling interest is reported after net income in
order to report net income attributable to the parent and the noncontrolling
interest. The adoption of SFAS 160 has no effect on our calculation of basic or
diluted earnings per share amounts, which will continue to be based upon amounts
attributable to AGL Resources.
The March
2004 amended and restated joint venture agreement includes a series of options
granting us the evergreen opportunity to purchase all or a portion of Piedmont’s
ownership interest in SouthStar. We have the right to exercise an option to
purchase on or before November of each year, with the purchase being effective
as of January 1, of the following year. We currently have two vested options to
purchase a portion of Piedmont’s ownership interest (33 1/3% and 50%,
respectively). Effective January 1, 2010, our option vests to purchase up to
100% of Piedmont’s ownership interest. If we were to exercise any option to
purchase less than 100% of Piedmont’s ownership interest in SouthStar, Piedmont,
at its discretion, could require us to purchase their entire ownership interest.
The purchase price, in any exercise of our option, would be based on the then
current fair market value of SouthStar. SFAS 160 requires that increases in our
ownership interest are recorded as equity transactions, with no adjustment to
the carrying amounts of the assets and liabilities. Piedmont has challenged our
interpretation of the duration of the various options in the amended and
restated agreement as described in Note 7.
Stock-Based
Compensation
In the
first three months of 2009, we issued grants of approximately 250,000 stock
options and 211,000 restricted stock units, which will result in the recognition
of approximately $2 million of stock-based compensation expense in 2009. 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, 2008.
Comprehensive
Income
Our
comprehensive income includes net income plus OCI, which includes other gains
and losses affecting 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 overfunded pension and postretirement obligation
adjustments.
Our
issuance of various securities, including long-term and short-term debt, is
subject to customary approval or authorization by, or filings with, state and
federal regulatory bodies, including state public service commissions, the SEC
and the FERC pursuant to the Energy Policy Act of 2005. The following table
provides more information on our various debt securities. For more information
on our debt, see Note 6 in Item 8 of our Annual Report on Form 10-K for the year
ended December 31, 2008.
|
|
|
|
|
|
|
|
Weighted
|
|
|
Outstanding
as of
|
|
In
millions
|
|
Year(s)
due
|
|
|
Interest
rate
(1)
|
|
|
average
interest rate
(2)
|
|
|
Mar.
31,
2009
|
|
|
Dec.
31,
2008
|
|
|
Mar.31,
2008
|
|
Short-term
debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial
paper & Credit Facilities
|
|
2009
|
|
|
|
0.9
|
%
|
|
|
1.2
|
%
|
|
$
|
335
|
|
|
$
|
773
|
|
|
$
|
213
|
|
SouthStar
line of credit
|
|
2009
|
|
|
|
1.1
|
|
|
|
1.1
|
|
|
|
45
|
|
|
|
75
|
|
|
|
-
|
|
Sequent
lines of credit
|
|
2009
|
|
|
|
0.9
|
|
|
|
0.9
|
|
|
|
22
|
|
|
|
17
|
|
|
|
31
|
|
Pivotal
Utility line of credit
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
Current
portion of long-term debt
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
114
|
|
Capital
leases
|
|
2009
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Total
short-term debt
|
|
|
|
|
|
|
1.0
|
%
|
|
|
1.1
|
%
|
|
$
|
403
|
|
|
$
|
866
|
|
|
$
|
369
|
|
Long-term
debt - net of current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
notes
|
|
|
2011-2034
|
|
|
|
4.5-7.1
|
%
|
|
|
5.9
|
%
|
|
$
|
1,275
|
|
|
$
|
1,275
|
|
|
$
|
1,275
|
|
Gas
facility revenue bonds
|
|
|
2022-2033
|
|
|
|
0.2-5.3
|
|
|
|
1.3
|
|
|
|
200
|
|
|
|
200
|
|
|
|
40
|
|
Medium-term
notes
|
|
|
2012-2027
|
|
|
|
6.6-9.1
|
|
|
|
7.8
|
|
|
|
196
|
|
|
|
196
|
|
|
|
196
|
|
Capital
leases
|
|
2013
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
4
|
|
|
|
4
|
|
|
|
5
|
|
Total
long-term debt
|
|
|
|
|
|
|
5.5
|
%
|
|
|
5.5
|
%
|
|
$
|
1,675
|
|
|
$
|
1,675
|
|
|
$
|
1,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
debt
|
|
|
|
|
|
|
4.6
|
%
|
|
|
4.3
|
%
|
|
$
|
2,078
|
|
|
$
|
2,541
|
|
|
$
|
1,885
|
|
(1)
|
As
of March 31, 2009
|
(2)
|
For
the three months ended March 31, 2009.
|
Contractual
Obligations and Commitments
We have
incurred various contractual obligations and financial commitments in the normal
course of our operating and financing activities that are reasonably likely to
have a material effect on liquidity or the availability of capital resources.
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. As we do for other subsidiaries, we provide guarantees to certain
gas suppliers for SouthStar in support of payment obligations. 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, 2008.
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 March 31, 2009.
|
|
Commitments
due before
Dec.
31,
|
|
In
millions
|
|
Total
|
|
|
2009
|
|
|
2010
& thereafter
|
|
Standby
letters of credit and performance and surety bonds
|
|
$
|
51
|
|
|
$
|
45
|
|
|
$
|
6
|
|
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
condensed consolidated financial position, results of operations or cash
flows.
Information
on 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, 2008. In April 2009,
the trial court ruled that the legislation that restricted Jefferson Island's
ability to use water from the Chicot aquifer to expand its existing storage
facility is unconstitutional and invalid. In addition, the court scheduled a
trial in September 2009 on Jefferson Island's claim that it is authorized to
expand the facility under its mineral lease. The ultimate resolution of such
litigation cannot be determined, but it is not expected to have a material
adverse effect on our condensed consolidated financial position, results of
operations or cash flows.
In March
2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware
against GNGC, asking the court to enter a judgment declaring that GNGC’s right
to purchase Piedmont’s ownership interest in SouthStar expires on November 1,
2009. We believe that, under the March 2004 amended and restated joint venture
agreement, GNGC has the evergreen opportunity, throughout the term of the joint
venture, to exercise its options to purchase a portion of, or all of, Piedmont’s
interest in SouthStar by notifying Piedmont on or before November 1, of each
year, with the purchase being effective as of January 1 of the following year.
The ultimate resolution of this litigation cannot be determined, but we believe
that the dispute will be resolved before our next option exercise notification
date on November 1, 2009.
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 statements of consolidated income for the year ended
December 31, 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
October 2008, the plaintiffs appealed the dismissal of the lawsuit and the
Georgia Court of Appeals heard oral arguments in 2009. GNG is awaiting the
Georgia Court of Appeal’s ruling on the lawsuit.
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. This lawsuit was dismissed with prejudice in March 2009. In
April 2009, plaintiffs appealed the dismissal of the lawsuit.
Review
of Compliance with FERC Regulations
In 2008
we 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 and continue to meet
with the FERC Enforcement staff to discuss with them these instances of possible
non-compliance. Accordingly we have accrued an appropriate estimate of possible
penalties assessed by the FERC. While we continue to adjust this estimate as
more information becomes available, the estimate does not have, and management
does not believe the ultimate resolution will have, a material financial impact
to our condensed consolidated results of operations, cash flows or financial
position.
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 and other income and expenses. 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 attributable to
AGL Resources Inc. 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 attributable to AGL Resources Inc.
for the three months ended March 31, 2009 and 2008.
|
|
Three
months ended
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Operating
revenues
|
|
$
|
995
|
|
|
$
|
1,012
|
|
Operating
expenses
|
|
|
765
|
|
|
|
824
|
|
Operating
income
|
|
|
230
|
|
|
|
188
|
|
Other
income
|
|
|
2
|
|
|
|
1
|
|
EBIT
|
|
|
232
|
|
|
|
189
|
|
Interest
expense, net
|
|
|
(25
|
)
|
|
|
(30
|
)
|
Earnings
before income taxes
|
|
|
207
|
|
|
|
159
|
|
Income
tax expense
|
|
|
72
|
|
|
|
54
|
|
Net
income
|
|
|
135
|
|
|
|
105
|
|
Net
income attributable to the noncontrolling interest
|
|
|
16
|
|
|
|
16
|
|
Net
income attributable to AGL Resources Inc.
|
|
$
|
119
|
|
|
$
|
89
|
|
Statements
of financial position information at December 31, 2008, is as
follows:
In
millions
|
|
Identifiable
and total assets (1)
|
|
|
Goodwill
|
|
Distribution
operations
|
|
$
|
5,138
|
|
|
$
|
404
|
|
Retail
energy operations
|
|
|
315
|
|
|
|
-
|
|
Wholesale
services
|
|
|
970
|
|
|
|
-
|
|
Energy
investments
|
|
|
353
|
|
|
|
14
|
|
Corporate and intercompany
eliminations
(2)
|
|
|
(66
|
)
|
|
|
-
|
|
Consolidated
AGL Resources Inc.
|
|
$
|
6,710
|
|
|
$
|
418
|
|
(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 months ended
March 31, 2009 and 2008, by segment, are shown in the following
tables.
Three
months ended March 31, 2009
In
millions
|
|
Distribution
operations
|
|
|
Retail
energy operations
|
|
|
Wholesale
services
|
|
|
Energy
investments
|
|
|
Corporate
and intercompany eliminations
(3)
|
|
|
Consolidated
AGL Resources
|
|
Operating
revenues from external parties
|
|
$
|
572
|
|
|
$
|
343
|
|
|
$
|
68
|
|
|
$
|
10
|
|
|
$
|
2
|
|
|
$
|
995
|
|
Intercompany
revenues
(1)
|
|
|
35
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(35
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
607
|
|
|
|
343
|
|
|
|
68
|
|
|
|
10
|
|
|
|
(33
|
)
|
|
|
995
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
355
|
|
|
|
259
|
|
|
|
9
|
|
|
|
-
|
|
|
|
(34
|
)
|
|
|
589
|
|
Operation
and maintenance
|
|
|
83
|
|
|
|
20
|
|
|
|
19
|
|
|
|
5
|
|
|
|
(2
|
)
|
|
|
125
|
|
Depreciation
and amortization
|
|
|
32
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
3
|
|
|
|
39
|
|
Taxes
other than income taxes
|
|
|
9
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
12
|
|
Total
operating expenses
|
|
|
479
|
|
|
|
280
|
|
|
|
30
|
|
|
|
8
|
|
|
|
(32
|
)
|
|
|
765
|
|
Operating
income (loss)
|
|
|
128
|
|
|
|
63
|
|
|
|
38
|
|
|
|
2
|
|
|
|
(1
|
)
|
|
|
230
|
|
Other
income
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
EBIT
|
|
$
|
130
|
|
|
$
|
63
|
|
|
$
|
38
|
|
|
$
|
2
|
|
|
$
|
(1
|
)
|
|
$
|
232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
and total assets
(2)
|
|
$
|
5,095
|
|
|
$
|
261
|
|
|
$
|
653
|
|
|
$
|
373
|
|
|
$
|
(225
|
)
|
|
$
|
6,157
|
|
Goodwill
|
|
$
|
404
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
14
|
|
|
$
|
-
|
|
|
$
|
418
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
69
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
23
|
|
|
$
|
5
|
|
|
$
|
97
|
|
Three
months ended March 31, 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
|
|
$
|
610
|
|
|
$
|
375
|
|
|
$
|
17
|
|
|
$
|
11
|
|
|
$
|
(1
|
)
|
|
$
|
1,012
|
|
Intercompany
revenues
(1)
|
|
|
66
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(66
|
)
|
|
|
-
|
|
Total
operating revenues
|
|
|
676
|
|
|
|
375
|
|
|
|
17
|
|
|
|
11
|
|
|
|
(67
|
)
|
|
|
1,012
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of gas
|
|
|
428
|
|
|
|
293
|
|
|
|
2
|
|
|
|
-
|
|
|
|
(66
|
)
|
|
|
657
|
|
Operation
and maintenance
|
|
|
86
|
|
|
|
19
|
|
|
|
12
|
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
119
|
|
Depreciation
and amortization
|
|
|
31
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
36
|
|
Taxes
other than income taxes
|
|
|
9
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
12
|
|
Total
operating expenses
|
|
|
554
|
|
|
|
313
|
|
|
|
16
|
|
|
|
6
|
|
|
|
(65
|
)
|
|
|
824
|
|
Operating
income (loss)
|
|
|
122
|
|
|
|
62
|
|
|
|
1
|
|
|
|
5
|
|
|
|
(2
|
)
|
|
|
188
|
|
Other
income
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
EBIT
|
|
$
|
123
|
|
|
$
|
62
|
|
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
(2
|
)
|
|
$
|
189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
and total assets
(2)
|
|
$
|
4,769
|
|
|
$
|
296
|
|
|
$
|
968
|
|
|
$
|
287
|
|
|
$
|
(214
|
)
|
|
$
|
6,106
|
|
Goodwill
|
|
$
|
406
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
14
|
|
|
$
|
-
|
|
|
$
|
420
|
|
Capital
expenditures for property, plant and equipment
|
|
$
|
59
|
|
|
$
|
6
|
|
|
$
|
-
|
|
|
$
|
11
|
|
|
$
|
4
|
|
|
$
|
80
|
|
(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 $165 million and $273 million
for the three months ended March 31, 2009 and 2008,
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.
|
FORWARD-LOOKING
STATEMENTS
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 or otherwise release to the public and
on our website are forward-looking statements. Senior 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," "would," or similar expressions. You are cautioned not to place undue
reliance on our forward-looking statements. 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 including any changes
related to climate change; 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, including recent disruptions in the capital markets and lending
environment and the current economic downturn; and general economic conditions;
uncertainties about environmental issues and the related impact of such issues;
the impact of changes in weather, including climate change, 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, 2008, among others, could
cause our business, results of operations or financial condition in 2009 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 three months ended March 31, 2009, our
six utilities serve approximately 2.3 million 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.
We intend
to continue executing our plan for long-term earnings and dividend growth.
Central to that plan is the execution of our regulatory strategy through the
filing of rate cases to recover the investments we have made, and should
continue to make, to enhance our infrastructure and improve customer service.
Further, we are collaborating with regulatory agencies and other companies to
promote and encourage conservation through innovative rate design mechanisms
that we believe are positioning our utility businesses to benefit in an economic
recovery.
We
continue to explore select opportunities to expand our businesses in strategic
areas and maintain a disciplined approach around current capital projects. Our
major capital projects - our Golden Triangle Storage natural gas storage
facility project and our Hampton Roads Crossing and Magnolia pipeline connection
projects - are on schedule and within budget. In these challenging economic
conditions we continue to aggressively focus on capital discipline and cost
control, while moving ahead with projects and initiatives that we expect to have
current and future benefits and provide an appropriate return on
capital.
Our
distribution operations segment is the largest component of our business and
includes six natural gas local distribution utilities. These utilities
construct, manage and maintain intrastate natural gas pipelines and distribution
facilities and include:
·
|
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. Rate base generally consists of the original cost
of utility plant in service, working capital and certain other assets; less
accumulated depreciation on utility plant in service and net deferred income tax
liabilities, and may include certain other additions or deductions.
Customer
growth declined slightly in our distribution operations segment in the first
three months of 2009 relative to last year, a trend we expect to continue
through 2009. For the three months ended March 31, 2009, our year-over-year
consolidated utility customer growth rate was slightly negative or (0.1)%,
compared to 0.3% for the same period of 2008. We anticipate overall customer
growth in 2009 to be flat to negative, primarily as a result of much slower
growth in the residential housing markets throughout most of our service
territories and the effects of a weak economy on our commercial and industrial
customers. Over the last 3 years we have reduced our customer attrition rates.
As a result, we believe we should be well positioned when the economy
recovers.
The weak
economy also impacted a significantly larger portion of consumer household
incomes during the most recent winter heating season. As a result, we incurred
additional bad debt expense and increased customer conservation. We expect these
factors may continue to adversely impact our results of operations during
the current economic situation. However, we expect operational and collections
efforts combined with regulatory mechanisms in place in most of our
jurisdictions to help mitigate some of our exposure to these
factors.
The 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 Marketers rather than from Atlanta Gas Light. Our credit
exposure at Atlanta Gas Light is primarily related to the provision of services
to the Marketers, but that exposure is mitigated, because we obtain security
support in an amount equal to a minimum of no less than two times a Marketer’s
highest month’s estimated bill. At our other utilities, while customer
conservation could adversely
impact our operating
margins, we utilize measures to collect delinquent accounts and continue to be
rigorous in monitoring and mitigating the impact of these expenses. Due to the
timing of usage and billing, the full effects of the most recent heating season
will not be known until several months following the end of the heating
season.
We worked
with regulators and state agencies in each of our jurisdictions to educate
customers about higher energy costs in advance of the winter heating season, in
particular, to ensure that those customers qualified for the Low Income Home
Energy Assistance Program and other similar programs receive any needed
assistance and we expect to continue this focus for the foreseeable
future.
Upcoming rate
cases
In 2009 and 2010, we expect to file base rate cases in four of our
six jurisdictions. Over the past several years our utilities have been
fulfilling their long-term commitments to rate freezes, which begin expiring in
2009. As these rate cases are filed, we plan to seek rate reforms that encourage
conservation and “decoupling.” In traditional rate designs, our utilities’
recovery of a significant portion of their fixed customer service costs is tied
to assumed natural gas volumes used by our customers. We believe separating, or
decoupling, the recovery of these fixed costs from the natural gas deliveries
will align the interests of our customers and utilities by encouraging energy
conservation, achieving rate stability for our customers and ensuring stable
returns for our shareholders. 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 expected to be effective are outlined in the chart
below:
Company
|
|
Expected
filing
date
|
|
|
Current
rates effective until
|
|
Atlanta
Gas Light
|
|
|
Q4
2009
|
|
|
|
Q2
2010
|
|
Virginia
Natural Gas
|
|
|
Q2
2010
|
|
|
|
Q3
2011
|
|
Chattanooga
Gas
|
|
|
Q2
2010
|
|
|
|
Q1
2011
|
|
Elizabethtown Gas
After a 5-year rate freeze and in accordance with the New Jersey
Commission’s order, we filed a rate case in March 2009 with a proposed effective
date of January 1, 2010. We are requesting an annual increase to base rates of
$25 million. This filing included energy conservation programs and a proposed
Efficiency Usage and Adjustment mechanism (EUA), which is a form of decoupling.
If the EUA is approved, the current weather normalization clause would be
eliminated. Our requested increase consists of:
·
|
increased
carrying costs and depreciation expense associated with increased rate
base ($15 million)
|
·
|
increased
operating expenses, including higher bad debt expenses and other ($6
million)
|
·
|
increased
return on equity from 10% to 11.25% and return on rate base from 7.95% to
8.57% ($4 million)
|
In
January 2009, and in response to New Jersey Governor Corzine’s call for
utilities to assist in the economic recovery by increasing infrastructure
investments, Elizabethtown Gas proposed an accelerated $60 million enhanced
infrastructure program over the next two years. In April 2009, the New Jersey
Commission approved a stipulation between Elizabethtown Gas and certain
intervenors to the case. Under the stipulation, the infrastructure program
should begin in 2009 and end in 2011, unless extended by the New Jersey
Commission. A regulatory cost recovery mechanism will be established with
estimated rates put into effect at the beginning of each year. At the end of the
program the regulatory cost recovery mechanism will be trued-up and any
remaining costs not previously collected will be included in base
rates.
Atlanta Gas Light
In March 2009 the Georgia Commission approved a new economic development
and environmental program developed by Atlanta Gas Light to encourage smart new
investment in Georgia. The new program, Georgia Sustainable Environmental
Economic Development (Georgia SEED), is designed to attract and retain jobs,
support projects to reduce carbon emissions and encourage new investment in
Georgia.
Under
Georgia SEED, Atlanta Gas Light will contract with new and existing business
customers that may be considering expanding into Georgia. Atlanta Gas Light will
have the option to invest capital to help customers finance line extensions, new
natural gas equipment and equipment installations. This is a five-year
experimental program and offers three potential avenues for
contracts:
·
|
Providing
customers with the benefit of a new utility service extension to plant
sites;
|
·
|
Offering
financing for the purchase and installation of new higher-efficiency gas
equipment, such as engines, boilers, fleet vehicles, refueling stations
and gas-fired air conditioning equipment;
and
|
·
|
Discounting
utility rates to help lower overall energy
costs.
|
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 34% 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 noncontrolling interest in our condensed consolidated statements
of income, and we record Piedmont’s portion of SouthStar’s capital as a
noncontrolling interest in our condensed consolidated statements of financial
position. The majority of SouthStar’s earnings allocated to us for the three
months ended March 31, 2009, were at the 75% contractual rate.
Our
amended and restated joint venture agreement with Piedmont includes a series of
options granting us the evergreen opportunity to purchase all or a portion of
Piedmont’s ownership interest in SouthStar. We have the right to exercise an
option to purchase on or before November of each year, with the purchase being
effective as of January 1, of the following year. We currently have options to
purchase up to 50% of Piedmonts’ ownership interest. Effective November 1, 2009,
the option allows us to purchase 100% of Piedmont’s ownership interest. If we
were to exercise any option to purchase less than 100% of Piedmont’s ownership
interest in SouthStar, Piedmont, at its discretion, could require us to purchase
their entire ownership interest. The purchase price, in any exercise of our
option, would be based on the then current fair market value of SouthStar. In
March 2009, Piedmont filed a lawsuit against GNGC regarding GNGC’s right to
purchase Piedmont’s interest in SouthStar. See Note 7 of the financial
statements for additional information.
SouthStar’s
operations are sensitive to seasonal weather, natural gas prices, retail pricing
plans and strategies, 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.
In the
Georgia market, we have experienced and expect through 2009 that we will
experience the negative impact to operating margins from increased competition
and an increase in the number of customers shopping for lower retail natural gas
prices. Further, the number of customers switching Marketers in the Georgia
market has increased in part due to customers seeking the most competitive price
plans.
SouthStar
continues to use a variety of targeted marketing programs to attract new
customers and to retain existing ones. These programs emphasize GNG as the
Marketer of choice. Despite these efforts we have seen a 3% decline in average
customer count at SouthStar for the three months ended March 31, 2009, as
compared to the same period of 2008. We believe this decline reflects some of
the same economic conditions that have affected our utility businesses as well
as the more competitive retail pricing market for natural gas in
Georgia.
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, lower wholesale natural gas prices, disciplined collection
practices and the unregulated pricing structure in Georgia.
SouthStar
continues to expand its business in other states as well. We are currently
focusing these efforts on Ohio and Florida, which are growing more rapidly than
anticipated.
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. This agreement was executed in April 2009, and as a result, we have
included approximately $89 million of future demand payments associated with
this capacity within our unrecorded contractual obligations and commitment
disclosures. As with its other transportation capacity agreements, Sequent has
and will identify opportunities to lock-in economic value associated with this
capacity through the use of financial hedges. Since the duration of this
agreement is significantly longer than the average duration of Sequent’s
portfolio, the hedging of the capacity has increased our exposure to hedge gains
and losses as well as impacting Sequent’s VaR. During the second half of 2008 we
began executing hedging transactions related to this transportation capacity. As
a result of changes in the fair value of these hedges, Sequent reported hedge
gains of $19 million during the first quarter of 2009. There was no significant
impact to VaR during the period.
Asset management
transactions
Sequent’s asset management customers include affiliated
utilities, nonaffiliated utilities, municipal utilities, power generators and
large industrial customers. These customers, due to seasonal demand or levels of
activity, may have contracts for transportation and storage capacity, which may
exceed their actual requirements. Sequent enters into structured agreements with
these customers, whereby Sequent, on behalf of the customer, optimizes the
transportation and storage capacity during periods when customers do not use it
for their own needs. Sequent may capture incremental operating margin through
optimization, and either share margins with the customers or pay them a fixed
amount.
In 2009,
Sequent extended its asset management agreement with Virginia Natural Gas for
three additional years. The new agreement includes a tiered structure of profit
sharing along with guaranteed annual minimums. With this renewal, Sequent has
completed renewal of all its affiliated asset management contracts for
multi-year periods.
The
following table provides updated information on Sequent’s asset management
agreements with its affiliated utilities, including amended or extended
agreements in 2008 and 2009 with Florida City Gas, Chattanooga Gas,
Elizabethtown Gas and Virginia Natural Gas.
|
|
|
%
of shared
|
|
|
Expiration
date
|
|
profits
or annual fee
|
|
Virginia
Natural Gas
|
March
2012
|
|
(A)
(B)
|
|
Chattanooga
Gas
|
March
2011
|
|
|
50%
(B)
|
|
Elizabethtown
Gas
|
March
2011
|
|
(A)
(B)
|
|
Atlanta
Gas Light
|
March
2012
|
|
up
to 60% (B)
|
|
Florida
City Gas
|
March
2013
|
|
|
50%
|
|
(A)
|
Shared
on a tiered structure.
|
(B)
|
Includes
aggregate annual minimum payments of $14 million for Chattanooga Gas,
Elizabethtown Gas, Virginia Natural Gas and Atlanta Gas
Light.
|
Storage inventory
outlook
The following graph presents the NYMEX forward natural gas prices
as of March 31, 2009 and December 31, 2008, for the period of April 2009 through
March 2010, and reflects the prices at which Sequent could buy natural gas at
the Henry Hub for delivery in the same time period. The Henry Hub is the largest
centralized point for natural gas spot and futures trading in the United States.
The NYMEX uses the Henry Hub as the point of delivery for its natural gas
futures contracts. Many natural gas marketers also use the Henry Hub as their
physical contract delivery point or their price benchmark for spot trades of
natural gas.
During
the last half of 2008 and continuing into 2009, natural gas prices declined
significantly, reflecting the decline in the U.S. economy, increasing natural
gas supplies and above-average storage volumes, among other factors. These lower
gas prices expected for 2009, as reflected in the NYMEX forward curve, would
result in significantly lower levels of working capital necessary for Sequent to
purchase its natural gas inventories as compared to 2008, which saw
significantly higher prices.
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 March 31, 2009. 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
$3.96)
|
|
|
Reservoir
(WACOG
$2.94)
|
|
|
Expected
operating revenues
(in
millions)
|
|
2009
|
|
|
|
|
|
|
|
|
|
Second
quarter
|
|
|
-
|
|
|
|
1
|
|
|
$
|
1
|
|
Third
quarter
|
|
|
2
|
|
|
|
2
|
|
|
|
2
|
|
Fourth
quarter
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
First
quarter
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
Total
|
|
|
2
|
|
|
|
5
|
|
|
$
|
5
|
|
If
Sequent’s storage withdrawals associated with existing inventory positions are
executed as planned, it expects operating revenues from storage withdrawals of
approximately $5 million during the next twelve months. 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. 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.
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 facility 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 7 to our Consolidated Financial Statements in
Item 8 of our Annual Report on Form 10-K for the year ended December 31,
2008. In April 2009, the trial court ruled that the legislation
restricting water usage from the Chicot aquifer to expand its existing storage
facility is unconstitutional and invalid. In addition, the court scheduled a
trial for September 28, 2009 on Jefferson Island's claim that it is authorized
to expand the facility under its mineral lease. The ultimate resolution of such
trial 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.
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 both caverns, with the first expected to be in service in the
third quarter of 2010 and the second cavern in the second quarter of 2012. 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 and materials 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
approximately 57% 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.
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. Operating margin is 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. EBIT is also a non-GAAP measure that includes
operating income, other income and expenses. 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.
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 billed
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 operating margin 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 operating income, or net
income attributable to AGL Resources Inc. 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 statement of financial position 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 statement of financial position as of
March 31, 2008, to provide comparisons of these items to December 31, 2008, and
March 31, 2009.
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 fair value 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 deferred
natural 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 statements of financial
position.
The
following table sets forth a reconciliation of our operating margin and EBIT to
our operating income, earnings before income taxes and net income attributable
to AGL Resources Inc., together with other consolidated financial information
for the three months ended March 31, 2009 and 2008.
|
|
Three
months ended March 31,
|
|
|
|
|
In
millions, except per share data
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
Operating
revenues
|
|
$
|
995
|
|
|
$
|
1,012
|
|
|
$
|
(17
|
)
|
Cost
of gas
|
|
|
589
|
|
|
|
657
|
|
|
|
(68
|
)
|
Operating
margin
(1)
|
|
|
406
|
|
|
|
355
|
|
|
|
51
|
|
Operating
expenses
|
|
|
176
|
|
|
|
167
|
|
|
|
9
|
|
Operating
income
|
|
|
230
|
|
|
|
188
|
|
|
|
42
|
|
Other
income
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
EBIT
(1)
|
|
|
232
|
|
|
|
189
|
|
|
|
43
|
|
Interest
expense, net
|
|
|
25
|
|
|
|
30
|
|
|
|
(5
|
)
|
Earnings
before income taxes
|
|
|
207
|
|
|
|
159
|
|
|
|
48
|
|
Income
tax expense
|
|
|
72
|
|
|
|
54
|
|
|
|
18
|
|
Net
income
|
|
|
135
|
|
|
|
105
|
|
|
|
30
|
|
Net
income attributable to the noncontrolling interest
|
|
|
16
|
|
|
|
16
|
|
|
|
-
|
|
Net
income attributable to AGL Resources Inc.
|
|
$
|
119
|
|
|
$
|
89
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
– attributable to AGL Resources Inc. common shareholders
|
|
$
|
1.55
|
|
|
$
|
1.17
|
|
|
$
|
0.38
|
|
Diluted
– attributable to AGL Resources Inc. common shareholders
|
|
$
|
1.55
|
|
|
$
|
1.16
|
|
|
$
|
0.39
|
|
Weighted-average
number of common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
76.7
|
|
|
|
76.0
|
|
|
|
0.7
|
|
Diluted
|
|
|
76.8
|
|
|
|
76.3
|
|
|
|
0.5
|
|
(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 months ended
March 31, 2009 and 2008, 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 customers’
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended Mar. 31,
|
|
|
2009
vs. normal colder
|
|
|
2009
vs. 2008 colder
|
|
|
|
Normal
|
|
|
2009
|
|
|
2008
|
|
|
(warmer)
|
|
|
(warmer)
|
|
Florida
|
|
|
332
|
|
|
|
369
|
|
|
|
197
|
|
|
|
11
|
%
|
|
|
87
|
%
|
Georgia
|
|
|
1,441
|
|
|
|
1,434
|
|
|
|
1,510
|
|
|
|
-
|
|
|
|
(5
|
)%
|
Maryland
|
|
|
2,510
|
|
|
|
2,612
|
|
|
|
2,339
|
|
|
|
4
|
%
|
|
|
12
|
%
|
New
Jersey
|
|
|
2,527
|
|
|
|
2,627
|
|
|
|
2,422
|
|
|
|
4
|
%
|
|
|
8
|
%
|
Tennessee
|
|
|
1,640
|
|
|
|
1,664
|
|
|
|
1,721
|
|
|
|
1
|
%
|
|
|
(3
|
)%
|
Virginia
|
|
|
1,800
|
|
|
|
1,988
|
|
|
|
1,601
|
|
|
|
10
|
%
|
|
|
24
|
%
|
(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 April 2000 through March
2009.
|
|
|
|
|
|
|
|
Customers
|
|
Three
months ended March 31,
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
%
change
|
|
Distribution
Operations
|
|
|
|
|
|
|
|
|
|
Average
end-use customers
(in
thousands)
|
|
|
|
|
|
|
|
|
|
Atlanta
Gas Light
|
|
|
1,577
|
|
|
|
1,582
|
|
|
|
(0.3
|
)%
|
Chattanooga
Gas
|
|
|
63
|
|
|
|
63
|
|
|
|
-
|
|
Elizabethtown
Gas
|
|
|
275
|
|
|
|
274
|
|
|
|
0.4
|
%
|
Elkton
Gas
|
|
|
6
|
|
|
|
6
|
|
|
|
-
|
|
Florida
City Gas
|
|
|
103
|
|
|
|
104
|
|
|
|
(1.0
|
)%
|
Virginia
Natural Gas
|
|
|
276
|
|
|
|
274
|
|
|
|
0.7
|
|
Total
|
|
|
2,300
|
|
|
|
2,303
|
|
|
|
(0.1
|
)%
|
Operation
and maintenance expenses per customer
|
|
$
|
36
|
|
|
$
|
37
|
|
|
|
(3
|
)%
|
EBIT
per customer
|
|
$
|
57
|
|
|
$
|
53
|
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
customers in Georgia
(in
thousands)
|
|
|
518
|
|
|
|
536
|
|
|
|
(3
|
)%
|
Market
share in Georgia
|
|
|
34
|
%
|
|
|
35
|
%
|
|
|
(3
|
)%
|
|
|
|
|
|
|
|
|
Volumes
|
|
Three
months ended March 31,
|
|
|
|
|
In
billion cubic feet (Bcf)
|
|
2009
|
|
|
2008
|
|
|
%
change
|
|
Distribution
Operations
|
|
|
|
|
|
|
|
|
|
Firm
|
|
|
99
|
|
|
|
98
|
|
|
|
1
|
%
|
Interruptible
|
|
|
26
|
|
|
|
29
|
|
|
|
(10
|
)%
|
Total
|
|
|
125
|
|
|
|
127
|
|
|
|
(2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Georgia
firm
|
|
|
18
|
|
|
|
19
|
|
|
|
(5
|
)%
|
Ohio
and Florida
|
|
|
5
|
|
|
|
2
|
|
|
|
150
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily
physical sales (Bcf/day)
|
|
|
3.1
|
|
|
|
2.7
|
|
|
|
15
|
%
|
|
First
quarter 2009 compared to first quarter 2008
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 March 31, 2009 and 2008.
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
607
|
|
|
$
|
252
|
|
|
$
|
124
|
|
|
$
|
130
|
|
Retail
energy operations
|
|
|
343
|
|
|
|
84
|
|
|
|
21
|
|
|
|
63
|
|
Wholesale
services
|
|
|
68
|
|
|
|
59
|
|
|
|
21
|
|
|
|
38
|
|
Energy
investments
|
|
|
10
|
|
|
|
10
|
|
|
|
8
|
|
|
|
2
|
|
Corporate
(2)
|
|
|
(33
|
)
|
|
|
1
|
|
|
|
2
|
|
|
|
(1
|
)
|
Consolidated
|
|
$
|
995
|
|
|
$
|
406
|
|
|
$
|
176
|
|
|
$
|
232
|
|
In
millions
|
|
Operating
revenues
|
|
|
Operating
margin (1)
|
|
|
Operating
expenses
|
|
|
EBIT(1)
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
operations
|
|
$
|
676
|
|
|
$
|
248
|
|
|
$
|
126
|
|
|
$
|
123
|
|
Retail
energy operations
|
|
|
375
|
|
|
|
82
|
|
|
|
20
|
|
|
|
62
|
|
Wholesale
services
|
|
|
17
|
|
|
|
15
|
|
|
|
14
|
|
|
|
1
|
|
Energy
investments
|
|
|
11
|
|
|
|
11
|
|
|
|
6
|
|
|
|
5
|
|
Corporate
(2)
|
|
|
(67
|
)
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(2
|
)
|
Consolidated
|
|
$
|
1,012
|
|
|
$
|
355
|
|
|
$
|
167
|
|
|
$
|
189
|
|
(1)
|
These
are non-GAAP measures. A reconciliation of operating margin and EBIT to
our
operating
income, earnings before income taxes and net income attributable to AGL
Resources Inc.
is
located in “Results of Operations”
herein.
|
(2)
|
Includes
intercompany eliminations.
|
For the
first quarter of 2009, net income attributable to AGL Resources Inc. increased
by $30 million and earnings per share attributable to AGL Resources Inc.
increased by $0.38 per basic and $0.39 per diluted share compared to the same
period last year. The variance between the two quarters was primarily the result
of higher operating margins offset by higher operating expenses largely a result
of higher incentive compensation costs due to higher earnings
Operating margin
Our operating margin for the first quarter of 2009 increased by $51
million or 14% compared to the same period last year. This increase was
primarily due to increased operating margins at wholesale services, supplemented
by higher operating margins in the distribution operations and retail energy
operations segments.
Distribution
operations’ operating margin increased by $4 million or 2% compared to last
year. The following table indicates the significant changes in distribution
operations’ operating margin for the three months ended March 31, 2009 compared
to 2008.
In
millions
|
|
|
|
Operating
margin for first quarter of 2008
|
|
$
|
248
|
|
Increased
margins from gas storage carrying amounts at Atlanta Gas
Light
|
|
|
3
|
|
Higher
PRP revenues at Atlanta Gas Light
|
|
|
2
|
|
Reduced
customer growth and usage
|
|
|
(1
|
)
|
Operating
margin for first quarter of 2009
|
|
$
|
252
|
|
Retail
energy operations’ operating margin increased by $2 million or 2%. The following
table indicates the significant changes in retail energy operations’ operating
margin for the three months ended March 31, 2009 compared to 2008.
In
millions
|
|
|
|
Operating
margin for first quarter of 2008
|
|
$
|
82
|
|
Higher
contributions from the management of storage and transportation assets
largely due to declining commodity prices in 2009
|
|
|
13
|
|
2008
pricing settlement with Georgia Commission
|
|
|
3
|
|
Higher
operating margins in Ohio and Florida
|
|
|
3
|
|
Average
customer usage
|
|
|
1
|
|
Change
in retail pricing plan mix and decrease in average number of
customers
|
|
|
(12
|
)
|
Inventory
LOCOM
|
|
|
(6
|
)
|
Operating
margin for first quarter of 2009
|
|
$
|
84
|
|
Wholesale
services’ operating margin increased $44 million compared to the first quarter
of 2008 primarily due to a $47 million increase in reported hedge gains as a
result of decreases in forward NYMEX natural gas prices and the narrowing of
transportation basis spreads in the current period compared to rising natural
gas prices and expanding transportation basis spreads in 2008. In addition,
commercial activity increased $5 million due to higher volatility in the
marketplace primarily associated with colder temperatures at the beginning of
the period. These increases were partially offset by an $8 million LOCOM
adjustment in the current period. The following table indicates the significant
changes in wholesale services’ operating margin for the three months ended March
31, 2009 and 2008.
In
millions
|
|
2009
|
|
|
2008
|
|
Commercial
activity
|
|
$
|
35
|
|
|
$
|
30
|
|
Gain
(loss) on transportation hedges
|
|
|
24
|
|
|
|
(4
|
)
|
Gain
(loss) on storage hedges
|
|
|
8
|
|
|
|
(11
|
)
|
Inventory
LOCOM
|
|
|
(8
|
)
|
|
|
-
|
|
Operating
margin
|
|
$
|
59
|
|
|
$
|
15
|
|
For more
information on Sequent’s expected operating revenues from its storage inventory
in the remainder of 2009 and in 2010 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 25.
Operating
Expenses
Our operating expenses for the first quarter of 2009 increased
$9 million or 5% as compared to the first quarter of 2008. The following table
indicates the significant changes in our operating expenses.
In
millions
|
|
|
|
|
Operating
expenses for first quarter of 2008
|
|
$
|
167
|
|
Increased
incentive compensation costs at wholesale services and retail energy
operations due to increased earnings
|
|
|
7
|
|
Increased
bad debt expense at distribution operations
|
|
|
1
|
|
Increased
depreciation expense at distribution operations and energy
investments
|
|
|
2
|
|
Increased
legal expenses related to Jefferson Island litigation
|
|
|
1
|
|
Other
|
|
|
2
|
|
Decreased
outside services, marketing and other expenses at distribution
operations
|
|
|
(4
|
)
|
Operating
expenses for first quarter of 2009
|
|
$
|
176
|
|
Interest Expense
Interest expense decreased by $5 million or 17% for the three months
ended March 31, 2009, 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 March 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
Average
debt outstanding (1)
|
|
$
|
2,333
|
|
|
$
|
2,098
|
|
|
$
|
235
|
|
Average
rate
|
|
|
4.3
|
%
|
|
|
5.7
|
%
|
|
|
(1.4
|
)%
|
(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 subsidiary lines of credit.
Additionally, from time to time, we raise funds from the public debt and equity
capital markets to fund our liquidity and capital resource needs.
Our
issuance of various securities, including long-term and short-term debt, is
subject to customary approval or authorization by, or filings with, state and
federal regulatory bodies including state public service commissions, the
SEC and the FERC. 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, 2008, 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.
|
|
Three
months ended Mar. 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Net
cash provided by (used in):
|
|
|
|
|
|
|
Operating
activities
|
|
$
|
611
|
|
|
$
|
511
|
|
Investing
activities
|
|
|
(97
|
)
|
|
|
(80
|
)
|
Financing
activities
|
|
|
(509
|
)
|
|
|
(430
|
)
|
Net
increase in cash and cash equivalents
|
|
$
|
5
|
|
|
$
|
1
|
|
Cash Flow from
Operating Activities
In the first three months of 2009, our net cash flow
provided from operating activities was $611 million, an increase of $100 million
or 20% from the same period in 2008. This was primarily a result of a larger
decrease in inventory in 2009 than 2008, primarily related to the higher cost of
inventory sold in 2009. This was partially offset by increased cash collateral
requirements for our derivative financial instrument activities due to the
change in hedge values due to the downward shift in the forward NYMEX curve
prices in 2009.
The
downward shift in the forward curve results in unrealized losses on the hedging
instruments, comprised primarily of exchange traded derivatives, associated with
anticipated natural gas purchases. 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. These unrealized losses are substantially
offset by gains on derivative financial instruments utilized to hedge the price
risk associated with the anticipated sale of these natural gas purchases. The
anticipated economics of these transactions will ultimately be realized in the
period when the natural gas is bought and sold.
Cash Flow from
Investing Activities
Our investing activities consisted of PP&E
expenditures of $97 million for the three months ended March 31, 2009 and $80
million for the same period in 2008. The increase of $17 million or 21% in
PP&E expenditures was primarily due to a $10 million increase at
distribution operations, which included higher spending for the pipeline
replacement program and expenditures for Virginia Natural Gas’ Hampton Roads
Crossing pipeline project connecting its northern and southern
systems.
Additionally,
our energy investments’ PP&E expenditures increased $12 million primarily
from increased expenditures at Golden Triangle Storage on our planned natural
gas storage facility partially offset by decreased telecommunication
expenditures at AGL Networks which expanded its Phoenix network in 2008. These
PP&E expenditure increases were partially offset by decreased expenditures
at retail energy operations’ of $6 million primarily due to decreased spending
on information technology assets compared to 2008, when the segment transitioned
to a new customer care and call center vendor.
Cash Flow from
Financing Activities
Our financing activities are primarily composed of
borrowings and payments of short-term debt, payments of medium-term notes,
issuances of senior notes, distributions to noncontrolling interests, cash
dividends on our common stock, 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 March
31, 2009, our variable-rate debt was 27% of our total debt, compared to 20% as
of March 31, 2008. We may issue additional long-term debt in 2009 in
consideration of our working capital needs and capital expenditure plans to
maintain an appropriate mix.
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 statements of financial position 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 March 31, 2009, and reflects no change from December 31,
2008.
|
|
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
|
|
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.
Default events
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 Facilities have financial covenants that require 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
noncontrolling interest, standby letters of credit, surety bonds and the
exclusion of other comprehensive income pension adjustments. Our debt-to-equity
calculation, as defined by our Credit Facilities was 53% at March 31, 2009 and
59% at December 31, 2008 and 52% at March 31, 2008. These amounts are within our
required and targeted ranges. Our debt and equity capitalization ratios, as of
the dates indicated, are summarized in the following table.
|
|
Mar.
31, 2009
|
|
|
Dec.
31, 2008
|
|
|
Mar.
31, 2008
|
|
Short-term
debt
|
|
|
10
|
%
|
|
|
20
|
%
|
|
|
10
|
%
|
Long-term
debt
|
|
|
44
|
|
|
|
40
|
|
|
|
42
|
|
Total
debt
|
|
|
54
|
|
|
|
60
|
|
|
|
52
|
|
Equity
|
|
|
46
|
|
|
|
40
|
|
|
|
48
|
|
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 6
“Debt.”
Short-term debt
Our
short-term debt is composed of borrowings and payments under our Credit
Facilities and commercial paper program, lines of credit and the current portion
of our capital leases. 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.
Excluding
the current portions of gas facility revenue bonds of $114 million that we
refinanced in 2008, our short-term borrowings, as of March 31, 2009, increased
$148 million or 58% compared to the same period last year. This was primarily a
result of $178 million increase in our margin requirements for our energy
marketing and risk management activities compared to the prior year. More
information on our short-term debt as of March 31, 2009, 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
|
|
|
$
|
335
|
|
SouthStar
line of credit
|
|
|
75
|
|
|
|
45
|
|
Sequent
lines of credit
|
|
|
30
|
|
|
|
22
|
|
Total
|
|
$
|
1,245
|
|
|
$
|
402
|
|
(1)
|
Supported
by our $1.0 billion and $140 million Credit Facilities, and includes $335
million of commercial paper
borrowings.
|
As of
March 31, 2009 and March 31, 2008 we had no outstanding borrowings under our
Credit Facilities. As of December 31, 2008, we had $500 million of outstanding
borrowings under the Credit Facilities. These unsecured promissory notes are
supported by our $1 billion Credit Facility which expires in August 2011 and a
supplemental $140 million Credit Facility that expires in September 2009. We
have the option to request an increase in the aggregate principal amount
available for borrowing under the $1 billion Credit Facility to $1.25 billion on
not more than three occasions during each calendar year. The $140 million Credit
Facility allows for the option to request an increase in the borrowing capacity
to $150 million.
Long-term debt
Our long-term
debt matures more than one year from the date of our statements of financial
position and consists of medium-term notes, senior notes, gas facility revenue
bonds, and capital leases.
For
information on the maturity of our long-term debt 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, 2008.
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 March
2009, we contributed $14 million to our pension plans. We expect to make
additional contributions to our pension plans of $18 million in 2009 for a total
of $32 million. We previously expected that our total required and additional
contributions to our pension plans would be approximately $68 million to
preserve the current levels of benefits under our pension plans and in
accordance with the funding requirements of the Pension Protection Act. The
reduction in our expected contributions are a result of a notice from the
Internal Revenue Service with respect to proposed changes to the pension funding
rules that resulted in the use of a discount rate that was higher than the
discount rate we used in our previous estimate. Consequently, our pension
liabilities as calculated under the funding rules were reduced and the 2009
funding requirements decreased to maintain current benefits levels.
The
following table illustrates our expected future contractual obligation payments
such as debt and lease agreements, and commitments and contingencies as of March
31, 2009.
|
|
|
|
|
|
|
|
2010
&
|
|
|
2012
&
|
|
|
2014
&
|
|
In
millions
|
|
Total
|
|
|
2009
|
|
|
2011
|
|
|
2013
|
|
|
thereafter
|
|
Recorded
contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$
|
1,675
|
|
|
$
|
-
|
|
|
$
|
302
|
|
|
$
|
240
|
|
|
$
|
1,133
|
|
Short-term
debt
|
|
|
403
|
|
|
|
403
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
PRP
costs
(1)
|
|
|
169
|
|
|
|
43
|
|
|
|
78
|
|
|
|
48
|
|
|
|
-
|
|
Environmental
remediation liabilities
(1)
|
|
|
105
|
|
|
|
15
|
|
|
|
40
|
|
|
|
39
|
|
|
|
11
|
|
Total
|
|
$
|
2,352
|
|
|
$
|
461
|
|
|
$
|
420
|
|
|
$
|
327
|
|
|
$
|
1,144
|
|
Unrecorded
contractual obligations and commitments
(2)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
charges, storage capacity and gas supply
(3)
|
|
$
|
1,713
|
|
|
$
|
420
|
|
|
$
|
603
|
|
|
$
|
332
|
|
|
$
|
358
|
|
Interest
charges
(4)
|
|
|
933
|
|
|
|
70
|
|
|
|
166
|
|
|
|
135
|
|
|
|
562
|
|
Operating
leases
|
|
|
130
|
|
|
|
23
|
|
|
|
45
|
|
|
|
25
|
|
|
|
37
|
|
Standby
letters of credit, performance / surety bonds
|
|
|
51
|
|
|
|
45
|
|
|
|
6
|
|
|
|
-
|
|
|
|
-
|
|
Asset
management agreements
(5)
|
|
|
37
|
|
|
|
12
|
|
|
|
23
|
|
|
|
2
|
|
|
|
-
|
|
Total
|
|
$
|
2,864
|
|
|
$
|
570
|
|
|
$
|
843
|
|
|
$
|
494
|
|
|
$
|
957
|
|
(1)
|
Includes
charges recoverable through rate rider
mechanisms.
|
(2)
|
In
accordance with GAAP, these items are not reflected in our condensed
consolidated statements of financial
position.
|
(3)
|
Charges
recoverable through a natural gas cost recovery mechanism or alternatively
billed to Marketers, and includes demand charges associated with Sequent.
Also includes SouthStar’s gas commodity purchase commitments of 22 Bcf at
floating gas prices calculated using forward natural gas prices as of
March 31, 2009, and are valued at $90 million. Additionally,
includes amounts associated with a subsidiary of NUI which entered into
two 20-year 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 that will be amortized
to our 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.
|
(4)
|
Floating
rate debt is based on the interest rate as of March 31, 2009, and the
maturity of the underlying debt instrument. As of March 31, 2009, we have
$31 million of accrued interest on our consolidated statements of
financial position that will be paid in
2009.
|
(5)
|
Represent
fixed-fee minimum payments for Sequent’s affiliated asset
management.
|
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
|
·
|
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, 2008.
Previously
discussed
SFAS 160
SFAS 160 requires us to present our minority interest, as noncontrolling
interest, separately within the capitalization section of our condensed
consolidated statements of financial position. We adopted SFAS 160 on January 1,
2009. More information on our adoption of SFAS 160 is discussed in
Note 5
.
SFAS
161
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
adopted SFAS 161 on January 1, 2009 and provided the required additional
disclosures, but it had no financial impact to our consolidated results of
operations, cash flows or financial condition
.
More information on our adoption of
SFAS 160 is discussed in
Note 3
.
FSP EITF
03-6-1
This FSP became effective on January 1, 2009 and provides guidance
on the computation of earnings per share when a company has unvested share
awards outstanding that have the right to receive dividends. The effects of this
FSP were immaterial to our calculation of earnings per share.
FSP FAS
133-1
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 had no financial impact to our consolidated results
of operations, cash flows or financial condition. We adopted FSP FAS 133-1 on
January 1, 2009.
Recently
issued
FSP FAS 132(R)-1
This FSP
requires additional disclosures relating to postretirement benefit plan assets
to provide transparency regarding the types of assets and the associated risks
within the types of plan assets. The required disclosures include:
·
|
How
investment allocation decisions are made, including information that
provides an understanding of investment policies and
strategies,
|
·
|
The
major categories of plan assets,
|
·
|
Inputs
and valuation techniques used to measure the fair value of plan assets,
including those measurements using significant unobservable inputs, on
changes in plan assets for the period,
and
|
·
|
Significant
concentrations of risk within plan
assets.
|
This FSP
is effective for fiscal years ending after December 15, 2009 and requires
additional disclosures in our notes to condensed consolidated financial
statements, but will not have a material impact on our financial position,
results of operations or cash flows.
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.
Our Risk
Management Committee (RMC) is responsible for establishing the overall risk
management policies and monitoring compliance with, and adherence to, the terms
within these policies, including approval and authorization levels and
delegation of these levels. Our RMC consists of members of senior management who
monitor open commodity price risk positions and other types of risk, corporate
exposures, credit exposures and overall results of our risk management
activities. It is chaired by our chief risk officer, who is responsible for
ensuring that appropriate reporting mechanisms exist for the RMC to perform its
monitoring functions. Our risk management activities and related accounting
treatments for our derivative financial instruments are described in further
detail in
Note 3
.
Commodity
Price Risk
Retail Energy
Operations
SouthStar’s use of derivative financial instruments is
governed by a risk management policy, approved and monitored by its Finance and
Risk Asset Management Committee, which prohibits the use of derivatives for
speculative purposes.
SouthStar
routinely utilizes various types of derivative financial instruments to mitigate
certain commodity price and weather risk inherent in the natural gas industry.
This includes the active management of storage positions through a variety of
hedging transactions for the purpose of managing exposures arising from changing
commodity prices. SouthStar uses these hedging instruments to lock in
economic margins (as spreads between wholesale and retail commodity prices widen
between periods) and thereby minimize its exposure to declining operating
margins.
The
following tables illustrate the change in the net fair value of the derivative
financial instruments during the three months ended March 31, 2009 and 2008, and
provide details of the net fair value of derivative financial instruments
outstanding as of March 31, 2009.
|
|
Three
months ended Mar. 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Net
fair value of derivative financial instruments outstanding at beginning of
period
|
|
$
|
(17
|
)
|
|
$
|
10
|
|
Derivative
financial instruments realized or otherwise settled during
period
|
|
|
4
|
|
|
|
(7
|
)
|
Change
in net fair value of derivative financial instruments
|
|
|
(9
|
)
|
|
|
3
|
|
Net
fair value of derivative financial instruments outstanding at end of
period
|
|
|
(22
|
)
|
|
|
6
|
|
Netting
of cash collateral
|
|
|
27
|
|
|
|
-
|
|
Cash
collateral and net fair value of derivative financial instruments
outstanding at end of period
|
|
$
|
5
|
|
|
$
|
6
|
|
The sources of SouthStar’s net fair value of its commodity-related
derivative financial instruments at March 31, 2009, are as follows:
In
millions
|
|
Prices
actively quoted
(Level
1)
(1)
|
|
|
Significant
other observable inputs
(Level
2)
|
|
|
Significant
unobservable inputs
(Level
3)
|
|
Mature
through
|
|
|
|
|
|
|
|
|
|
2009
|
|
$
|
(28
|
)
|
|
$
|
(1
|
)
|
|
$
|
-
|
|
2010
|
|
|
7
|
|
|
|
-
|
|
|
|
-
|
|
Total
derivative financial instruments
(2)
|
|
$
|
(21
|
)
|
|
$
|
(1
|
)
|
|
$
|
-
|
|
(1)
|
Valued
using NYMEX futures prices.
|
(2)
|
Excludes
cash collateral amounts.
|
The
following tables include the fair values and average values of SouthStar’s
derivative financial instruments as of the dates indicated. SouthStar bases the
average values on monthly averages for the three months ended March 31, 2009 and
2008.
|
|
Derivative
financial instruments
average
fair values
(1)
at
Mar. 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Asset
|
|
$
|
11
|
|
|
$
|
5
|
|
Liability
|
|
|
35
|
|
|
|
1
|
|
(1)
Excludes cash collateral amounts.
|
|
Derivative
financial instruments fair values netted with cash collateral
at
|
|
In
millions
|
|
Mar.
31,
2009
|
|
|
Dec.
31,
2008
|
|
|
Mar.
31,
2008
|
|
Asset
|
|
$
|
10
|
|
|
$
|
16
|
|
|
$
|
7
|
|
Liability
|
|
|
5
|
|
|
|
2
|
|
|
|
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
March 31, 2009 and 2008 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 derivative financial
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.
The
following tables include the fair values and average values of Sequent’s
derivative financial instruments as of the dates indicated. Sequent bases the
average values on monthly averages for the three months ended March 31, 2009 and
2008.
|
|
Derivative
financial instruments average values
(1)
at Mar.
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Asset
|
|
$
|
187
|
|
|
$
|
42
|
|
Liability
|
|
|
82
|
|
|
|
37
|
|
(1)
|
Excludes
cash collateral amounts.
|
|
|
Derivative
financial instruments fair values netted with cash collateral
at
|
|
In
millions
|
|
Mar.
31,
2009
|
|
|
Dec.
31,
2008
|
|
|
Mar.
31,
2008
|
|
Asset
|
|
$
|
211
|
|
|
$
|
206
|
|
|
$
|
44
|
|
Liability
|
|
|
17
|
|
|
|
27
|
|
|
|
26
|
|
Sequent
experienced a $75 million decrease in the net fair value of its outstanding
contracts during the first three months of 2009 and 2008 due to changes in the
fair value of derivative financial 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 financial instruments during the three months ended March 31, 2009
and 2008, and provide details of the net fair value of contracts outstanding as
of March 31, 2009.
|
|
Three
months ended Mar. 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Net
fair value of derivative financial instruments outstanding at beginning of
period
|
|
$
|
82
|
|
|
$
|
57
|
|
Derivative
financial instruments realized or otherwise settled during
period
|
|
|
(95
|
)
|
|
|
(42
|
)
|
Change
in net fair value of derivative financial instruments
|
|
|
20
|
|
|
|
(33
|
)
|
Net
fair value of derivative financial instruments outstanding at end of
period
|
|
|
7
|
|
|
|
(18
|
)
|
Netting
of cash collateral
|
|
|
187
|
|
|
|
36
|
|
Cash
collateral and net fair value of derivative financial instruments
outstanding at end of period
|
|
$
|
194
|
|
|
$
|
18
|
|
The
sources of Sequent’s net fair value of its commodity-related derivative
financial instruments at March 31, 2009, are as follows:
In
millions
|
|
Prices
actively quoted
(Level
1)
(1)
|
|
|
Significant
other observable inputs
(Level
2) (2)
|
|
|
Significant
unobservable inputs
(Level
3)
|
|
Mature
through
|
|
|
|
|
|
|
|
|
|
2009
|
|
$
|
(120
|
)
|
|
$
|
105
|
|
|
$
|
-
|
|
2010 - 2011
|
|
|
(20
|
)
|
|
|
33
|
|
|
|
-
|
|
2012
- 2014
|
|
|
2
|
|
|
|
7
|
|
|
|
-
|
|
Total
derivative financial instruments
(3)
|
|
$
|
(138
|
)
|
|
$
|
145
|
|
|
$
|
-
|
|
(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.
|
(3)
|
Excludes
cash collateral amounts.
|
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 months ended March 31, 2009 and
2008 had the following VaRs.
|
|
Three
months ended March 31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
Period
end
|
|
$
|
2.1
|
|
|
$
|
2.9
|
|
Average
|
|
|
1.9
|
|
|
|
1.4
|
|
High
|
|
|
3.3
|
|
|
|
2.9
|
|
Low
|
|
|
1.3
|
|
|
|
0.8
|
|
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 $563 million of variable-rate debt,
which includes $402 million of our variable-rate short-term debt and $161
million of variable-rate gas facility revenue bonds outstanding at March 31,
2009, a 100 basis point change in market interest rates from 0.76% to 1.76%
would have resulted in an increase in pretax interest expense of $6 million on
an annualized basis.
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 March 31, 2009, Sequent’s top 20 counterparties
represented approximately 69% of the total counterparty exposure of $325
million, derived by adding together the top 20 counterparties’ exposures and
dividing by the total of Sequent’s counterparties’ exposures.
As of
March 31, 2009, 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, 2008 and March 31, 2008. 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.
The
following table shows Sequent’s third-party commodity receivable and payable
positions as of March 31, 2009 and 2008 and December 31, 2008.
|
|
Gross
receivables
|
|
|
Gross
payables
|
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
|
March
31,
|
|
In
millions
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Netting
agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade
|
|
$
|
237
|
|
|
$
|
398
|
|
|
$
|
483
|
|
|
$
|
168
|
|
|
$
|
266
|
|
|
$
|
439
|
|
Counterparty
is non-investment grade
|
|
|
8
|
|
|
|
15
|
|
|
|
46
|
|
|
|
19
|
|
|
|
41
|
|
|
|
30
|
|
Counterparty
has no external rating
|
|
|
76
|
|
|
|
129
|
|
|
|
91
|
|
|
|
153
|
|
|
|
228
|
|
|
|
239
|
|
No
netting agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade
|
|
|
5
|
|
|
|
7
|
|
|
|
4
|
|
|
|
2
|
|
|
|
4
|
|
|
|
3
|
|
Amount
recorded on statements of financial position
|
|
$
|
326
|
|
|
$
|
549
|
|
|
$
|
624
|
|
|
$
|
342
|
|
|
$
|
539
|
|
|
$
|
711
|
|
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 March
31, 2009, 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 $12
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, 2008.
(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 March 31, 2009, 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 March 31, 2009, 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.
Item
1. Legal Proceedings
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 7
- Commitments and Contingencies”
contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated
Financial Statements (Unaudited).”
In March
2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware
against GNGC, asking the court to enter a judgment declaring that GNGC’s right
to purchase Piedmont’s ownership interest in SouthStar expires on November 1,
2009. We believe that, under the March 2004 amended and restated joint venture
agreement, GNGC has the evergreen opportunity, throughout the term of the joint
venture, to exercise its options to purchase a portion of, or all of, Piedmont’s
interest in SouthStar by notifying Piedmont on or before November of each
year, with the purchase being effective as of January 1 of the following year.
The ultimate resolution of this litigation cannot be determined, but we believe
that the dispute will be resolved before our next option exercise date on
November 1, 2009.
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.
The
following table sets forth information regarding purchases of our common stock
by us and any affiliated purchasers during the three months ended March 31,
2009. 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)
|
|
January
2009
|
|
|
4,500
|
|
|
$
|
30.33
|
|
|
|
-
|
|
|
|
4,950,951
|
|
February
2009
|
|
|
14,200
|
|
|
|
33.53
|
|
|
|
-
|
|
|
|
4,950,951
|
|
March
2009
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,950,951
|
|
Total
first quarter
|
|
|
18,700
|
|
|
$
|
32.76
|
|
|
|
-
|
|
|
|
|
|
(1)
|
The
total number of shares purchased includes an aggregate of 8,650 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 purchased
10,050 shares for such purposes in the first quarter of 2009. As of March
31, 2009, we had purchased a total 322,417 of the 600,000 shares
authorized for purchase, leaving 277,583 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.
|
10.6
|
Fourth
Modification to the amended and Restated Master Environmental Management
Services Agreement dated as of February 1, 2009 by and
between Atlanta Gas Light Company and the RETEC Group,
Inc.
|
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:
April 29,
2009
/s/ Andrew W.
Evans
Executive
Vice President and Chief Financial Officer
Agilon Health (NYSE:AGL)
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