UNITED
STATES |
SECURITIES
AND EXCHANGE COMMISSION |
Washington,
D.C. 20549 |
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FORM
8-K |
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CURRENT
REPORT |
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PURSUANT
TO SECTION 13 OR 15(d) OF |
THE
SECURITIES EXCHANGE ACT OF 1934 |
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Date
of Report (Date of earliest event reported): April 27,
2005 |
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AGL
RESOURCES INC. |
(Exact
name of registrant as specified in its charter) |
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Georgia |
1-14174 |
58-2210952 |
(State
or other jurisdiction of incorporation) |
(Commission
File No.) |
(I.R.S.
Employer Identification No.) |
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Ten
Peachtree Place NE, Atlanta, Georgia 30309 |
(Address
and zip code of principal executive offices) |
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404-584-4000 |
(Registrant's
telephone number, including area code) |
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Not
Applicable |
(Former
name or former address, if changed since last report) |
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Check
the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant under any
of the following provisions: |
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[ ]
Written communications pursuant to Rule 425 under the Securities Act (17
CFR 230.425) |
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[ ]
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR
240.14a-12) |
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[ ]
Pre-commencement communications pursuant to Rule 14d-2(b) under the
Exchange Act (17 CFR 240.14d-2(b)) |
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[ ]
Pre-commencement communications pursuant to Rule 13e-4(c) under the
Exchange Act (17 CFR 240.13e-4(c)) |
Item
2.02 Results
of Operations and Financial Condition
On April
27, 2005, AGL Resources Inc. announced its financial results for the three
months ended March 31, 2005 and certain other information. A copy of AGL
Resources’ press release announcing such financial results and other information
is attached as Exhibit 99.1 hereto and incorporated by reference herein.
The
information in the preceding paragraph, as well as Exhibit 99.1 referenced
therein, shall not be deemed “filed” for purposes of Section 18 of the
Securities Exchange Act of 1934, nor shall it be deemed incorporated by
reference in any filing under the Securities Act of 1933.
Item
7.01 Regulation
FD Disclosure
On April
27, 2005 at 4:30 p.m. (ET) AGL Resources Inc. plans to hold its first
quarter 2005 earnings conference call. The Company is filing this Form 8-K to
provide selected discussion of financial results, liquidity and market risks as
of March 31, 2005.
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Certain
expectations and projections regarding our future performance referenced in this
report, as well as in other reports and proxy statements we file with the
Securities and Exchange Commission (SEC), are forward-looking statements.
Officers and other key 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, such as projections of
our financial performance, management’s goals and strategies for our business
and assumptions regarding the foregoing. Because these statements involve
anticipated events or conditions, forward-looking statements often include words
such as “anticipate,” “assume,” “believe,” “can,” “could,” “estimate,” “expect,”
“forecast,” “indicate,” “intend,” “may,” “plan,” “predict,” “project,” “seek,”
“should,” “target,” “will,” “would” or similar expressions. For example, in this
report, we have forward-looking statements regarding our expectations for
various items, including:
· |
operating
income growth; |
· |
cash
flows from operations; |
· |
operating
expense growth; |
· |
our
business strategies and goals; |
· |
our
potential for growth and profitability; |
· |
our
ability to integrate our recent and future
acquisitions; |
· |
trends
in our business and industries, and |
· |
developments
in accounting standards |
Do not
unduly rely on forward-looking statements. They represent our expectations about
the future and are not guarantees. Our expectations 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 the
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 results to differ significantly from our expectations. We
caution readers that, in addition to the important factors described elsewhere
in this report, the factors set forth in our 2004 Annual Report on Form 10-K
filed with the SEC on February 15, 2005 under Item 7, “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” under the caption
“Risk Factors,” among others, could cause our business, results of operations or
financial condition in 2005 and thereafter to differ significantly from those
expressed in any forward-looking statements. There also may be other factors not
described 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, and we do not undertake any
obligation to update these statements to reflect subsequent
changes.
Overview
We are a
Fortune 1000 energy services holding company whose principal business is the
distribution of natural gas in six states - Florida, Georgia, Maryland, New
Jersey, Tennessee and Virginia. Our six utilities serve more than 2.3 million
end-use customers, making us the largest distributor of natural gas in the
Southeast and mid-Atlantic regions of the United States, based on customer
count. We also are involved in various related businesses, including retail
natural gas marketing to end-use customers in Georgia; natural gas asset
management and related logistics activities for our own utilities as well as for
other non-affiliated companies; natural gas storage arbitrage and related
activities; operation of high-deliverability underground natural gas storage
assets; and construction and operation of telecommunications conduit and fiber
infrastructure within select metropolitan areas. We manage these businesses
through four operating segments - distribution operations, retail energy
operations, wholesale services and energy investments - and a non-operating
corporate segment.
The
distribution operations segment is the largest component of our business and is
comprehensively regulated by regulatory agencies in six states. These agencies
approve rates designed to provide us the opportunity to generate revenues; to
recover the cost of natural gas delivered to our customers and our fixed and
variable costs such as depreciation, interest, maintenance and overhead costs;
and to earn a reasonable return for our shareholders. With the exception of
Atlanta Gas Light Company (Atlanta Gas Light), our largest utility franchise,
the earnings of our regulated utilities are weather-sensitive to varying
degrees. Although various regulatory mechanisms provide a reasonable opportunity
to recover our fixed costs regardless of volumes sold, the effect of weather
manifests itself in terms of higher earnings during periods of colder weather
and lower earnings with warmer weather. Our retail energy operations segment,
which includes SouthStar Energy Services LLC (SouthStar), also is weather
sensitive, and uses a variety of hedging strategies to mitigate potential
weather impacts. Our utilities and SouthStar face competition in the residential
and commercial customer markets based on customer preferences for natural gas
compared with other energy products, as well as the price of those products
relative to that of natural gas.
We
derived approximately 96% of our earnings before interest and taxes (EBIT)
during the three months ended March 31, 2005 from our regulated natural gas
distribution business and from the sale of natural gas to end-use customers in
Georgia by SouthStar. This statistic is significant because it represents the
portion of our earnings that results directly from the underlying business of
supplying natural gas to retail customers. Although SouthStar is not subject to
the same regulatory framework as our utilities, it is an integral part of the
retail framework for providing gas service to end-use customers in the state of
Georgia. For more information regarding our measurement of EBIT and the items it
excludes from operating income and net income, see “Results of Operations - AGL
Resources.”
The
remaining 4% of our EBIT was principally derived from businesses that are
complementary to our natural gas distribution business. We engage in natural gas
asset management and operation of high deliverability natural gas underground
storage as subordinate activities to our utility franchises. 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 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 business
vitality.
Industry
Dynamics and Competition The
natural gas industry continues to face a number of challenges, most of which
relate to the supply of, and demand for, natural gas across the United States. A
confluence of factors - including higher peak demands across all customer
classes; incremental
demand for natural gas to fuel the production of electricity, declining
continental supply, particularly in the Gulf of Mexico region, and sustained
higher pricing levels relative to historical averages - have created a mismatch
between demand and declining supply.
These
factors continue to challenge our industry to unlock new sources of natural gas
supply to serve the North American market. Liquefied natural gas (LNG) continues
to grow in importance as an incremental supply source to meet the expected
growth in demand for natural gas. Expansion of existing LNG terminals and
construction of new facilities both point toward rapid import expansions
throughout the rest of this decade. In addition to expansion of LNG supplies,
access to previously restricted areas for natural gas drilling also will be
critical in meeting future supply needs. The challenge is magnified by the time
lags and capital expenditures required to bring new LNG facilities and new
drilling rigs online and by the absence of a comprehensive national energy
policy designed to facilitate the construction and expansion
process.
The
natural gas industry also continues to face significant competition from the
electric utilities serving the residential and small commercial markets as the
potential replacement of natural gas appliances with electric appliances becomes
more prevalent. The primary competitive factors are the price of energy and the
comfort of natural gas heating compared to electric heating and other energy
sources. The increase in wholesale natural gas prices over the last several
years has resulted in increases in the costs of natural gas billed to our
customers and has affected, to some extent, our ability to retain customers,
which remains one of our greater challenges in our southernmost utilities in
2005 and future years.
Integration
of NUI Corporation We have
made significant progress in integrating the assets and operations of NUI
Corporation (NUI), which we acquired on November 30, 2004, into our business
operations. In the first quarter of 2005, we consolidated a number of NUI’s
business technology platforms into our enterprise-wide systems, including the
accounting, payroll, human resources and supply chain functions. We also
consolidated the call center operation that previously served the NUI utilities
into our centralized call center. The combination of system integrations and the
application of our best-practice operational model in managing the NUI assets
already has resulted in improvements in the metrics we use to measure our
business results. Such metrics include the productivity of our field personnel,
the speed of our response to customers, personal and system safety and system
reliability.
Internal
Controls Section
404 of the Sarbanes-Oxley Act of 2002 (SOX 404) and related rules of the SEC
require management of public companies to assess the effectiveness of the
company’s internal controls over financial reporting as of the end of each
fiscal year. In our 2004 Annual Report on Form 10-K filed with the SEC on
February 15, 2005 we noted that, for 2004, the scope of our assessment of our
internal controls over financial reporting included all our consolidated
entities except those falling under NUI, which we acquired on November 30, 2004,
and Jefferson Island Storage & Hub, LLC (Jefferson Island), which we
acquired on October 1, 2004. In accordance with the SEC’s published guidance, we
excluded these entities from our assessment as they were acquired late in the
year, and it was not possible to conduct our assessment between the date of
acquisition and the end of the year. SEC rules require that we complete our
assessment of the internal control over financial reporting of these entities
within one year from the date of acquisition.
We have
initiated our efforts to assess the systems of internal control related to NUI’s
and Jefferson Island’s businesses to comply with the SEC’s requirements under
both Sections 302 and 404 of the Sarbanes-Oxley Act. During the first quarter of
2005, we converted and integrated substantially all of NUI’s accounting systems
and internal control processes into our corporate accounting systems and
internal control processes. As part of this process, we are addressing and
resolving the material deficiencies in internal controls for the NUI business
identified by NUI’s external and internal auditors during audits performed in
fiscal years 2003 and 2004, as more fully described in our 2004 Annual Report on
Form 10-K. While the conversion of financial systems is a key step toward
remediation of the control deficiencies, we still are in the process of
documenting the internal control process for the NUI business and we continue to
remediate known deficiencies in internal controls.
Results
of Operations
AGL
Resources We
acquired Jefferson Island and NUI in the fourth quarter of 2004. As a result,
these acquired operations are included in our results of operations for the
three months ended March 31, 2005 but are not included for the same period in
2004.
Beginning
in 2005, we added an additional segment, Retail Energy Operations, which
consists of the operations of SouthStar, our retail gas marketing subsidiary
that conducts business primarily in Georgia. We added this segment due to our
application of accounting guidance in SFAS No. 131, “Disclosures About Segments
of an Enterprise and Related Information,” (“FAS 131”) in consideration of the
impact of the NUI and Jefferson Island acquisitions and it is consistent with
our desire to provide transparency and visibility to SouthStar on a standalone
basis. Separating SouthStar into its own segment also provides additional
visibility to the remaining businesses in the Energy Investments segment,
principally Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal
Propane), which are more closely related in structure and operation.
Additionally, we have restated the segment information for the three months
ended March 31, 2004 in accordance with the guidance set forth in FAS
131.
Revenues We
generate nearly all our operating revenues through the sale, distribution and
storage of natural gas. We include in our consolidated revenues an estimate of
revenues from natural gas distributed, but not yet billed, to residential and
commercial customers from the latest meter reading date to the end of the
reporting period. We record these estimated revenues as unbilled revenues on our
consolidated balance sheet.
A
significant portion of our operations is subject to variability associated with
changes in commodity prices and seasonal fluctuations. During the heating
season, primarily from November through March, natural gas usage and operating
revenues are higher since generally more customers will be connected to our
distribution systems and natural gas usage is higher in periods of colder
weather than in periods of warmer weather. Commodity prices tend to be higher in
colder months as well. Our non-utility businesses principally use physical and
financial arrangements to economically hedge the risks associated with seasonal
fluctuations and changing commodity prices. Certain hedging and trading
activities may require cash deposits to satisfy margin requirements. In
addition, because these economic hedges do not generally qualify for hedge
accounting treatment, our reported earnings for the wholesale services and
retail energy operations segments reflect changes in the fair value of certain
derivatives and these values may change significantly from period to period.
Operating
margin and EBIT We
evaluate the performance of our operating segments using the measures of
operating margin and EBIT. We believe operating margin is a better indicator
than revenues for the contribution resulting from customer growth in our
distribution operations and retail energy operations segments since the cost of
gas can vary significantly and is generally passed directly to our customers. We
also consider operating margin to be a better indicator in our wholesale
services and energy investments segments since it is a direct measure of gross
profit before overhead costs. Management believes EBIT is useful to investors as
a measurement of our operating segments’ performance because it 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 affects the efficiency of the underlying
operations.
Our
operating margin and EBIT are not measures that are considered to be calculated
in accordance with GAAP. 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 as determined in accordance with GAAP. In
addition, our operating margin or EBIT measures may not be comparable to a
similarly titled measure of another company. The following are reconciliations
of our operating margin and EBIT to operating income and net income, together
with other consolidated financial information for the three months ended March
31, 2005 and 2004.
|
|
Three
months ended March 31, |
|
|
|
In
millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Operating
revenues |
|
$ |
912 |
|
$ |
651 |
|
|
40 |
% |
Cost
of gas |
|
|
572 |
|
|
393 |
|
|
46 |
|
Operating
margin |
|
|
340 |
|
|
258 |
|
|
32 |
|
Operating
expenses |
|
|
159 |
|
|
125 |
|
|
27 |
|
Operating
income |
|
|
181 |
|
|
133 |
|
|
36 |
|
Other
income |
|
|
1 |
|
|
1 |
|
|
- |
|
Minority
interest |
|
|
(13 |
) |
|
(11 |
) |
|
(18 |
) |
EBIT |
|
|
169 |
|
|
123 |
|
|
37 |
|
Interest
expense |
|
|
(26 |
) |
|
(16 |
) |
|
(63 |
) |
Earnings
before income taxes |
|
|
143 |
|
|
107 |
|
|
34 |
|
Income
taxes |
|
|
(55 |
) |
|
(41 |
) |
|
(34 |
) |
Net
income |
|
$ |
88 |
|
$ |
66 |
|
|
33 |
% |
Basic
earnings per common share |
|
$ |
1.15 |
|
$ |
1.02 |
|
|
13 |
% |
Fully
diluted earnings per common share |
|
$ |
1.14 |
|
$ |
1.00 |
|
|
14 |
% |
Weighted
average number of common shares outstanding |
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
76.9 |
|
|
64.6 |
|
|
19 |
% |
Fully
diluted |
|
|
77.6 |
|
|
65.5 |
|
|
19 |
% |
Segment
information
Operating revenues, operating margin and EBIT information for each of our
segments are contained in the following table for the three months ended March
31, 2005 and 2004:
2005
(in
millions) |
|
Operating
revenues |
|
Operating
margin |
|
EBIT |
|
Distribution
operations |
|
$ |
634 |
|
$ |
253 |
|
$ |
123 |
|
Retail
energy operations |
|
|
314 |
|
|
66 |
|
|
40 |
|
Wholesale
services |
|
|
11 |
|
|
11 |
|
|
4 |
|
Energy
investments |
|
|
12 |
|
|
9 |
|
|
5 |
|
Corporate
(1) |
|
|
(59 |
) |
|
1 |
|
|
(3 |
) |
Consolidated |
|
$ |
912 |
|
$ |
340 |
|
$ |
169 |
|
2004 |
|
|
|
|
|
|
|
|
|
|
Distribution
operations |
|
$ |
389 |
|
$ |
180 |
|
$ |
82 |
|
Retail
energy operations |
|
|
307 |
|
|
57 |
|
|
33 |
|
Wholesale
services |
|
|
20 |
|
|
20 |
|
|
12 |
|
Energy
investments |
|
|
1 |
|
|
1 |
|
|
1 |
|
Corporate
(1) |
|
|
(66 |
) |
|
- |
|
|
(5 |
) |
Consolidated |
|
$ |
651 |
|
$ |
258 |
|
$ |
123 |
|
(1) |
Includes
intercompany eliminations |
First
quarter 2005 compared to first quarter 2004
Operating
Margin $73
million of the $82 million increase in operating margin resulted from
distribution operations, of which approximately $70 million resulted from the
acquisition of NUI. The remaining $12 million primarily reflects increased
contributions from retail energy operations in the amount of $9 million,
increased contributions of $8 million in the energy investments segment, and an
increase of $1 million in the corporate segment, offset by a $9 million decrease
in wholesale services.
Operating
Expenses
Operating expenses increased by $34 million, of which $32 million was from our
distribution operations where $37 million was as a result of the NUI
acquisition. The higher expenses from NUI were offset by $2 million of lower
expenses at Virginia Natural Gas Company and $1 million of lower expenses
related to favorable bad debt expense compared to last year. Wholesale services’
operating expenses were $1 million less than in 2004 because of costs related to
Sequent’s Energy Trading and Risk Management system in the first quarter of
2004. Our energy investments expenses increased $4 million due primarily to the
Jefferson Island acquisition. Operating expenses for the retail energy
operations segment were essentially flat year-over-year.
Interest
Expense Interest
expense increased by $10 million from last year’s first quarter, primarily as a
result of NUI and Jefferson Island acquisition debt ($8 million) and higher
short-term interest rates ($2 million) as shown in the following table:
|
|
Three
months ended March 31, |
|
Dollars
in millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Average
debt outstanding (1) |
|
$ |
1,820 |
|
$ |
1,214 |
|
$ |
606 |
|
Average
rate |
|
|
5.7 |
% |
|
5.3 |
% |
|
0.4 |
% |
(1) |
Daily
average of all outstanding debt. |
If, for
the three months ended March 31, 2005, market interest rates on our variable
rate debt had been 100 basis points higher, representing a 6.1% interest rate
rather than our actual 5.1% interest rate, our year-to-date pretax interest
expense would have increased by $4 million.
Income
Taxes Income
taxes increased by $14 million, primarily as a result of the higher pre-tax
income for the first quarter of 2005.
Shares
Outstanding Weighted
average shares outstanding increased 12.3 million during
the first quarter 2005, primarily as a result of our 11-million share equity
offering completed in November 2004.
Distribution
Operations
Distribution
operations includes our natural gas local distribution utility companies, which
construct, manage and maintain natural gas pipelines and distribution facilities
and serve 2.3 million end-use customers. Our distribution utilities
include:
· |
Virginia
Natural Gas Company, Inc. (Virginia Natural
Gas) |
· |
Florida
City Gas (Florida Gas) |
· |
Chattanooga
Gas Company (Chattanooga Gas) |
Each
utility operates subject to regulations provided by 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 should generally allow for the recovery of all prudently incurred
costs, including a return on rate base sufficient to pay interest on debt and
provide a reasonable return on common equity. Rate base consists generally
of the original cost of utility plant in service, working capital, inventories
and certain other assets; less accumulated depreciation on utility plant in
service, net deferred income tax liabilities and certain other deductions.
We continuously monitor the performance of our utilities to determine whether
rates need to be adjusted through the regulatory process.
Updates The
following is a summary of significant developments with regard to our
distribution operations segment that have occurred since we filed our 2004
Annual Report on Form 10-K on February 15, 2005.
On
October 15, 2004, Atlanta Gas Light filed a request for a $26 million rate
increase from the Georgia Public Service Commission (Georgia Commission) which
would continue its performance-based rate plan (PBR) and included a return on
equity (ROE) band of 10.2% to 12.2% with an 11.2% midpoint. This filing was
required by the PBR implemented for AGLC in 2001. On February 25, 2005, the
Georgia Commission Adversary Staff and intervening parties filed rebuttal
testimony. Adversary Staff put forth a case calling for a $55.6 million base
rate reduction predicated on a 9.0% ROE.
In March
2005, the Virginia State Corporation Commission staff issued a report alleging
that Virginia Natural Gas’ rates were excessive and that its rates should be
adjusted to produce a $15 million reduction in revenue. The staff also filed a
motion requesting that Virginia Natural Gas’ rates be declared interim and
subject to refund. On April 11, 2005, Virginia Natural Gas responded to the
staff’s report and motion and contested the allegations in the report and
objected to the motion filed by the staff. Virginia Natural Gas also notified
the Virginia State Corporation Commission that it would file a general rate case
before December 31, 2005. As of April 27, 2005, the Virginia Commission has
taken no action on the staff’s motions.
On April
26, 2005, Elizabethtown Gas presented the New Jersey Board of Public Utilities
(NJBPU) with a proposal to accelerate the replacement of approximately 88 miles
of 8” to 12” elevated pressure cast iron main. Under the proposal, approximately
$42 million in estimated capital costs incurred over a three year period would
be recovered through a pipeline replacement rider similar to the program in
effect at Atlanta Gas Light. If the program as proposed is approved, cost
recovery would occur on a one-year lag basis, with collections starting on
October 1, 2006 and extending through December 31, 2009, after which time the
program would be rolled into base rates.
In
October 2004, the Tennessee Regulatory Authority (Tennessee Authority) denied
Chattanooga Gas Company’s (CGC) request for a $4 million rate increase, instead
approving an increase of approximately $1 million based on a 10.2% return on
equity. In November 2004, the Tennessee Authority granted Chattanooga Gas’
motion for reconsideration of the rate increase and in December 2004 heard oral
arguments on the issues of the appropriate capital structure and the return on
equity to be used in setting Chattanooga Gas’ rates. In March 2005, CGC filed
additional testimony and supporting documentation at the request of the
Tennessee Authority. The Tennessee Authority has yet to issue a final ruling on
our request for reconsideration.
Operations
On March
1, 2005, Atlanta Gas Light completed its acquisition of 250 miles of interstate
pipeline in central Georgia from Southern Natural Gas (SNG), a subsidiary of El
Paso Corporation, for $32 million. The acquisition will improve deliverable
capacity and reliability of the storage capacity from our LNG facility in Macon
to our markets in Atlanta.
Results
of Operations for our
distribution operations segment for the
three months ended March 31, 2005 and 2004 are as follows:
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004
|
|
2005
vs. 2004 |
|
Operating
revenues |
|
$ |
634 |
|
$ |
389 |
|
$ |
245 |
|
Cost
of gas |
|
|
381 |
|
|
209 |
|
|
172 |
|
Operating
margin |
|
|
253 |
|
|
180 |
|
|
73 |
|
Operating
expenses |
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance |
|
|
93 |
|
|
71 |
|
|
22 |
|
Depreciation
and amortization |
|
|
28 |
|
|
21 |
|
|
7 |
|
Taxes
other than income |
|
|
9 |
|
|
6 |
|
|
3 |
|
Total
operating expenses |
|
|
130 |
|
|
98 |
|
|
32 |
|
Operating
income |
|
|
123 |
|
|
82 |
|
|
41 |
|
Other
income |
|
|
- |
|
|
- |
|
|
- |
|
EBIT |
|
$ |
123 |
|
$ |
82 |
|
$ |
41 |
|
|
|
|
|
|
|
|
|
|
|
|
Metrics (includes
information only for 2005 for utilities acquired from
NUI) |
|
|
|
|
|
|
|
|
|
|
Average
end-use customers (in
thousands) |
|
|
2,266 |
|
|
1,840 |
|
|
23 |
% |
Operation
and maintenance expenses per customer |
|
$ |
42 |
|
$ |
38 |
|
|
11 |
|
EBIT
per customer |
|
$ |
53 |
|
$ |
45 |
|
|
18 |
|
Throughput
(in
millions of dekatherms) |
|
|
|
|
|
|
|
|
|
|
Firm |
|
|
106 |
|
|
90 |
|
|
18 |
% |
Interruptible |
|
|
33 |
|
|
28 |
|
|
18 |
|
Total |
|
|
139 |
|
|
118 |
|
|
18 |
% |
Heating
degree days (1): |
|
|
|
|
|
|
|
|
%
Colder / (Warmer |
) |
Florida
|
|
|
490 |
|
|
- |
|
|
- |
% |
Georgia
|
|
|
1,396 |
|
|
1,503 |
|
|
(7 |
) |
Maryland |
|
|
2,684 |
|
|
- |
|
|
- |
|
New
Jersey |
|
|
2,755 |
|
|
- |
|
|
- |
|
Tennessee
|
|
|
1,545 |
|
|
1,716 |
|
|
(10 |
) |
Virginia
|
|
|
2,056 |
|
|
1,853 |
|
|
11 |
|
(1) |
We
measure the effects of weather on our businesses using “degree days.” The
measure of degree days for a given day is the difference between the
average daily actual temperature and the baseline temperature of 65
degrees Fahrenheit. Heating degree days result when the average daily
actual temperature is less than 65-degrees. Generally, increased heating
degree days result in greater demand for gas on our distribution
systems. |
First
quarter 2005 compared to first quarter 2004
Operating
Margin The
increase in operating margin of $73 million, or 41%, was primarily a result of
the addition of NUI’s operations, which contributed $70 million. The remainder
of the increase was the combination of higher operating margin at Atlanta Gas
Light offset by lower operating margin at Virginia Natural Gas. The increase at
Atlanta Gas Light was a result of higher PRP revenues, additional revenue from
gas storage carrying charges billed to marketers and increased customer usage
and growth. These results were offset by a reduction in operating margins at
Virginia Natural Gas, resulting from lower use per heating degree day and a
change in the weather normalization adjustment calculation resulting from a
regulatory order.
Operating
Expenses The
increase in operating expenses of $32 million, or 33%, primarily was a result of
the addition of NUI’s operations, which contributed $37 million. This increase
was offset primarily by lower operating expenses at Virginia Natural Gas,
largely in part to lower bad debt and payroll expenses.
EBIT The
increase in EBIT of $41 million was primarily from the inclusion of NUI’s
operations, which contributed approximately $34 million.
Retail Energy Operations
Our
retail energy operations segment consists of SouthStar, a joint venture formed
in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas and
Dynegy Inc. (Dynegy). The purpose was to market natural gas and related services
to retail customers on an unregulated basis, principally in Georgia. On March
11, 2003, we purchased Dynegy’s 20% ownership interest.
We
currently own a non-controlling 70% financial interest in SouthStar, and
Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all
significant management decisions require approval of both owners. On March 29,
2004, we executed an amended and restated partnership agreement with Piedmont.
This amended and restated partnership agreement calls for SouthStar’s future
earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to
Piedmont. In addition, we executed a services agreement which provided that AGL
Services Company will provide and administer accounting, treasury, internal
audit, human resources and information technology functions for
SouthStar.
Results
of operations for our
retail energy operations segment for the three months ended March 31, 2005 and
2004 are shown in the following table.
|
|
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Operating
revenues |
|
$ |
314 |
|
$ |
307 |
|
$ |
7 |
|
Cost
of sales |
|
|
248 |
|
|
250 |
|
|
(2 |
) |
Operating
margin |
|
|
66 |
|
|
57 |
|
|
9 |
|
Operating
expenses |
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance |
|
|
13 |
|
|
13 |
|
|
- |
|
Depreciation
and amortization |
|
|
- |
|
|
- |
|
|
- |
|
Taxes
other than income |
|
|
- |
|
|
- |
|
|
- |
|
Total
operating expenses |
|
|
13 |
|
|
13 |
|
|
- |
|
Operating
income |
|
|
53 |
|
|
44 |
|
|
9 |
|
Minority
interest (1) |
|
|
(13 |
) |
|
(11 |
) |
|
(2 |
) |
EBIT |
|
$ |
40 |
|
|
33 |
|
$ |
7 |
|
Average
customers (in thousands) |
|
|
531 |
|
|
550 |
|
|
(4 |
%) |
Market
share in Georgia |
|
|
36 |
% |
|
37 |
% |
|
(3 |
%) |
(1)
Minority interest adjusts our earnings to reflect our 75% share of SouthStar’s
earnings.
First
quarter 2005 compared to first quarter 2004
Operating
Margin The $9
million increase in operating margin is primarily a result of higher commodity
margins in 2005, partly offset by lower sales volumes due to 7% warmer weather
in 2004. These margins resulted from larger storage spreads and favorable asset
management activities during the quarter.
Operating
Expenses
Operating expenses were virtually flat year-over-year. Bad debt expense
decreased $2 million in 2005 as a result of significantly lower write-offs.
However, this was substantially offset by a one-time vendor performance credit
and the timing of marketing expenses in 2005.
EBIT
SouthStar’s EBIT contribution of $40 million in 2005 was $7 million higher than
last year, reflecting higher commodity margins and favorable asset management
results during the quarter.
Wholesale
Services
Wholesale
services consists of Sequent, our subsidiary involved in asset optimization,
transportation, storage, producer and peaking services and wholesale marketing.
Our asset optimization business focuses on capturing economic value from idle or
underutilized natural gas assets, which are typically amassed by companies via
investments in or contractual rights to natural gas transportation and storage
assets. Margin is typically created in this business by participating in
transactions that balance the needs of varying markets and time
horizons.
Sequent
provides its customers with natural gas from the major producing regions and
market hubs primarily in the Eastern and Mid-Continental United States. Sequent
also purchases 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
end-use customers.
The
following is a summary of significant developments with regard to our wholesale
services segment that have occurred since we filed our 2004 Annual Report on
Form 10-K on February 15, 2005.
Asset
Management Transactions Our asset
management customers include our own utilities, nonaffiliated utilities,
municipal utilities and large industrial customers. These customers must
contract for transportation and storage services to meet their demands, and they
typically contract for these services on a 365-day basis even though they may
only need a portion of these services to meet their peak demands for a much
shorter period. We enter into agreements with these customers, either through
contract assignment or agency arrangement, whereby we use their rights to
transportation and storage services during periods when they do not need them.
We capture margin by optimizing the purchase, transportation, storage and sale
of natural gas, and we typically either share profits with customers or pay them
a fee for using their assets.
On April
1, 2005, in connection with the acquisition of NUI, Sequent commenced asset
management responsibilities for Elizabethtown Gas, Florida Gas and Elkton Gas.
The following table summarizes Sequent’s asset management transactions with our
affiliated utilities.
Dollars
in millions |
Duration
of contract (in years) |
Expiration
date |
Frequency
of payment |
Profits
shared / fees paid in 2005
(1) |
Profits
shared / fees paid in 2004 (2) |
Virginia
Natural Gas |
5 |
Oct
2005 |
Annually |
$- |
$3 |
Atlanta
Gas Light |
3 |
Feb
2006 |
Semi-annually |
3 |
4 |
Chattanooga
Gas |
3 |
Mar
2007 |
Annually |
2 |
1 |
Elizabethtown
Gas |
3 |
Mar
2008 |
Monthly |
- |
- |
Florida
Gas |
3 |
Mar
2008 |
Quarterly |
- |
- |
Elkton
Gas |
2 |
Mar
2007 |
Monthly |
- |
- |
(1) |
For
the three months ended March 31. |
(2) |
For
the twelve months ended December 31. |
Energy
Marketing and Risk Management Activities The
tables below illustrate the change in the net fair value of Sequent’s derivative
instruments and energy-trading contracts during the three months ended March 31,
2005 and 2004, and provide details of the net fair value of contracts
outstanding as of March 31, 2005. Sequent’s storage positions are affected by
changes in the New York Mercantile Exchange, Inc. (NYMEX) average
price.
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004 |
|
Net
fair value of contracts outstanding at beginning of period |
|
$ |
17 |
|
|
($5 |
) |
Contracts
realized or otherwise settled during period |
|
|
9 |
|
|
4 |
|
Change
in net fair value of contracts |
|
|
(15 |
) |
|
10 |
|
Net
fair value of contracts outstanding at end of period |
|
|
11 |
|
|
9 |
|
Less
net fair value of contracts outstanding at beginning of
period |
|
|
17 |
|
|
(5 |
) |
Unrealized
(loss) gain related to changes in the fair value of derivative
instruments |
|
|
($6 |
) |
$ |
14 |
|
The
sources of our net fair value at March 31, 2005 are as follows:
In
millions |
|
Matures
through March 2006 |
|
Matures
through March 2009 |
|
Matures
through March 2011 |
|
Matures
after March 2012 |
|
Total
net fair value |
|
Prices
actively quoted (1) |
|
$ |
19 |
|
|
1 |
|
|
- |
|
|
- |
|
$ |
20 |
|
Prices
provided by other external sources (1) |
|
|
(13 |
) |
|
3 |
|
|
1 |
|
|
- |
|
|
(9 |
) |
(1) |
The
“prices actively quoted” category represents Sequent’s positions in
natural gas, which are valued exclusively using NYMEX futures prices.
“Prices provided by other external sources” are basis transactions that
represent the cost to transport the commodity from a NYMEX delivery point
to the contract delivery point. Our basis spreads are primarily based on
quotes obtained either directly from brokers or through electronic trading
platforms. |
Mark-to-Market
versus Lower of Average Cost or Market We
purchase natural gas for storage when the current market price we pay plus the
cost for storage is less than the market price we could receive in the future.
We attempt to mitigate substantially all of our commodity price risk associated
with our storage portfolio. We use derivative instruments to reduce the risk
associated with future changes in the price of natural gas. We sell NYMEX
futures contracts or other over-the-counter derivatives in forward months to
substantially lock-in the profit margin we will ultimately realize when the
stored gas is actually sold.
Natural
gas stored in inventory is accounted for differently than the derivatives we use
to mitigate the commodity price risk associated with our storage portfolio. The
difference in accounting can result in volatility in our reported net income,
even though the profit margin is essentially unchanged from the date the
transactions were consummated. Natural gas that we purchase and inject into
storage is accounted for at the lower of average cost or market. The derivatives
we use to mitigate commodity price risk are accounted for at fair value and
marked to market each period. These differences in our accounting treatment
result in volatility in our reported net income.
Earnings
Volatility And Price Sensitivity Over
time, gains or losses on the sale of inventory will be offset by losses or gains
on the derivatives used as hedges, resulting in the realization of the profit
margin we expected when we entered into the transactions. Accounting differences
cause Sequent’s earnings on its storage positions to be affected by natural gas
price changes, even though the economic profits remain essentially unchanged.
Based upon our storage positions at March 31, 2005, a $0.10 change in the
forward NYMEX prices would result in a $0.5 million impact to Sequent’s EBIT.
Storage
Inventory Outlook The NYMEX
forward curve graph set forth below reflects the NYMEX natural gas prices as of
December 31, 2004 and March 31, 2005 for the period of April 2005 through March
2006, and reflects the prices at which we could buy natural gas at the Henry Hub
for delivery in the same time period. April 2005 futures expired on March 29,
2005; however they are included in the table below as they coincide with the
April storage withdrawals. The Henry Hub, located in Louisiana, is the largest
centralized point for natural gas spot and futures trading in the United States.
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.
The NYMEX
forward curve graph also displays the significant increase in NYMEX prices
experienced during the first quarter of 2005. As shown in the table following
the graph, a significant portion of our inventory in storage as of March 31,
2005 is scheduled for withdrawal in July and August. Since we have these NYMEX
contracts in place, our original economic profit margin is unaffected. However,
the increase in NYMEX prices during the first quarter of 2005 resulted in
unrealized losses associated with our NYMEX contracts. During the first quarter
of 2004, we experienced the same phenomenon, albeit to a lesser degree. See
further discussions in “Results of Operations” below.
As shown
in the table below, “Open Futures NYMEX Contracts” represents the volume in
contract equivalents of the transactions we executed to lock in our storage
inventory margin. Each contract equivalent represents 10,000 million British
thermal units (MMBtu’s). As of March 31, 2005, the expected withdrawal schedule
of this inventory is reflected in items (B) and (C) of the table to the graph.
At March 31, 2005, the weighted average cost of gas (WACOG) in salt dome storage
was $6.74, and the WACOG for gas in reservoir storage was $6.33.
The table
also reflects that our storage inventory is fully hedged with futures as
evidenced by the NYMEX short positions (A) being equal to the physical long
positions (B and C), which results in an overall locked-in margin, timing
notwithstanding. Expected gross margin after regulatory sharing reflects the
gross margin we would generate in future periods based on the forward curve and
inventory withdrawal schedule at March 31, 2005. Our current inventory level and
pricing should result in gross margin of approximately $7 million through March
2006. This gross margin will likely change as we adjust our daily injection and
withdrawal plans in response to changes in market conditions in future
months.
|
Apr 05 |
May 05 |
Jun 05 |
Jul 05 |
Aug 05 |
Sep 05 |
Oct 05 |
Nov 05 |
Dec 05 |
Jan 06 |
Feb 06 |
Mar 06 |
Total |
(A) |
(114) |
(89) |
(66) |
(165) |
(225) |
(21) |
(68) |
- |
- |
- |
(41) |
(46) |
(835) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(B) |
80 |
64 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
144 |
(C) |
34 |
25 |
66 |
165 |
225 |
21 |
68 |
- |
- |
- |
41 |
46 |
691 |
|
114 |
89 |
66 |
165 |
225 |
21 |
68 |
- |
- |
- |
41 |
46 |
835 |
(D) |
$0.8 |
$0.7 |
$0.4 |
$1.1 |
$2.0 |
$0.3 |
$0.7 |
- |
- |
- |
$0.6 |
$0.6 |
$7.2 |
(A) Open
futures NYMEX contracts (short) long (in MMBtu)
(B)
Physical salt dome withdrawal schedule (in MMBtu)
(C)
Physical reservoir withdrawal schedule (in MMBtu)
(D)
Expected gross margin, in millions, after regulatory sharing for withdrawal
activity
Credit
Rating Sequent
has certain trade and credit contracts that have explicit credit rating trigger
events in case of a credit rating downgrade. These rating triggers typically
give counterparties the right to suspend or terminate credit if our credit
ratings are downgraded to non-investment grade status. Under such circumstances,
we would need to post collateral to continue transacting business with some of
our counterparties. Posting collateral would have a negative effect on our
liquidity. If such collateral were not posted, our ability to continue
transacting business with these counterparties would be impaired. If at March
31, 2005, our credit ratings had been downgraded to non-investment grade, the
required amounts to satisfy potential collateral demands under such agreements
between Sequent and its counterparties would have totaled $15
million.
Results
of Operations for our
wholesale services segment for the
three months ended March 31, 2005 and 2004 are as follows:
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Operating
revenues |
|
$ |
11 |
|
$ |
20 |
|
|
($9 |
) |
Cost
of sales |
|
|
- |
|
|
- |
|
|
|
|
Operating
margin |
|
|
11 |
|
|
20 |
|
|
(9 |
) |
Operating
expenses |
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance |
|
|
7 |
|
|
8 |
|
|
(1 |
) |
Depreciation
and amortization |
|
|
- |
|
|
- |
|
|
- |
|
Taxes
other than income |
|
|
- |
|
|
- |
|
|
- |
|
Total
operating expenses |
|
|
7 |
|
|
8 |
|
|
(1 |
) |
Operating
income |
|
|
4 |
|
|
12 |
|
|
(8 |
) |
Other
income |
|
|
- |
|
|
- |
|
|
|
|
EBIT |
|
$ |
4 |
|
$ |
12 |
|
|
($8 |
) |
|
|
|
|
|
|
|
|
|
|
|
Metrics |
|
|
|
|
|
|
|
|
|
|
Physical
sales volumes (Bcf/day) |
|
|
2.3 |
|
|
2.1 |
|
|
10 |
% |
First
quarter 2005 compared to first quarter 2004
Operating
Margin The $9
million reduction in operating margin reflects the negative impacts of changes
in forward NYMEX prices during late 2004 and early 2005, partially offset by
improved origination operations during the 2005 period. During December 2004,
there was a significant decline in forward NYMEX prices which resulted in the
recognition of gains associated with the financial instruments used to hedge
Sequent’s inventory held in storage. The majority of this inventory was
scheduled for withdrawal during the first quarter of 2005 and, as a result, $5
million of margin that was originally anticipated to be recognized during the
first quarter of 2005 was recognized in 2004. The results for the first quarter
of 2004 did not experience a similar impact. Also, as a result of an increase in
forward NYMEX prices during the first quarter of 2005, the results for this
period reflect the recognition of $8 million of losses associated with our
inventory hedges. The results for the first quarter of 2004 were similarly
affected; however, the earnings impact was less than $1 million. Partially
offsetting the negative impacts of forward NYMEX price changes was a $5 million
increase in origination results in the Northeast market due to higher
transportation spreads.
Operating
Expenses Operating
expenses decreased $1 million as a result of lower outside services costs
associated with the prior year implementation of our ETRM system and certain
one-time SOX compliance costs incurred in 2004. The reduced expenses were
partially offset by higher payroll costs related to increased
headcount.
Energy
Investments
Our
energy investments segment includes:
· |
Pivotal
Propane of Virginia |
· |
50%
ownership interset in Saltville Gas Storage Company, LLC
(Saltville) |
On April
27, 2005, we announced our agreement to sell our 50 percent interest in
Saltville and our wholly-owned subsidiaries in Virginia Gas Pipeline and
Virginia Gas Storage to Duke Energy Corporation, the other 50 percent partner in
Saltville LLC. We acquired these Virginia assets in November 2004 with our
purchase of NUI. We will retain Virginia Gas Distribution Company, another NUI
asset, which has 270 customers and annual throughput of 240,000
Dth.
When
completed, the sale will make Duke Energy the sole owner of Saltville, which
operates a storage facility that currently has approximately 2.0 Bcf of
capacity. AGL Resources will receive, subject to working capital adjustments,
$62 million in cash at closing and will utilize the proceeds to repay debt and
for other general corporate purposes. The transaction is not expected to have a
material impact on our earnings. Closing of the transaction, which is
conditional upon regulatory approvals, including approval from the Virginia
State Corporation Commission, is expected in the third quarter of
2005.
Results
of operations for our
energy investments segment for the three months ended March 31, 2005 and 2004
are shown in the following table.
|
|
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Operating
revenues |
|
$ |
12 |
|
$ |
1 |
|
$ |
11 |
|
Cost
of sales |
|
|
3 |
|
|
- |
|
|
3 |
|
Operating
margin |
|
|
9 |
|
|
1 |
|
|
8 |
|
Operating
expenses |
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance |
|
|
3 |
|
|
1 |
|
|
2 |
|
Depreciation
and amortization |
|
|
2 |
|
|
- |
|
|
2 |
|
Taxes
other than income |
|
|
- |
|
|
- |
|
|
- |
|
Total
operating expenses |
|
|
5 |
|
|
1 |
|
|
4 |
|
Operating
income |
|
|
4 |
|
|
- |
|
|
4 |
|
Other
income |
|
|
1 |
|
|
1 |
|
|
- |
|
EBIT |
|
$ |
5 |
|
$ |
1 |
|
$ |
4 |
|
First
quarter 2005 compared to first quarter 2004
Operating
Margin Operating
margin in the energy investments segment increased $8 million, primarily as a
result of the addition of Jefferson Island (which contributed $4 million of the
increase), the addition of Virginia Gas Company and Saltville obtained with the
NUI acquisition (which contributed $2 million of the increase) and improved
margins at AGL Networks (which contributed approximately $1 million of the
increase) during the quarter.
Operating
Expenses Operating
expenses in the Energy Investments segment increased $4 million, primarily
driven by the addition of Pivotal Jefferson Island, Virginia Gas Company and
Saltville and additional expenses at AGL Networks associated with the projects
in Phoenix and Atlanta.
EBIT
The $4
million EBIT growth year-over-year is from the addition of Jefferson
Island.
Corporate
Our
corporate segment includes our nonoperating business units, including AGL
Services Company (AGSC), AGL Capital Corporation (AGL Capital) and Pivotal
Energy Development (Pivotal). AGSC is a service company established in
accordance with the Public Utility Holding Company Act of 1935, as amended
(PUHCA). AGL Capital provides for our ongoing financing needs through a
commercial paper program, the issuance of various debt and hybrid securities,
and other financing arrangements.
Pivotal
coordinates, among our related operating segments, the development, construction
or acquisition of assets in the Southeast and Mid-Atlantic regions in order to
extend our natural gas capabilities and improve system reliability while
enhancing service to our customers in those areas. The focus of Pivotal’s
commercial activities is to improve the economics of system reliability and
natural gas deliverability in these targeted regions.
We
allocate substantially all of AGSC’s and AGL Capital’s operating expenses and
interest costs to our operating segments in accordance with PUHCA and state
regulations. Our corporate segment also includes intercompany eliminations for
transactions between our operating business segments. Our EBIT results include
the impact of these allocations to the various operating segments. The
acquisition of additional assets, such as our recent acquisitions of NUI and
Jefferson Island Storage & Hub, typically will enable us to allocate
corporate costs across a larger number of businesses and, as a result, lower the
relative allocations charged to those business units we owned prior to the
acquisition of the new businesses.
Results
of operations for our
corporate segment for the
three months ended March 31, 2005 and 2004 are as follows:
|
|
Three
months ended March 31, |
|
In
millions |
|
2005 |
|
2004 |
|
2005
vs. 2004 |
|
Payroll |
|
$ |
13 |
|
$ |
11 |
|
$ |
2 |
|
Benefits
and incentives |
|
|
8 |
|
|
10 |
|
|
(2 |
) |
Outside
services |
|
|
8 |
|
|
6 |
|
|
2 |
|
Depreciation
and amortization |
|
|
3 |
|
|
3 |
|
|
- |
|
Taxes
other than income |
|
|
2 |
|
|
2 |
|
|
- |
|
Other |
|
|
11 |
|
|
11 |
|
|
- |
|
Total
operating expenses before allocations |
|
|
45 |
|
|
43 |
|
|
2 |
|
Allocation
to operating segments |
|
|
(42 |
) |
|
(38 |
) |
|
(4 |
) |
Total
operating expenses |
|
|
3 |
|
|
5 |
|
|
(2 |
) |
Other
losses |
|
|
- |
|
|
- |
|
|
- |
|
EBIT |
|
|
($3 |
) |
|
($5 |
) |
|
$2 |
|
First
quarter 2005 compared to first quarter 2004 The
corporate segment had a $2 million positive EBIT variance in the first quarter
of 2005 relative to the same period last year. The key drivers of corporate
operating expense are detailed in the above table and summarized
below.
Payroll
Expense Corporate
payroll expenses were $2 million higher than last year. Approximately $1 million
of the increase related to the acquisition of NUI. The remaining $1 million is
the result of increased headcount.
Benefits
and Incentives A $2
million reduction in benefits and incentive expenses was primarily the result of
$1 million lower incentive pay and $1 million lower group insurance expense
charged to AGSC.
Outside
Services A $2
million increase in outside services resulted primarily from additional spending
in the information technology area, including $2 million in projects related to
NUI integration and $1 million related to customer solution
projects.
Other Our
corporate segment recorded a $2 million loss on the retirement of some
information technology assets in the first quarter of 2004 that was absent from
this year’s results.
Liquidity
and Capital Resources
We rely
on operating cash flow; short-term borrowings under our commercial paper
program, which is backed by our supporting credit agreement (Credit Facility);
and borrowings or stock issuances in the long-term capital markets to meet our
capital and liquidity requirements. Our issuance of various securities,
including long-term and short-term debt, is subject to customary approval or
authorization by state and federal regulatory bodies including state public
service commissions and the SEC. Furthermore, a substantial portion of our
consolidated assets, earnings and cash flow is derived from the operation of our
regulated utility subsidiaries, whose legal authority to pay dividends or make
other distributions to us is subject to regulation.
The
availability of borrowings and unused availability under our Credit Facility is
limited and subject to conditions specified within the Credit Facility, which we
currently meet. These conditions specified and defined within the Credit
Facility include:
· |
compliance
with certain financial covenants |
· |
the
continued accuracy of representations and warranties contained in the
agreement, and |
· |
our
total debt-to-capital ratio |
Our total
cash and available liquidity under our Credit Facility as of the dates indicated
are represented in the table below.
In
millions |
|
March
31, 2005 |
|
Dec.
31, 2004 |
|
Unused
availability under the Credit Facility |
|
$ |
750 |
|
$ |
750 |
|
Cash
and cash equivalents |
|
|
24 |
|
|
49 |
|
Total
cash and available liquidity under the Credit Facility |
|
$ |
774 |
|
$ |
799 |
|
We
believe these sources will be sufficient for our working capital needs, debt
service obligations and scheduled capital expenditures for the foreseeable
future. The relatively stable operating cash flows of our distribution
operations businesses currently contribute most of our cash flow from
operations, and we anticipate this to continue in the future. We will continue
to evaluate our need to increase our available liquidity based upon our view of
natural gas prices and liquidity requirements established by the rating
agencies. We have historically had a working capital deficit, primarily as a
result of our borrowings of short-term debt to finance the purchase of long-term
assets, principally property, plant and equipment. However, our liquidity and
capital resource requirements may change in the future due to a number of
factors, some of which we cannot control. These factors include:
· |
the
impact of the integration of NUI |
· |
the
seasonal nature of the natural gas business and our resulting short-term
borrowing requirements, which typically peak during colder
months |
· |
increased
gas supplies required to meet our customers’ needs during cold
weather |
· |
changes
in wholesale prices and customer demand for our products and
services |
· |
regulatory
changes and changes in rate-making policies of regulatory commissions
|
· |
contractual
cash obligations and other commercial commitments
|
· |
pension
and postretirement funding requirements |
· |
changes
in income tax laws |
· |
margin
requirements resulting from significant increases or decreases in our
commodity prices |
Contractual
Obligations and Commitments We have
incurred various contractual obligations and financial commitments in the normal
course of our operations 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 calculate any expense
pension contributions using an actuarial method called the projected unit credit
cost method, and as a result of our calculations, we do not expect to make a
pension contribution in 2005. The following table illustrates our expected
future contractual obligations:
|
|
|
|
Payments
due before December 31, |
|
|
|
|
|
|
|
2006 |
|
2008 |
|
2010 |
|
|
|
|
|
|
|
& |
|
& |
|
& |
|
In
millions |
|
Total |
|
2005 |
|
2007 |
|
2009 |
|
Thereafter |
|
Long-term
debt (1)
(2) |
|
$ |
1,618 |
|
$ |
1 |
|
$ |
2 |
|
$ |
2 |
|
$ |
1,613 |
|
Short-term
debt (2) |
|
|
38 |
|
|
38 |
|
|
- |
|
|
- |
|
|
- |
|
Pipeline
charges, storage capacity and gas supply (2)
|
|
|
1,756 |
|
|
208 |
|
|
502 |
|
|
423 |
|
|
623 |
|
Commodity
and transportation charges |
|
|
129 |
|
|
20 |
|
|
23 |
|
|
14 |
|
|
72 |
|
Pipeline
replacement program costs (3) |
|
|
346 |
|
|
76 |
|
|
178 |
|
|
92 |
|
|
- |
|
ERC (3) |
|
|
74 |
|
|
12 |
|
|
12 |
|
|
11 |
|
|
39 |
|
Operating
leases
(4) |
|
|
146 |
|
|
14 |
|
|
32 |
|
|
28 |
|
|
72 |
|
Communication/network
service and maintenance |
|
|
12 |
|
|
5 |
|
|
7 |
|
|
- |
|
|
- |
|
Total |
|
$ |
4,119 |
|
$ |
373 |
|
$ |
756 |
|
$ |
570 |
|
$ |
2,420 |
|
(1) |
Includes
$232 million of Notes Payable to Trusts, callable in 2006 and 2007.
|
(2) |
Does
not include the interest expense associated with the long-term and
short-term debt. |
(3) |
Charges
recoverable through a purchased gas adjustment mechanism or alternatively
billed to Marketers. Also includes demand charges associated with
Sequent. |
(4) |
Charges
recoverable through rate rider mechanisms. |
(5) |
We
have certain operating leases with provisions for step rent or escalation
payments, or certain lease concessions. We account for these leases by
recognizing the future minimum lease payments on a straight-line basis
over the respective minimum lease terms in accordance with SFAS No. 13,
“Accounting for Leases.” However, this accounting treatment does not
affect the future annual operating lease cash obligations as shown
herein. |
We have
certain operating leases with provisions for step rent or escalation payments,
or certain lease concessions. We account for these leases by recognizing the
future minimum lease payments on a straight-line basis over the respective
minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.”
However, this accounting treatment does not affect the future annual operating
lease cash obligations as shown herein.
SouthStar
has natural gas purchase commitments related to the supply of minimum natural
gas volumes to its customers. These commitments are priced on an index plus
premium basis. At March 31, 2005, SouthStar had obligations under these
arrangements for 11 Bcf through December 31, 2005.
We also
have incurred various contingent financial commitments in the normal course of
business. Contingent financial commitments represent obligations that become
payable only if certain pre-defined events occur, such as financial guarantees
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 expected contingent financial commitments as of March 31,
2005:
|
|
|
|
Commitments
due before December 31, |
|
|
|
|
|
|
|
2006 |
|
2008 |
|
2010 |
|
|
|
|
|
|
|
& |
|
& |
|
& |
|
In
millions |
|
Total |
|
2005 |
|
2007 |
|
2009 |
|
Thereafter |
|
Guarantees
(1) |
|
$ |
7 |
|
$ |
7 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
Standby
letters of credit, performance/ surety bonds |
|
|
15 |
|
|
12 |
|
|
3 |
|
|
- |
|
|
- |
|
Total
other commercial commitments |
|
$ |
22 |
|
$ |
19 |
|
$ |
3 |
|
$ |
- |
|
$ |
- |
|
(1)
We provide guarantees on behalf of SouthStar. We guarantee 70% of
SouthStar’s obligations to SNG under certain agreements between the
parties up to a maximum of $7 million if SouthStar fails to make payment
to SNG. |
Investing
activities Our cash
used in investing activities consists primarily of property, plant and equipment
expenditures. As shown in the following table, we made investments of $81
million in the three months ended March 31, 2005 and $45 million in the same
period in 2004.
|
|
Three
months ended |
|
|
|
March
31, |
|
In
millions |
|
2005 |
|
2004 |
|
Distribution
operations |
|
$ |
72 |
|
$ |
36 |
|
Retail
energy operations |
|
|
- |
|
|
2 |
|
Wholesale
services |
|
|
- |
|
|
3 |
|
Energy
investments |
|
|
3 |
|
|
4 |
|
Corporate |
|
|
6 |
|
|
- |
|
Total
property, plant and equipment expenditures |
|
$ |
81 |
|
$ |
45 |
|
The
increase of $36 million is primarily from higher expenditures at our
distribution operations segment, including $32 million for the acquisition of a
250-mile pipeline in Georgia from SNG and approximately $7 million in
expenditures at Elizabethtown Gas and Florida Gas.
Financing
activities Our
financing activities are primarily composed of borrowings and payments of
short-term debt, payments of Medium-Term notes, borrowings of senior notes,
distributions to minority interests, cash dividends on our common stock and the
issuance of common stock. 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 by us of the
percentage of total debt relative to our total capitalization, as well as the
term and interest rate profile of our debt securities.
We also
work to maintain or improve our credit ratings on our senior notes to
effectively manage our existing financing costs and enhance our ability to raise
additional capital on favorable terms. Factors we consider important in
assessing our credit ratings include: our balance sheet leverage, capital
spending, earnings, cash flow generation, available liquidity and overall
business risks. We do not have any trigger events in our debt instruments that
are tied to changes in our specified credit ratings or our stock price and have
not entered into any transaction that would require us to issue equity based on
credit ratings or other trigger events. As of April 2005, our senior unsecured
debt ratings are BBB+ from Standard & Poor’s Rating Services (S&P), Baa1
from Moody’s Investor Service and A- from Fitch Ratings (Fitch).
Our
credit ratings may be subject to revision or withdrawal at any time by the
assigning rating organization, and each rating should be evaluated independently
of any other rating. We cannot ensure that a rating will remain in effect for
any given period of time or that a rating will not be lowered or withdrawn
entirely by a rating agency if, in its judgment, circumstances so warrant. If
the rating agencies downgrade our ratings, particularly below investment grade,
it may significantly limit our access to the commercial paper market and our
borrowing costs would increase. In addition, we would likely be required to pay
a higher interest rate in future financings, and our potential pool of investors
and funding sources would decrease.
Our debt
instruments and other financial obligations include provisions that, if not
complied with, could require early payment, additional collateral support or
similar actions. Our most important default events include maintaining covenants
with respect to maximum leverage ratio, minimum net worth, insolvency events,
nonpayment of scheduled principal or interest payments, acceleration of other
financial obligations and change of control provisions. Our Credit Facility’s
financial covenants and our
(PUHCA) financing authority 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% of
debt-to-total-capitalization. We are currently in compliance with all existing
debt provisions and covenants.
We
believe that accomplishing these 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. The components of
our capital structure, as of the dates indicated, are summarized in the
following table:
In
millions |
|
March
31, 2005 |
|
December
31, 2004 |
|
March
31, 2004 |
|
Short-term
debt |
|
$ |
38 |
|
|
1 |
% |
$ |
334 |
|
|
10 |
% |
$ |
100 |
|
|
5 |
% |
Current
portion of long-term debt |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
33 |
|
|
1 |
|
Long-term
debt (1) |
|
|
1,618 |
|
|
52 |
|
|
1,623 |
|
|
48 |
|
|
970 |
|
|
46 |
|
Total
debt |
|
|
1,656 |
|
|
53 |
|
|
1,957 |
|
|
58 |
|
|
1,103 |
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority
interest |
|
|
30 |
|
|
1 |
|
|
36 |
|
|
1 |
|
|
27 |
|
|
1 |
|
Common
equity |
|
|
1,446 |
|
|
46 |
|
|
1,385 |
|
|
41 |
|
|
1,002 |
|
|
47 |
|
Total
capitalization |
|
$ |
3,132 |
|
|
100 |
% |
$ |
3,378 |
|
|
100 |
% |
$ |
2,132 |
|
|
100 |
% |
(1) |
Net
of interest rate swaps |
Short-term
debt Our
short-term debt is composed of borrowings under our commercial paper program,
Sequent’s line of credit, the current portion of our capital lease obligation
due within the next year and SouthStar’s line of credit. The decrease in our
short-term debt of $295 million is primarily a result of payments on outstanding
commercial paper from:
· |
cash
generated from strong operating results |
· |
positive
working capital from lower inventory and receivable requirements
|
Refinancing
of Gas Facility Revenue Bonds On April
19, 2005, our wholly-owned subsidiary, Pivotal Utility Holdings, Inc. completed
the refinancing of $20 million in Gas Facility Revenue Bonds due October 1,
2024. These bonds which had a fixed interest rate of 6.4% were refunded with $20
million of adjustable rate Gas Facility Revenue Bonds. The maturity date of
these bonds remains October 1, 2024. The bonds were issued at an initial
interest rate of 2.8%, and initially have a 35-day auction period, where the
interest rate will adjust every 35 days.
It is
also our intent to refinance an additional $46 million in Gas Facility Revenue
Bonds bearing interest at 6.35% with an adjustable rate 35-day auction period.
Upon the completion of certain regulatory approvals, we anticipate the closing
to be completed by May 2005.
Dividends
on Common Stock In
February 2005, we announced a 7% increase in our common stock dividend, raising
the quarterly dividend from $0.29 per share to $0.31 per share, which equates to
an indicated annual dividend of $1.24 per share. The increase in our common
stock dividend of $5 million for the three months ended March 31, 2005 as
compared to the same period last year was a result of our increased quarterly
dividend and the increase in the number of shares outstanding as a result of our
November 2004 equity offering.
Market Risks
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 a particular instrument or commodity.
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 the overall establishment of risk
management policies and the monitoring of compliance with and adherence to the
terms within these policies, including approval and authorization levels and
delegation of these levels. Our RMC consists of senior executives who monitor
commodity price risk positions, corporate exposures, credit exposures and
overall results of our risk management activities. The RMC 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.
Commodity
Price Risk
Wholesale
Services This
segment routinely utilizes various types of financial and other instruments to
mitigate certain commodity price risks inherent in the natural gas industry.
These instruments include a variety of exchange-traded and over-the-counter
energy contracts, such as forward contracts, futures contracts, option contracts
and financial swap agreements. The following table includes the fair values and
average values of our energy marketing and risk management assets and
liabilities as of March 31, 2005, December 31, 2004 and March 31, 2004. We based
the average values on monthly averages for the three months ended March 31, 2005
and the twelve months ended December 31, 2004.
|
|
|
|
|
|
Natural
gas contracts |
|
Average
values |
|
Value
at: |
|
In
millions |
|
Three
months ended March 31, 2005 |
|
Twelve
months ended Dec. 31, 2004 |
|
March
31, 2005 |
|
Dec.
31, 2004 |
|
March
31, 2004 |
|
Asset |
|
$ |
54 |
|
$ |
28 |
|
$ |
73 |
|
$ |
36 |
|
$ |
30 |
|
Liability |
|
|
38 |
|
|
21 |
|
|
61 |
|
|
19 |
|
|
21 |
|
We employ
a systematic approach to the evaluation and management of the risks associated
with our contracts related to wholesale marketing and risk management, including
value-at-risk (VaR). VaR 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.
We use a
1-day and a 10-day holding period and a 95% confidence interval to evaluate our
VaR exposure. A 95% confidence interval means there is a 5% probability that the
actual change in portfolio value will be greater than the calculated VaR value
over the holding period. We calculate VaR based on the variance-covariance
technique. This technique requires several assumptions for the basis of the
calculation, such as 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.
Our 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 we generally manage
physical gas assets and economically protect our positions by hedging in the
futures markets, our open exposure is generally minimal, permitting us to
operate within relatively low VaR limits. We employ daily risk testing, using
both VaR and stress testing, to evaluate the risks of our open positions.
Our
management actively monitors open commodity positions and the resulting VaR. We
continue to maintain a relatively matched book, where our total buy volume is
close to our sell volume, with minimal open commodity risk. Based on a 95%
confidence interval and employing a 1-day and a 10-day holding period for all
positions, our portfolio of positions for the three months ended March 31, 2005
had the following 1-day and 10-day holding period VaRs:
|
|
Three
months ended March 31, 2005 |
|
In
millions |
|
1-day |
|
10-day |
|
Period
end (1) |
|
$ |
0.0 |
|
$ |
0.1 |
|
Average |
|
|
0.2 |
|
|
0.5 |
|
High |
|
|
0.4 |
|
|
1.3 |
|
Low
(1) |
|
|
0.0 |
|
|
0.0 |
|
(1) |
$0.0
values represent amounts less than $0.1 million.
|
Retail
Energy Operations
SouthStar’s use of derivatives is governed by a risk management policy which
prohibits the use of derivatives for speculative purposes. This policy also
establishes VaR limits of $0.5 million on a 1-day holding period and $0.7
million on a 10-day holding period. A 95% confidence interval is used to
evaluate VaR exposure. The maximum VaR experienced during the three months ended
March 31, 2005 was less than $0.2 million for the 1-day holding period and $0.5
million for the 10-day holding period.
Credit
Risk
Sequent
may require its counterparties to pledge additional collateral when deemed
necessary. We conduct credit evaluations and obtain appropriate internal
approvals for our 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, we
require credit enhancements by way of guaranty, cash deposit or letter of credit
for transaction counterparties that do not meet the minimum ratings threshold.
Sequent
evaluates its counterparties using the S&P equivalent credit rating which is
determined by a process of converting the lower of the S&P or Moody’s rating
to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to
AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by
S&P and Moody’s. A counterparty that does not have an external rating is
assigned an internal rating based a variety of financial metrics.
The
weighted average credit rating is obtained by multiplying each counterparty’s
assigned internal rating by the counterparty’s credit exposure and the
individual results are then summed for all counterparties. That total is divided
by the aggregate total counterparties’ exposure. This numeric value is converted
to an S&P equivalent. Under the refined methodology, Sequent’s
counterparties, or the counterparties’ guarantors, had a weighted average
S&P equivalent credit rating of BBB+ at March 31, 2005, compared with our
previously reported rating of A- at December 31, 2004 and BBB+ at March 31,
2004. For more information on Sequent’s counterparties credit ratings, see the
discussion in “Results of Operation - Wholesale Services.” The following tables
show Sequent’s commodity receivable and payable positions as of the dates
indicated:
Gross
receivables |
|
|
|
|
|
In
millions |
|
March
31, 2005 |
|
Dec.
31, 2004 |
|
March
31, 2004 |
|
Receivables
with netting agreements in place: |
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade |
|
$ |
295 |
|
$ |
378 |
|
$ |
232 |
|
Counterparty
is non-investment grade |
|
|
28 |
|
|
36 |
|
|
8 |
|
Counterparty
has no external rating |
|
|
59 |
|
|
78 |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
without netting agreements in place: |
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade |
|
|
12 |
|
|
16 |
|
|
17 |
|
Counterparty
is non-investment grade |
|
|
2 |
|
|
6 |
|
|
- |
|
Counterparty
has no external rating |
|
|
- |
|
|
- |
|
|
- |
|
Amount
recorded on balance sheet |
|
$ |
396 |
|
$ |
514 |
|
$ |
268 |
|
Gross
payables |
|
|
|
|
|
In
millions |
|
March
31, 2005 |
|
Dec.
31, 2004 |
|
March
31, 2004 |
|
Payables
with netting agreements in place: |
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade |
|
$ |
215 |
|
$ |
291 |
|
$ |
189 |
|
Counterparty
is non-investment grade |
|
|
46 |
|
|
45 |
|
|
33 |
|
Counterparty
has no external rating |
|
|
141 |
|
|
139 |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
Payables
without netting agreements in place: |
|
|
|
|
|
|
|
|
|
|
Counterparty
is investment grade |
|
|
37 |
|
|
40 |
|
|
43 |
|
Counterparty
is non-investment grade |
|
|
- |
|
|
6 |
|
|
3 |
|
Counterparty
has no external rating |
|
|
- |
|
|
- |
|
|
- |
|
Amount
recorded on balance sheet |
|
$ |
439 |
|
$ |
521 |
|
$ |
318 |
|
Item
9.01. Financial
Statements and Exhibits.
Exhibit
No. |
Description |
|
|
99.1 |
AGL
Resources’ Press Release announcing financial results and other
information. |
SIGNATURE
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 27, 2005 |
/s/
Richard T. O’Brien |
|
Executive
Vice President and Chief Financial Officer |