|
|
 | | | |
- close
- close
- close
- close
Atmos Energy 10-Q 2007 Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
Commission File Number 1-10042
(972) 934-9227
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 o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Exchange Act. (Check one):
Large Accelerated
Filer þ Accelerated
Filer o Non-Accelerated
Filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act) Yes o No þ
Number of shares outstanding of each of the issuer’s
classes of common stock, as of July 31, 2007.
Table of Contents
TABLE OF CONTENTS
Table of Contents
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
See accompanying notes to condensed consolidated financial
statements
Table of Contents
ATMOS
ENERGY CORPORATION
See accompanying notes to condensed consolidated financial
statements
Table of Contents
ATMOS
ENERGY CORPORATION
See accompanying notes to condensed consolidated financial
statements
Table of Contents
ATMOS
ENERGY CORPORATION
See accompanying notes to condensed consolidated financial
statements
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) June 30, 2007
Atmos Energy Corporation (“Atmos” or “the
Company”) and our subsidiaries are engaged primarily in the
natural gas utility business as well as other natural gas
nonutility businesses. Our natural gas utility business
distributes natural gas through sales and transportation
arrangements to approximately 3.2 million residential,
commercial, public authority and industrial customers throughout
our six regulated natural gas utility divisions, in the service
areas described below:
In addition, we transport natural gas for others through our
distribution system. Our utility business is subject to federal
and state regulation
and/or
regulation by local authorities in each of the states in which
the utility divisions operate. Our corporate headquarters and
shared services function are located in Dallas, Texas, and our
customer support centers are located in Amarillo and Waco, Texas.
Our nonutility businesses operate in 22 states and include
our natural gas marketing operations, pipeline and storage
operations and other nonutility operations. These operations are
either organized under or managed by Atmos Energy Holdings, Inc.
(AEH), a wholly-owned subsidiary of the Company based in
Houston, Texas.
Our natural gas marketing operations are managed by Atmos Energy
Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides
a variety of natural gas management services to municipalities,
natural gas utility systems and industrial natural gas
customers, primarily in the southeastern and midwestern states
and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana
utility divisions. These services consist primarily of
furnishing natural gas supplies at fixed and market-based
prices, contract negotiation and administration, load
forecasting, gas storage acquisition and management services,
transportation services, peaking sales and balancing services,
capacity utilization strategies and gas price hedging through
the use of derivative instruments.
Our pipeline and storage business includes the regulated
operations of our Atmos Pipeline — Texas Division, a
division of the Company, and the nonregulated operations of
Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by
AEH. The Atmos Pipeline — Texas Division transports
natural gas to our Atmos Energy Mid-Tex Division and to third
parties, and manages five underground storage reservoirs in
Texas. Through APS, we own or have an interest in underground
storage fields in Kentucky and Louisiana. We also use these
storage facilities to reduce the need to contract for additional
pipeline capacity to meet customer demand during peak periods.
Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services, LLC (AES) and Atmos Power
Systems, Inc., which are each wholly-owned by AEH. Through
December 31, 2006, AES provided natural gas management
services to our utility operations, other than the Mid-Tex
Division. These
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
services included aggregating and purchasing gas supply,
arranging transportation and storage logistics and ultimately
delivering the gas to our utility service areas at competitive
prices. Effective January 1, 2007, our shared services
function began providing these services to our utility
operations. AES continues to provide limited services to our
utility division, and the revenues AES receives are equal to the
costs incurred to provide those services. Through Atmos Power
Systems, Inc., we have constructed electric peaking
power-generating plants and associated facilities and lease
these plants through lease agreements that are accounted for as
sales under generally accepted accounting principles.
In the opinion of management, all material adjustments
(consisting of normal recurring accruals) necessary for a fair
presentation have been made to the unaudited consolidated
interim-period financial statements. These consolidated
interim-period financial statements are condensed as permitted
by the instructions to
Form 10-Q
and should be read in conjunction with the audited consolidated
financial statements of Atmos Energy Corporation included in its
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2006. Because of
seasonal and other factors, the results of operations for the
three and nine-month periods ended June 30, 2007 are not
indicative of expected results of operations for the full 2007
fiscal year, which ends September 30, 2007.
Our accounting policies are described in Note 2 to our
Annual Report on
Form 10-K
for the year ended September 30, 2006. There were no
significant changes to those accounting policies during the nine
months ended June 30, 2007.
Additionally, during the second quarter of fiscal 2007, we
completed our annual goodwill impairment assessment. Based on
the assessment performed, our goodwill was not impaired.
We record certain costs as regulatory assets in accordance with
Statement of Financial Accounting Standards (SFAS) 71,
Accounting for the Effects of Certain Types of Regulation,
when future recovery through customer rates is considered
probable. Regulatory liabilities are recorded when it is
probable that revenues will be reduced for amounts that will be
credited to customers through the ratemaking process.
Substantially all of our regulatory assets are recorded as a
component of deferred charges and other assets and substantially
all of our regulatory liabilities are recorded as a component of
deferred credits and other liabilities. Deferred gas costs are
recorded either in other current assets or liabilities and the
regulatory cost of removal obligation is separately reported.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Significant regulatory assets and liabilities as of
June 30, 2007 and September 30, 2006 included the
following:
Currently, our authorized rates do not include a return on
certain of our merger and integration costs; however, we recover
the amortization of these costs. Merger and integration costs,
net, are generally amortized on a straight-line basis over
estimated useful lives ranging up to 20 years.
Environmental costs have been deferred to be included in future
rate filings in accordance with rulings received from various
state regulatory commissions.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents the components of comprehensive
income, net of related tax, for the three-month and nine-month
periods ended June 30, 2007 and 2006:
Accumulated other comprehensive loss, net of tax, as of
June 30, 2007 and September 30, 2006 consisted of the
following unrealized gains (losses):
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Recent
accounting pronouncements
In February 2007, the Financial Accounting Standards Board
(FASB) issued FASB Statement No. 159, The Fair Value
Option for Financial Assets and Financial
Liabilities — Including an amendment of FASB Statement
No. 115. This new standard permits an entity to measure
certain financial assets and financial liabilities at fair
value. The objective of the standard is to improve financial
reporting by allowing entities to mitigate volatility in
reported earnings caused by measuring related assets and
liabilities differently without having to apply complex hedge
accounting provisions. Entities that elect the fair value option
will report unrealized gains and losses in earnings at each
subsequent reporting date. The fair value option may be elected
on an
instrument-by-instrument
basis. The fair value option is irrevocable, unless a new
election date occurs. The provisions of this standard will be
effective October 1, 2008. We are currently evaluating the
impact this standard may have on our financial position, results
of operations and cash flows.
In September 2006, the FASB issued SFAS 158,
Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R). The new standard
represents a significant change to the existing rules by
requiring recognition in the balance sheet of the overfunded or
underfunded positions of defined benefit pension and other
postretirement plans based upon the projected benefit
obligation, along with a corresponding noncash, after-tax
adjustment to stockholders’ equity. Additionally, this
standard requires that the measurement date must correspond to
the fiscal year end balance sheet date but it does not change
how net periodic pension and postretirement cost or the
projected benefit obligation is determined. The balance sheet
recognition-related provisions of this standard will be
effective as of September 30, 2007, while the measurement
date provisions of this standard may be adopted as late as
fiscal 2009 for the Company.
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation
of FASB Statement No. 109 (FIN 48). FIN 48
clarifies the accounting for uncertainty in income taxes by
establishing standards for measurement and recognition in
financial statements of positions taken by an entity in its
income tax returns. This interpretation also provides guidance
on removing income tax assets and liabilities from the balance
sheet, classification of current and deferred income tax assets
and liabilities, accounting for interest and penalties,
accounting for income taxes in interim periods and income tax
disclosures. We will be required to apply the provisions of
FIN 48 beginning October 1, 2007. We are currently
evaluating the impact this standard may have on our financial
position, results of operations and cash flows.
We conduct risk management activities with independent third
parties through both our utility and natural gas marketing
segments. We record our derivatives as a component of risk
management assets and liabilities, which are classified as
current or noncurrent other assets or liabilities based upon the
anticipated settlement date of the underlying derivative. Our
determination of 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 and
losses on open contracts. In our determination of fair value, we
consider various factors, including closing exchange and
over-the-counter quotations, time value and volatility factors
underlying the contracts. These risk management assets and
liabilities are subject to continuing market risk until the
underlying derivative contracts are settled.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table shows the fair values of our risk management
assets and liabilities by segment at June 30, 2007 and
September 30, 2006:
We use a combination of storage, fixed physical contracts and
fixed financial contracts to partially insulate us and our
customers against gas price volatility during the winter heating
season. Because the gains or losses of financial derivatives
used in our utility segment ultimately will be recovered through
our rates, current period changes in the assets and liabilities
from these risk management activities are recorded as a
component of deferred gas costs in accordance with SFAS 71,
Accounting for the Effects of Certain Types of
Regulation. Accordingly, there is no earnings impact to our
utility segment as a result of the use of these financial
derivatives.
Our nonutility hedging activities are subject to various market
risks, including risks known as flat price risk, time spread
risk and basis risk.
Flat price risk arises from maintaining unhedged open positions.
Time spread risk arises when we enter into transactions to buy
and sell natural gas that over a period of months offset one
another but do not offset in any particular month within the
overall time period. This risk arises even when we have no
unhedged open positions for the overall time period. Finally,
basis risk arises when the pricing of a physical contract is
based on a pricing location that differs from the Henry Hub, the
NYMEX clearing location.
We seek to mitigate these risks by continually monitoring our
positions to maximize our gains. Additionally, under our risk
management policies, we seek to match our financial derivative
positions to our physical storage positions as well as our
expected current and future sales and purchase obligations to
maintain no open positions at the end of each trading day. The
determination of our net open position as of any day, however,
requires us to make assumptions as to future circumstances,
including the use of gas by our customers in relation to our
anticipated storage and market positions. Because the flat price
risk associated with any net open position at the end of each
day may increase if the assumptions are not realized, we review
these assumptions as part of our daily monitoring activities. We
may also be affected by intraday fluctuations of gas prices,
since the price of natural gas purchased or sold for future
delivery earlier in the day may not be
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on June 30, 2007, AEH
had a net open position (including existing storage) of
0.1 Bcf.
Finally, AEM manages its exposure to the risk of natural gas
price changes through a combination of storage and financial
derivatives, including futures, over-the-counter and
exchange-traded options and swap contracts with counterparties.
Our financial derivative activities include fair value hedges to
offset changes in the fair value of our natural gas inventory
and cash flow hedges to offset anticipated purchases and sales
of gas in the future. AEM also utilizes basis swaps and other
non-hedge derivative instruments to manage its exposure to
market volatility.
For the three and nine-month periods ended June 30, 2007,
the change in the deferred hedging position in accumulated other
comprehensive loss was attributable to decreases in future
natural gas prices relative to the natural gas prices stipulated
in the derivative contracts. The recognition in net income for
the nine months ended June 30, 2007 of $27.4 million
in net deferred hedging losses (of which $0.2 million was
recognized during the three months ended June 30,
2007) was the result of the maturing of derivative
contracts. The net deferred hedging loss associated with open
cash flow hedges remains subject to market price fluctuations
until the positions are either settled under the terms of the
hedge contracts or terminated prior to settlement. The majority
of the deferred hedging balance as of June 30, 2007 is
expected to be recognized in net income by the end of fiscal
2007 along with the corresponding hedged purchases and sales of
natural gas.
Gains and losses recognized in the income statement from hedge
ineffectiveness primarily result from basis risk and from
differences between the timing of the settlement of physical
contracts and the settlement of the related hedge, that is
referred to below as timing ineffectiveness. The following
summarizes the gains and losses recognized in the income
statement for the three and nine months ended June 30, 2007.
In March 2007, we entered into a Treasury lock agreement to fix
the Treasury yield component of the interest cost associated
with $100 million of our $250 million
6.35% Senior Notes issued in June 2007 (the Senior Notes
Offering).
We designated this Treasury lock as a cash flow hedge of an
anticipated transaction. This Treasury lock was settled in June
2007 upon completion of the Senior Notes Offering with the
receipt of $4.8 million from the counterparties due to an
increase in the 10 year Treasury rates between inception of
the Treasury lock and settlement. Because the Treasury lock was
effective, the net $2.9 million unrealized gain was
recorded as a component of accumulated other comprehensive
income and will be recognized over the ten year life of the
senior notes.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Long-term debt at June 30, 2007 and September 30, 2006
consisted of the following:
Our unsecured floating rate senior notes bear interest at a rate
equal to the three-month LIBOR rate plus 0.375 percent per
year. At June 30, 2007, the interest rate on our floating
rate debt was 5.731 percent.
At June 30, 2007, there were no borrowings outstanding
under our commercial paper program or bank credit facilities. At
September 30, 2006, there was $379.3 million
outstanding under our commercial paper program and
$3.1 million outstanding under our bank credit facilities.
On December 4, 2006, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$401.5 million of capacity carried over from our prior
shelf registration statement filed with the SEC in August 2004.
As discussed in Note 5, in December 2006, we sold
approximately 6.3 million shares of common stock under the
new registration statement.
On June 14, 2007, we closed our Senior Notes Offering. The
effective interest rate on these notes is 6.26 percent
after giving effect to the $100 million Treasury lock
discussed in Note 3. The net proceeds of
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
approximately $247 million, together with $53 million
of available cash, were used to repay our $300 million
unsecured floating rate senior notes, which were called in May
for redemption on July 15, 2007. Under the terms of the
indenture under which the unsecured floating rate senior notes
were issued, if we elected to redeem the notes prior to their
maturity, we were required to do so only on any January 15,
April 15, July 15 or October 15.
As of June 30, 2007, we had approximately $450 million
of availability remaining under the registration statement.
However, due to certain restrictions placed by one state
regulatory commission on our ability to issue securities under
the registration statement, we now have remaining and available
for issuance a total of approximately $100 million of
equity securities, $50 million of senior debt securities
and $300 million of subordinated debt securities. In
addition, due to restrictions imposed by another state
regulatory commission, if the credit ratings on our senior
unsecured debt were to fall below investment grade from either
Standard & Poor’s Corporation (BBB-),
Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings,
Ltd. (BBB-), our ability to issue any type of debt securities
under the registration statement would be suspended until an
investment grade rating from any of the three credit rating
agencies was achieved.
We maintain both committed and uncommitted credit facilities.
Borrowings under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas and the
increased gas supplies required to meet customers’ needs
during periods of cold weather.
As of June 30, 2007, we had three short-term committed
revolving credit facilities totaling $918 million. The
first facility is a five-year unsecured facility for
$600 million that we entered into in December 2006, which
replaced our previously existing $600 million three-year
revolving credit facility. The new facility, expiring December
2011, bears interest at a base rate or at the LIBOR rate plus
from 0.30 percent to 0.75 percent, based on the
Company’s credit ratings, and serves as a backup liquidity
facility for our $600 million commercial paper program. At
June 30, 2007, there were no borrowings outstanding under
our commercial paper program.
The second facility is a $300 million unsecured
364-day
facility expiring November 2007, that bears interest at a base
rate or at the LIBOR rate plus from 0.30 percent to
0.75 percent, based on the Company’s credit ratings.
At June 30, 2007, there were no borrowings under this
facility.
The third facility is an $18 million unsecured facility
that bears interest at the Federal Funds rate plus
0.5 percent. This facility expired on March 31, 2007
and was renewed effective April 1, 2007 for one year with
no material changes to the terms and pricing. At June 30,
2007, there were no borrowings under this facility.
The availability of funds under our credit facilities is subject
to conditions specified in the respective credit agreements, all
of which we currently satisfy. These conditions include our
compliance with financial covenants and the continued accuracy
of representations and warranties contained in these agreements.
We are required by the financial covenants in both our
$600 million and $300 million credit facilities to
maintain, at the end of each fiscal quarter, a ratio of total
debt to total capitalization of no greater than 70 percent.
At June 30, 2007, our total-debt-to-total-capitalization
ratio, as defined, was 58 percent. In addition, the fees
that we pay on unused amounts under both the $600 million
and $300 million credit facilities are subject to
adjustment depending upon our credit ratings.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
AEM has a $580 million uncommitted demand working capital
credit facility. On March 30, 2007, AEM and the banks in
the facility amended the facility, primarily to extend it to
March 31, 2008. Borrowings under the credit facility can be
made either as revolving loans or offshore rate loans. Revolving
loan borrowings will bear interest at a floating rate equal to a
base rate defined as the higher of (i) 0.50 percent
per annum above the Federal Funds rate or (ii) the
lender’s prime rate plus 0.25 percent. Offshore rate
loan borrowings will bear interest at a floating rate equal to a
base rate based upon LIBOR plus an applicable margin, ranging
from 1.25 percent to 1.625 percent per annum,
depending on the excess tangible net worth of AEM, as defined in
the credit facility. Borrowings drawn down under letters of
credit issued by the banks will bear interest at a floating rate
equal to the base rate, as defined above, plus an applicable
margin, which will range from 1.00 percent to
1.875 percent per annum, depending on the excess tangible
net worth of AEM and whether the letters of credit are
swap-related standby letters of credit.
AEM is required by the financial covenants in the credit
facility not to exceed a maximum ratio of total liabilities to
tangible net worth of 5 to 1, along with minimum levels of net
working capital ranging from $20 million to
$120 million. Additionally, AEM must maintain a minimum
tangible net worth ranging from $21 million to
$121 million, and must not have a maximum cumulative loss
for the most recent 12 month reporting period exceeding
$4 million to $23 million, depending on the total
amount of borrowing elected from time to time by AEM. At
June 30, 2007, AEM’s ratio of total liabilities to
tangible net worth, as defined, was 1.70 to 1.
At June 30, 2007, there were no borrowings outstanding
under this credit facility. However, at June 30, 2007, AEM
letters of credit totaling $131.7 million had been issued
under the facility, which reduced the amount available by a
corresponding amount. The amount available under this credit
facility is also limited by various covenants, including
covenants based on working capital. Under the most restrictive
covenant, the amount available to AEM under this credit facility
was $18.3 million at June 30, 2007. This line of
credit is collateralized by substantially all of the assets of
AEM and is guaranteed by AEH.
The Company also has an unsecured short-term uncommitted credit
line of $25 million that is used for working-capital and
letter-of-credit purposes. There were no borrowings under this
uncommitted credit facility at June 30, 2007, but letters
of credit reduced the amount available by $5.4 million.
This uncommitted line is renewed or renegotiated at least
annually with varying terms, and we pay no fee for the
availability of the line. Borrowings under this line are made on
a
when-and-as-available
basis at the discretion of the bank.
AEH, the parent company of AEM, has an intercompany uncommitted
demand credit facility with the Company which bears interest at
the rate of AEM’s $580 million uncommitted demand
working capital credit facility plus 0.25 percent.
Effective May 1, 2007, the intercompany credit facility was
increased from $100 million to $200 million. State
regulators have approved this facility through December 31,
2007. At June 30, 2007, there were no borrowings under this
facility.
In June 2007, the Company entered into a $200 million
intercompany uncommitted revolving credit facility and
promissory note with AEH. The new facility, expiring December
2007, bears interest at the lesser of (i) LIBOR plus
0.20 percent or (ii) the marginal borrowing rate
available to the Company on any such date under its commercial
paper program. At June 30, 2007, there were no borrowings
under this facility.
In addition, to supplement its $580 million credit
facility, AEM has an intercompany uncommitted demand credit
facility with AEH, which bears interest at LIBOR plus
2.75 percent. Effective May 1, 2007, this intercompany
credit facility was increased from $120 million to
$175 million. Any outstanding amounts under this facility
are subordinated to AEM’s $580 million uncommitted
demand credit facility. At June 30, 2007, there were no
borrowings under this facility.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
We have other debt covenants in addition to those described
above. Our Series P First Mortgage Bonds contain provisions
that allow us to prepay the outstanding balance in whole at any
time, after November 2007, subject to a prepayment premium. The
First Mortgage Bonds provide for certain cash flow requirements
and restrictions on additional indebtedness, sale of assets and
payment of dividends. Under the most restrictive of such
covenants, cumulative cash dividends paid after
December 31, 1985 may not exceed the sum of
accumulated net income for periods after that date plus
$9 million. At June 30, 2007, approximately
$294.6 million of retained earnings was unrestricted with
respect to the payment of dividends.
We were in compliance with all of our debt covenants as of
June 30, 2007. If we were unable to comply with our debt
covenants, we could be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions. Our public debt indentures relating to our
senior notes and debentures, as well as our $600 million
and $300 million revolving credit agreements, each contain
a default provision that is triggered if outstanding
indebtedness arising out of any other credit agreements in
amounts ranging from in excess of $15 million to in excess
of $100 million becomes due by acceleration or is not paid
at maturity. In addition, AEM’s credit agreement contains a
cross-default provision whereby AEM would be in default if it
defaults on other indebtedness, as defined, by at least $250
thousand in the aggregate. Additionally, this agreement contains
a provision that would limit the amount of credit available if
Atmos were downgraded below an S&P rating of BBB and a
Moody’s rating of Baa2.
Except as described above, we have no triggering events in our
debt instruments that are tied to changes in specified credit
ratings or stock price, nor have we entered into any
transactions that would require us to issue equity, based on our
credit rating or other triggering events.
On December 13, 2006, we completed the public offering of
6,325,000 shares of our common stock including the
underwriters’ exercise of their overallotment option of
825,000 shares. The offering was priced at $31.50 per share
and generated net proceeds of approximately $192 million.
We used the net proceeds from this offering to reduce short-term
debt.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Basic and diluted earnings per share for the three and nine
months ended June 30, 2007 and 2006 are calculated as
follows:
There were approximately 466,000 and 396,000 restricted and
other shares and approximately 165,000 and 102,000 stock options
that were excluded from the calculation of diluted earnings per
share for the three months ended June 30, 2007 and 2006 as
their inclusion in the computation would be anti-dilutive.
There were no out-of-the-money options excluded from the
computation of diluted earnings per share for the three and nine
months ended June 30, 2007 and 2006 as their exercise price
was less than the average market price of the common stock
during that period.
The components of our net periodic pension cost for our pension
and other postretirement benefit plans for the three and nine
months ended June 30, 2007 and 2006 are presented in the
following tables. The costs relating to our utility operations
are recoverable through our gas utility rates; however, a
portion of these costs is capitalized into our utility rate
base. The remaining costs are recorded as a component of
operation and maintenance expense.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The assumptions used to develop our net periodic pension cost
for the three and nine months ended June 30, 2007 and 2006
are as follows:
The discount rate used to compute the present value of a
plan’s liabilities generally is based on rates of
high-grade corporate bonds with maturities similar to the
average period over which the benefits will be paid. Generally,
our funding policy is to contribute annually an amount in
accordance with the requirements of the Employee Retirement
Income Security Act of 1974. However, additional voluntary
contributions are made to satisfy regulatory requirements in
certain of our jurisdictions. During the nine months ended
June 30, 2007, we contributed $8.5 million to our
other postretirement plans, and we expect to contribute a total
of approximately $12 million to these plans during fiscal
2007.
With respect to the specific litigation and
environmental-related matters or claims that were disclosed in
Note 13 to our annual report on
Form 10-K
for the year ended September 30, 2006, there were no
material changes in the status of such litigation and
environmental-related matters or claims during the nine months
ended June 30, 2007. We continue to believe that the final
outcome of such litigation and environmental-related matters or
claims will not have a material adverse effect on our financial
condition, results of operations or cash flows.
In addition, we are involved in other litigation and
environmental-related matters or claims that arise in the
ordinary course of our business. While the ultimate results of
such litigation and response actions to such
environmental-related matters or claims cannot be predicted with
certainty, we believe the final outcome of such litigation and
response actions will not have a material adverse effect on our
financial condition, results of operations or cash flows.
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At June 30, 2007, AEM was committed to
purchase 87.0 Bcf
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
within one year and 48.2 Bcf within one to three years
under indexed contracts. AEM is committed to purchase
1.9 Bcf within one year and less than 0.1 Bcf within
one to three years under fixed price contracts with prices
ranging from $6.00 to $9.85. Purchases under these contracts
totaled $567.9 million and $398.9 million for the
three months ended June 30, 2007 and 2006 and
$1,551.3 million and $1,718.4 million for the nine
months ended June 30, 2007 and 2006.
Our utility operations, other than the Mid-Tex Division,
maintain supply contracts with several vendors that generally
cover a period of up to one year. Commitments for estimated base
gas volumes are established under these contracts on a monthly
basis at contractually negotiated prices. Commitments for
incremental daily purchases are made as necessary during the
month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
prices. The estimated fiscal year commitments under these
contracts as of June 30, 2007 are as follows (in thousands):
At June 30, 2007, we were involved in a number of
“show cause” proceedings filed by cities in several of
our jurisdictions. We are currently providing information to and
addressing questions raised by the respective regulatory
commissions. We believe we will be able to demonstrate to these
regulators that our rates are just and reasonable. Additionally,
we have a rate case in progress in our Tennessee service area.
These regulatory proceedings are discussed in further detail in
Management’s Discussion and Analysis — Recent
Ratemaking Developments.
Information regarding our concentration of credit risk is
disclosed in Note 15 to our annual report on
Form 10-K
for the year ended September 30, 2006. During the nine
months ended June 30, 2007, there were no material changes
in our concentration of credit risk.
Atmos Energy Corporation and our subsidiaries are engaged
primarily in the natural gas utility business as well as certain
nonutility businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 million residential, commercial, public authority and
industrial customers throughout our six regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses we provide natural gas
management and marketing services to industrial customers,
municipalities and other local distribution companies located in
22 states. Additionally, we provide natural gas
transportation and storage services to certain of our utility
operations and to third parties.
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Our operations are divided into four segments:
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in differing regulatory environments.
Although our utility segment operations are geographically
dispersed, they are reported as a single segment as each utility
division has similar economic characteristics. The accounting
policies of the segments are the same as those described in the
summary of significant accounting policies found in our annual
report on
Form 10-K
for the fiscal year ended September 30, 2006. We evaluate
performance based on net income or loss of the respective
operating units.
Income statements for the three and nine-month periods ended
June 30, 2007 and 2006 by segment are presented in the
following tables:
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
21
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
22
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
23
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Balance sheet information at June 30, 2007 and
September 30, 2006 by segment is presented in the following
tables:
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Table of Contents
The Board of Directors
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of June 30, 2007, and the
related condensed consolidated statements of income for the
three-month and nine-month periods ended June 30, 2007 and
2006, and the condensed consolidated statements of cash flows
for the nine-month periods ended June 30, 2007 and 2006.
These financial statements are the responsibility of the
Company’s management.
We conducted our review in accordance with the standards of the
Public Company Accounting Oversight Board (United States). A
review of interim financial information consists principally of
applying analytical procedures and making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting
Oversight Board, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the condensed consolidated
financial statements referred to above for them to be in
conformity with U.S. generally accepted accounting
principles.
We have previously audited, in accordance with the standards of
the Public Company Accounting Oversight Board (United States),
the consolidated balance sheet of Atmos Energy Corporation as of
September 30, 2006, and the related consolidated statements
of income, shareholders’ equity, and cash flows for the
year then ended, not presented herein, and in our report dated
November 20, 2006, we expressed an unqualified opinion on
those consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated
balance sheet as of September 30, 2006, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Ernst &
Young LLP
Dallas, Texas
August 8, 2007
Table of Contents
The following discussion should be read in conjunction with the
condensed consolidated financial statements in this Quarterly
Report on
Form 10-Q
and Management’s Discussion and Analysis in our Annual
Report on
Form 10-K
for the year ended September 30, 2006.
The statements contained in this Quarterly Report on
Form 10-Q
may contain “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical fact included in
this Report are forward-looking statements made in good faith by
us and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation
Reform Act of 1995. When used in this Report, or any other of
our documents or oral presentations, the words
“anticipate”, “believe”,
“estimate”, “expect”, “forecast”,
“goal”, “intend”, “objective”,
“plan”, “projection”, “seek”,
“strategy” or similar words are intended to identify
forward-looking statements. Such forward-looking statements are
subject to risks and uncertainties that could cause actual
results to differ materially from those expressed or implied in
the statements relating to our strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties include the
following: regulatory trends and decisions, including
deregulation initiatives and the impact of rate proceedings
before various state regulatory commissions; adverse weather
conditions, such as warmer than normal weather in our utility
service territories or colder than normal weather that could
adversely affect our natural gas marketing activities; the
concentration of our distribution, pipeline and storage
operations in one state; impact of environmental regulations on
our business; market risks beyond our control affecting our risk
management activities including market liquidity, commodity
price volatility, increasing interest rates and counterparty
creditworthiness; our ability to continue to access the capital
markets; the effects of inflation and changes in the
availability and prices of natural gas, including the volatility
of natural gas prices; increased competition from energy
suppliers and alternative forms of energy; increased costs of
providing pension and postretirement health care benefits; the
capital-intensive nature of our distribution business; the
inherent hazards and risks involved in operating our
distribution business; effects of natural disasters or terrorist
activities and other risks and uncertainties, which may be
discussed herein, all of which are difficult to predict and many
of which are beyond our control. A more detailed discussion of
these risks and uncertainties may be found in our Annual Report
on
Form 10-K
for the year ended September 30, 2006. Accordingly, while
we believe these forward-looking statements to be reasonable,
there can be no assurance that they will approximate actual
experience or that the expectations derived from them will be
realized. Further, we undertake no obligation to update or
revise any of our forward-looking statements whether as a result
of new information, future events or otherwise.
Atmos Energy Corporation and our subsidiaries are engaged
primarily in the natural gas utility business as well as certain
nonutility businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 million residential, commercial, public authority and
industrial customers throughout our six regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses, we primarily provide natural
gas management and marketing services to municipalities, other
local gas distribution companies and industrial customers in
22 states and natural gas transportation and storage
services to certain of our utility operations and to third
parties.
Our operations are divided into four segments:
Table of Contents
Our condensed consolidated financial statements were prepared in
accordance with accounting principles generally accepted in the
United States. Preparation of these 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 based our estimates on historical experience and
various other assumptions that we believe to be reasonable under
the circumstances. On an ongoing basis, we evaluate our
estimates, including those related to risk management and
trading activities, allowance for doubtful accounts, legal and
environmental accruals, insurance accruals, pension and
postretirement obligations, deferred income taxes and the
valuation of goodwill, indefinite-lived intangible assets and
other long-lived assets. Actual results may differ from such
estimates.
Our critical accounting policies used in the preparation of our
consolidated financial statements are described in our Annual
Report on
Form 10-K
for the year ended September 30, 2006 and include the
following:
Our critical accounting policies are reviewed by the Audit
Committee on a quarterly basis. There have been no significant
changes to these critical accounting policies during the nine
months ended June 30, 2007.
RESULTS
OF OPERATIONS
Consolidated financial highlights for the three-month and
nine-month periods ended June 30, 2007 and 2006 are
presented below:
Table of Contents
For the nine months ended June 30, 2007, we earned
$174.4 million, or $2.00 per diluted share, compared with
net income of $141.7 million, or $1.75 per diluted share
during the nine months ended June 30, 2006. The
23 percent period-over-period increase in net income was
primarily attributable to strong financial results in our
natural gas marketing and pipeline and storage segments coupled
with improved results in our utility segment. Our utility
operations contributed $92.5 million ($1.06 per diluted
share) or 53 percent to our results for the nine months
ended June 30, 2007. Our nonutility operations, comprised
of our natural gas marketing, pipeline and storage and other
nonutility segments, contributed $81.9 million ($0.94 per
diluted share), or 47 percent to our results for the nine
months ended June 30, 2007.
Key financial and other events for the nine months ended
June 30, 2007 include the following:
Table of Contents
Three
Months Ended June 30, 2007 compared with Three Months Ended
June 30, 2006
Our utility segment has historically contributed 65 to
85 percent of our consolidated net income. However, in
recent years, this contribution has declined as our nonutility
businesses have grown and our utility operations have
experienced the adverse effects of warmer-than-normal weather
and declining average gas usage per customer.
Natural gas sales to residential, commercial and public
authority customers are affected by winter heating season
requirements, whereas natural gas sales to industrial customers
are much less weather sensitive. As residential, commercial and
public authority customers comprise approximately
90 percent of our gas sales volumes, the results of
operations for our utility segment are seasonal. We typically
experience higher operating revenues and net income during the
period from October through March of each year and lower
operating revenues and either lower net income or net losses
during the period from April through September of each year.
Accordingly, our second fiscal quarter has historically been our
most critical earnings quarter with an average of approximately
64 percent of our consolidated net income having been
earned in the second quarter during the three most recently
completed fiscal years. Additionally, we typically experience
higher levels of accounts receivable, accounts payable, gas
stored underground and short-term debt balances during the
winter heating season due to the seasonal nature of our revenues
and the need to purchase and store gas to support these
operations.
The primary factors that currently impact the results of our
utility operations are regulatory decisions and trends, the
increased use of energy-efficient appliances by our customers,
competitive factors in the energy industry and economic
conditions in our service areas.
Seasonal weather patterns can also affect our utility
operations. However, the effect of weather that is above or
below normal is substantially offset through weather
normalization adjustments, known as WNA, which, beginning with
the
2006-2007
winter heating season, has been approved by regulators for
approximately 90 percent of our residential and commercial
meters in the following states for the following time periods:
WNA allows us to increase customers’ bills to offset lower
gas usage when weather is warmer than normal and decrease
customers’ bills to offset higher gas usage when weather is
colder than normal. Although our WNA periods do not cover the
entire heating season in all jurisdictions, we believe these
mechanisms substantially insulate our utility gross profit
margin from the effects of weather.
Our utility operations are also affected by the cost of natural
gas. The cost of gas is passed through to our customers without
markup. Therefore, increases in the cost of gas are offset by a
corresponding increase in revenues. Accordingly, we believe
gross profit is a better indicator of our financial performance
than revenues. However, gross profit in our Texas and
Mississippi service areas include franchise fees and gross
receipts
Table of Contents
taxes, which are calculated as a percentage of revenue
(inclusive of gas costs). Therefore, the amount of these taxes
included in revenues is influenced by the cost of gas and the
level of gas sales volumes. We record the tax expense as a
component of taxes, other than income. Although changes in
revenue-related taxes arising from changes in gas cost affect
gross profit, over time the impact is offset within operating
income. Timing differences exist between the recognition of
revenue for franchise fees collected from our customers and the
recognition of expense of franchise taxes. The effect of these
timing differences can be significant in periods of volatile gas
prices, particularly in our Mid-Tex Division. These timing
differences may favorably or unfavorably affect net income;
however, these amounts should offset over time with no permanent
impact on net income.
Higher gas costs affect our utility operations in other ways as
well. Higher gas costs may cause customers to conserve, or, in
the case of industrial customers, to use alternative energy
sources. Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt expense and
may require us to increase borrowings under our credit
facilities, resulting in higher interest expense.
Review
of Financial and Operating Results
Financial and operational highlights for our utility segment for
the three months ended June 30, 2007 and 2006 are presented
below:
Table of Contents
The following table shows our operating income by utility
division for the three months ended June 30, 2007 and 2006.
The presentation of our utility operating income by division is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
The $20.8 million improvement in utility gross profit
primarily reflects a 20 percent increase in throughput,
which increased gross profit by $18.9 million and
$7.3 million of rate increases received from our Rate
Stabilization Clause (RSC) filings in our Louisiana service
areas, GRIP-related recoveries in our Texas service areas and
rate design changes in our Missouri service areas. These
increases in the current-year period were partially offset by
the recognition in the prior-year’s gross profit margin of
$6.2 million in previously deferred gross profit from the
2003 RSC filing in our Louisiana Division.
Gross profit also increased approximately $6.9 million in
revenue-related taxes primarily due to increased throughput and
higher revenues, on which the tax is calculated, due to an
increase in the cost of gas in the current-year quarter compared
with the prior-year quarter. This increase, partially offset by
a $3.5 million quarter-over-quarter increase in the
associated franchise and state gross receipts tax expense
recorded as a component of taxes, other than income resulted in
a $3.4 million increase in operating income when compared
with the prior-year quarter.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, increased to
$190.6 million for the three months ended June 30,
2007 from $172.8 million for the three months ended
June 30, 2006.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $10.7 million primarily due to
higher employee and administrative costs and a one-time
$3.3 million noncash charge to write off software that will
no longer be used. These increases were partially offset by a
$2.0 million reversal of an accrual in the prior-year
quarter for Hurricane Katrina losses after the outlook to
recover the losses sustained from the storm had improved.
The provision for doubtful accounts increased $0.9 million
to $3.0 million for the three months ended June 30,
2007. The increase primarily was attributable to increased
revenues. In the utility segment, the average cost of natural
gas for the three months ended June 30, 2007 was $7.90 per
thousand cubic feet (Mcf), compared with $7.11 per Mcf for the
three months ended June 30, 2006.
Interest charges associated with the utility segment for the
three months ended June 30, 2007 decreased to
$29.0 million from $30.9 million for the three months
ended June 30, 2006. The decrease was primarily
attributable to reduced interest expense attributable to lower
average outstanding short-term debt balances in the current-year
quarter compared with the prior-year quarter, partially offset
by a 28 basis point increase in
Table of Contents
the interest rate on our $300 million unsecured floating
rate senior notes due July 2007 due to an increase in the
three-month LIBOR rate.
Our natural gas marketing segment aggregates and purchases gas
supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request, including
furnishing natural gas supplies at fixed and market-based
prices, contract negotiation and administration, load
forecasting, gas storage acquisition and management services,
transportation services, peaking sales and balancing services,
capacity utilization strategies and gas price hedging through
the use of derivative products. As a result, our revenues arise
from the types of commercial transactions we have structured
with our customers and include the value we extract by
optimizing the storage and transportation capacity we own or
control as well as revenues for services we perform.
To optimize the storage and transportation capacity we own or
control, we participate in transactions in which we combine the
natural gas commodity and transportation costs to minimize our
costs incurred to serve our customers by identifying the lowest
cost alternative within the natural gas supplies, transportation
and markets to which we have access. Additionally, we engage in
natural gas storage transactions in which we seek to find and
profit from the pricing differences that occur over time. We
purchase physical natural gas and then sell financial contracts
at advantageous prices to lock in a gross profit margin. Through
the use of transportation and storage services and derivative
contracts, we are able to capture gross profit margin through
the arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
The natural gas inventory used in our natural gas marketing
storage activities is marked to market at the end of each month
based upon the Gas Daily index with changes in fair value
recognized as unrealized gains and losses in the period of
change. We use derivatives, designated as fair value hedges, to
hedge this natural gas inventory. These derivatives are marked
to market each month based upon the NYMEX price with changes in
fair value recognized as unrealized gains and losses in the
period of change. The changes between the spreads between the
forward natural gas prices used to value the financial hedges
designated against our physical inventory and the market (spot)
prices used to value our physical storage result in the
unrealized margins reported as a part of our storage activities
until the underlying physical gas is cycled and the related
financial derivatives are settled.
AEM also uses derivative instruments to capture additional
storage arbitrage opportunities that arise subsequent to the
execution of the original physical inventory hedge and to
insulate and protect the economic value within its storage and
marketing activities. Changes in fair value associated with
these financial instruments are recognized as unrealized gains
and losses within AEM’s storage and marketing activities
until they are settled.
Table of Contents
Review
of Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the three months ended June 30, 2007
and 2006 are presented below. Gross profit for our natural gas
marketing segment consists primarily of storage activities and
marketing activities. Storage activities represent the
optimization of our managed proprietary and third-party storage
and transportation assets. Marketing activities represent the
utilization of proprietary and customer-owned transportation and
storage assets to provide various services our customers request.
The $0.3 million increase in our natural gas marketing
segment’s gross profit reflects a $44.1 million
increase in unrealized margins during the current-year quarter
compared with the prior-year quarter offset by a
$43.8 million decrease in realized storage and marketing
margins.
Realized gross profit from our storage activities decreased
$41.1 million compared with the prior-year quarter. The
decrease reflects an increase in storage fees, park and loan
fees and the impact of a less volatile market, which reduced the
arbitrage spreads earned from these activities. Additionally,
AEM recognized financial hedge settlement losses associated with
the deferral of storage withdrawals.
These decreases were partially offset by a $38.9 million
increase in unrealized gains primarily attributable to a
narrowing of the spreads between the physical and forward
natural gas prices. This mark-to-market impact was magnified by
a 2.5 Bcf increase in our net physical position at
June 30, 2007 compared to the prior-year quarter.
Differences between the forward and spot prices may continue to
cause material volatility in our unrealized margin. However, the
economic gross profit we have captured in the original
transactions should remain essentially unchanged.
Realized gross profit from our marketing activities decreased
$2.7 million compared with the prior-year quarter. This
decrease reflects the impact of a less volatile market, which
reduced opportunities to take advantage of pricing differences
between hubs, partially offset by increased sales volumes
attributable to
Table of Contents
successful execution of our marketing strategies. This decrease
was more than offset by a $5.2 million increase in
unrealized margins primarily attributable to a favorable
movement in the forward natural gas prices associated with the
financial derivatives used in these activities during the three
months ended June 30, 2007.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $7.5 million for the three months ended
June 30, 2007 from $6.5 million for the three months
ended June 30, 2006. The increase in operating expense
primarily was attributable to an increase in employee and other
administrative costs.
Interest charges for the three months ended June 30, 2007
increased to $2.0 million from $1.7 million for the
three months ended June 30, 2006. The increase was
attributable to higher intercompany borrowings during the
current-year quarter.
Our pipeline and storage segment consists of the regulated
pipeline and storage operations of the Atmos
Pipeline — Texas Division and the nonregulated
pipeline and storage operations of Atmos Pipeline and Storage,
LLC (APS). The Atmos Pipeline — Texas Division
transports natural gas to our Mid-Tex Division and for third
parties and manages five underground storage reservoirs in
Texas. We also provide ancillary services customary in the
pipeline industry including parking arrangements, lending and
sales of inventory on hand. These operations represent one of
the largest intrastate pipeline operations in Texas with a heavy
concentration in the established natural gas-producing areas of
central, northern and eastern Texas, extending into or near the
major producing areas of the Texas Gulf Coast and the Delaware
and Val Verde Basins of West Texas. This pipeline system
provides access to nine basins located in Texas, which are
estimated to contain a substantial portion of the nation’s
remaining onshore natural gas reserves. APS owns or has an
interest in underground storage fields in Kentucky and
Louisiana. We also use these storage facilities to reduce the
need to contract for additional pipeline capacity to meet
customer demand during peak periods.
Similar to our utility segment, our pipeline and storage segment
is impacted by seasonal weather patterns, competitive factors in
the energy industry and economic conditions in our service
areas. Natural gas transportation requirements are affected by
the winter heating season requirements of our customers. This
generally results in higher operating revenues and net income
during the period from October through March of each year and
lower operating revenues and either lower net income or net
losses during the period from April through September of each
year. Further, as the Atmos Pipeline — Texas Division
operations provide all of the natural gas for our Mid-Tex
Division, the results of this segment are highly dependent upon
the natural gas requirements of this division. As a regulated
pipeline, the operations of the Atmos Pipeline — Texas
Division may be impacted by the timing of when costs and
expenses are incurred and when these costs and expenses are
recovered through its tariffs.
Review
of Financial and Operating Results
Financial and operational highlights for our pipeline and
storage segment for the three months ended June 30, 2007
and 2006 are presented below. Gross profit for our pipeline and
storage segment primarily consists of transportation margins
earned from our Mid-Tex Division and from third parties, other
ancillary pipeline services and asset management fees earned by
APS. Additionally, this segment’s margins include an
unrealized component as APS hedges its risk associated with its
asset management contracts. Our pipeline and storage
segment’s gross profit was comprised of the following
components for the three months ended June 30, 2007 and
2006:
Table of Contents
The $2.2 million increase in gross profit is primarily
attributable to a 19 percent increase in throughput,
including $2.8 million of margin from our North Side Loop
and other compression projects, coupled with a $0.7 million
increase due to rate adjustments resulting from Atmos
Pipeline — Texas Division’s 2005 GRIP filing.
These increases were partially offset by a $1.1 million
decrease in reservation, demand and deficiency fees which are
market driven and reduced asset management margins in APS.
Operating expenses increased to $22.2 million for the three
months ended June 30, 2007 from $20.6 million for the
three months ended June 30, 2006 due to higher
administrative and other operating costs primarily associated
with the North Side Loop and other compression projects that
were completed in fiscal 2006.
Interest charges associated with the pipeline and storage
segment for the three months ended June 30, 2007 increased
to $7.1 million from $6.4 million for the three months
ended June 30, 2006. The increase was attributable to the
use of updated allocation factors for fiscal 2007. These factors
are reviewed and updated on an annual basis.
Miscellaneous income increased to $3.9 million for the
three months ended June 30, 2007 from $0.3 million for
the three months ended June 30, 2006. The increase was
primarily attributable to $2.1 million received from
leasing certain mineral interests coupled with an increase in
interest income recorded in the pipeline and storage segment.
Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services, LLC (AES), and Atmos Power
Systems, Inc. Through December 31, 2006, AES provided
natural gas management services to our utility operations, other
than the Mid-Tex Division. These services included aggregating
and purchasing gas supply, arranging transportation and storage
logistics and ultimately delivering the gas to our utility
service areas at competitive prices. Effective January 1,
2007, our shared services function began providing these
services to our utility operations. AES continues to provide
limited services to our utility
36
Table of Contents
divisions, and the revenues AES receives are equal to the costs
incurred to provide those services. Through Atmos Power Systems,
Inc., we have constructed electric peaking power-generating
plants and associated facilities and lease these plants through
agreements that are accounted for as sales under generally
accepted accounting principles.
Operating income for this segment primarily reflects the leasing
income associated with two sales-type lease transactions
completed in 2001 and 2002 and did not materially change for the
three months ended June 30, 2007 compared with the
prior-year quarter.
Nine
Months Ended June 30, 2007 compared with Nine Months Ended
June 31, 2006
Financial and operational highlights for our utility segment for
the nine months ended June 30, 2007 and 2006 are presented
below:
Table of Contents
The following table shows our operating income by utility
division for the nine months ended June 30, 2007 and 2006.
The presentation of our utility operating income by division is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
The $33.7 million increase in utility gross profit
primarily reflects an eleven percent increase in throughput,
which increased gross profit by $33.4 million, a
$10.8 million increase associated with the implementation
of WNA in our Mid-Tex and Louisiana Divisions beginning with the
2006-2007
winter heating season coupled with $25.6 million of rate
increases received from our Rate Stabilization Clause (RSC)
filings in our Louisiana service areas, GRIP-related recoveries
in our Texas service areas and rate design changes in our
Missouri service areas.
Offsetting these increases in gross profit was a reduction in
revenue-related taxes. Due to a significant decline in the cost
of gas in the current-year period compared with the prior-year
period, franchise and state gross receipts taxes included in
gross profit decreased approximately $2.4 million; however,
franchise and state gross receipts tax expense recorded as a
component of taxes, other than income increased
$6.5 million, which resulted in a $4.1 million
increase in operating income when compared with the prior-year
period. Gross profit was also adversely affected by
$9.1 million from unfavorable rate rulings received in
Tennessee and our Mid-Tex Division during fiscal 2007 and a
reduction in other pass-through items. The prior-year’s
gross profit margin also reflects the recognition of
$6.2 million in previously deferred gross profit from the
2003 RSC filing in our Louisiana Division.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, increased to
$561.9 million for the nine months ended June 30, 2007
from $544.7 million for the nine months ended June 30,
2006.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $18.7 million, primarily due
to increased employee and other administrative costs and a
one-time $3.3 million noncash charge to write off software
that will no longer be used. These increases were partially
offset by the deferral of $4.3 million of incremental
Hurricane Katrina-related operation and maintenance expense in
our Louisiana Division.
The provision for doubtful accounts decreased $3.8 million
to $13.7 million for the nine months ended June 30,
2007. The decrease primarily was attributable to reduced
collection risk as a result of lower natural gas prices. In the
utility segment, the average cost of natural gas for the nine
months ended June 30, 2007 was $8.19 Mcf, compared
with $10.39 per Mcf for the nine months ended June 30, 2006.
Table of Contents
Depreciation and amortization expense increased
$11.6 million in the nine months ended June 30, 2007
compared with the prior-year period. The increase was primarily
attributable to increases in assets placed in service during
fiscal 2006. Additionally, the increase was partially
attributable to the absence in the current-year period of a
$2.8 million reduction in depreciation expense recorded in
the prior-year period arising from the Mississippi Public
Service Commission’s decision to allow certain deferred
costs in our rate base.
Interest charges allocated to the utility segment for the nine
months ended June 30, 2007 decreased to $91.2 million
from $92.8 million for the nine months ended June 30,
2006. The decrease was primarily attributable to lower average
outstanding short-term debt balances in the current-year period
compared with the prior-year period partially offset by
increased interest rates on our $300 million unsecured
floating rate senior notes due July 2007.
Financial and operational highlights for our natural gas
marketing segment for the nine months ended June 30, 2007
and 2006 are presented below.
The $16.2 million increase in our natural gas marketing
segment’s gross profit reflects a $41.2 million
increase in unrealized storage and marketing margins partially
offset by a $25.0 million reduction in realized margins.
Realized gross profit from our storage activities decreased
$6.1 million compared with the prior-year period. The
decrease reflects an increase in storage fees, park and loan
fees and the impact of a less volatile market, which reduced the
arbitrage spreads earned from these activities. These decreases
were more than offset by a $51.8 million increase in
unrealized margins attributable to a narrowing of the spreads
between the physical and forward natural gas prices, coupled
with the increase in our net physical position.
Table of Contents
Realized gross profit from our marketing activities decreased
$18.9 million compared with the prior-year period. This
decrease reflects the impact of a less volatile market, which
reduced opportunities to take advantage of pricing differences
between hubs, partially offset by increased sales volumes
attributable to successful execution of our marketing
strategies. Also contributing to the decrease in our marketing
activities was a $10.6 million decrease in unrealized
margins primarily attributable to an unfavorable movement in the
forward natural gas prices associated with the financial
derivatives used in these activities during the nine months
ended June 30, 2007.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $21.1 million for the nine months ended
June 30, 2007 from $18.2 million for the nine months
ended June 30, 2006. The increase in operating expense
primarily was attributable to an increase in employee and other
administrative costs.
Interest charges for the nine months ended June 30, 2007
decreased to $3.4 million from $6.6 million for the
nine months ended June 30, 2006. The decrease was
attributable to lower borrowing requirements during the current
year period.
Financial and operational highlights for our pipeline and
storage segment for the nine months ended June 30, 2007 and
2006 are presented below.
The $26.0 million increase in gross profit is primarily
attributable to a 28 percent increase in throughput and
increased demand for storage services. These activities
increased gross profit by $14.3 million, of which,
$8.7 million was associated with our North Side Loop and
other compression projects. Gross profit also includes an
increase of $1.6 million from the sale of excess gas
inventory by our Atmos Pipeline-Texas Division and
$2.1 million from rate adjustments resulting from Atmos
Pipeline-Texas Division’s 2005 GRIP filing. Finally, gross
profit increased $7.1 million from asset management fees
earned by APS due to its ability to capture more favorable
arbitrage spreads on its asset management contracts, coupled
with incremental margins received from APS’ asset
management contract with our Mississippi utility division
executed in July 2006.
Table of Contents
Operating expenses increased to $60.9 million for the nine
months ended June 30, 2007 from $57.9 million for the
nine months ended June 30, 2006 due to higher
administrative and other operating costs primarily associated
with the North Side Loop and other compression projects that
were completed in fiscal 2006.
Interest charges allocated to the pipeline and storage segment
for the nine months ended June 30, 2007 increased to
$24.6 million from $19.0 million for the nine months
ended June 30, 2006. The increase was attributable to the
use of updated allocation factors for fiscal 2007. These factors
are reviewed and updated on an annual basis.
Miscellaneous income increased to $5.5 million for the nine
months ended June 30, 2007 from $1.8 million for the
nine months ended June 30, 2006. The increase was primarily
attributable to $2.1 million received from leasing certain
mineral interests coupled with an increase in interest income
recorded in the pipeline and storage segment.
Operating income for this segment primarily reflects the leasing
income associated with two sales-type lease transactions
completed in 2001 and 2002 and did not materially change for the
nine months ended June 30, 2007 compared with the
prior-year period.
Our internally generated funds and borrowings under our credit
facilities and commercial paper program generally provide the
liquidity needed to fund our working capital, capital
expenditures and other cash needs. Additionally, from time to
time, we raise funds from the public debt and equity capital
markets through our existing shelf registration statement to
fund our liquidity needs.
In May 2007, we called our $300 million unsecured floating
rate senior notes for redemption on July 15, 2007. In June
2007, we issued $250 million of 6.35% Senior Notes due
2017. The net proceeds from this issuance, together with
available cash, were used to repay our $300 million senior
notes in July 2007. We believe the new senior notes, combined
with the other sources of funds described above will provide the
necessary working capital and liquidity for capital expenditures
and other cash needs for the remainder of fiscal 2007.
Our internally generated funds may change in the future due to a
number of factors, some of which we cannot control. These
include regulatory changes, prices for our products and
services, demand for such products and services, margin
requirements resulting from significant changes in commodity
prices, operational risks and other factors.
Period-over-period changes in our operating cash flows primarily
are attributable to changes in net income and working capital
changes, particularly within our utility segment. Our utility
segment’s working capital is primarily affected by the
price of natural gas, the timing of customer collections,
payments for natural gas purchases and deferred gas cost
recoveries.
For the nine months ended June 30, 2007, we generated
operating cash flow of $552.7 million from operating
activities compared with $223.4 million for the nine months
ended June 30, 2006. Period over period, our operating cash
flow was favorably impacted by improved net income, increased
sales volumes attributable to colder weather in the current-year
period and lower natural gas prices compared with the prior-year
period. Specifically, the timing of the collection of and
payment for other current assets, accounts payable and other
accrued liabilities increased operating cash flow by
$309.6 million. Additionally, improved management of our
deferred gas cost balances increased operating cash flow by
$77.4 million. These increases were partially offset by
$99.8 million associated with the unfavorable timing of
accounts receivable. Finally,
Table of Contents
other changes in working capital and other items increased
operating cash flow by $42.1 million, primarily resulting
from increased net income and favorable net changes associated
with our risk management activities.
In recent years, a substantial portion of our cash resources has
been used to fund acquisitions, new pipeline expansion projects
and our ongoing utility construction program. Our ongoing
utility construction program enables us to provide natural gas
distribution services to our existing customer base, expand our
natural gas distribution services into new markets, enhance the
integrity of our pipelines and, more recently, expand our
intrastate pipeline network. In executing our current rate
strategy, we are directing discretionary capital spending to
jurisdictions that permit us to earn a timely return in excess
of our cost of capital. Currently, our Mid-Tex, Louisiana,
Mississippi and West Texas utility divisions and our Atmos
Pipeline — Texas Division have rate designs that
provide the opportunity to include in their rate base approved
capital costs on a periodic basis without having to file a rate
case.
Capital expenditures for fiscal 2007 are expected to range from
$365 million to $385 million. For the nine months
ended June 30, 2007, we incurred $263.0 million for
capital expenditures compared with $322.7 million for the
nine months ended June 30, 2006. The decrease in capital
spending primarily reflects the absence of capital expenditures
associated with our North Side Loop and other pipeline
compression projects, which were completed in the third quarter
of fiscal 2006.
For the nine months ended June 30, 2007, our financing
activities reflected a use of cash of $5.2 million compared
with the $90.8 million provided from financing activities
in the prior-year period. Our significant financing activities
for the nine months ended June 30, 2007 and 2006 are
summarized as follows.
Table of Contents
As of June 30, 2007, we had a total of approximately
$1.5 billion of credit facilities, comprised of three
short-term committed credit facilities totaling
$918 million, one uncommitted credit facility totaling
$25 million and, through AEM, a second uncommitted credit
facility that can provide up to $580 million. Borrowings
under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas charged
by suppliers and the increased gas supplies required to meet
customers’ needs during periods of cold weather.
As of June 30, 2007, the amount available to us under our
credit facilities, net of outstanding letters of credit, was
$955.9 million. We believe these credit facilities,
combined with our operating cash flows will be sufficient to
fund our working capital needs. These facilities are described
in further detail in Note 4 to the unaudited condensed
consolidated financial statements.
On December 4, 2006, we filed a registration statement with
the SEC to issue, from time to time, up to $900 million in
common stock
and/or debt
securities available for issuance, including approximately
$401.5 million of capacity carried over from our prior
shelf registration statement filed with the SEC in August 2004.
In December 2006, we sold approximately 6.3 million shares
of common stock and used the net proceeds to reduce short-term
debt.
In June 2007, we issued $250 million of 6.35% Senior
Notes due 2017 under the registration statement. The net
proceeds of approximately $247 million, together with
$53 million of available cash, were used to repay our
$300 million unsecured floating rate senior notes, which
were called in May for redemption on July 15, 2007.
After these issuances, we have approximately $450 million
of availability remaining under the registration statement.
However, due to certain restrictions imposed by one state
regulatory commission on our ability to issue securities under
the registration statement, we now have remaining and available
for issuance a total of approximately $100 million of
equity securities, $50 million of senior debt securities
and $300 million of subordinated debt securities. In
addition, due to restrictions imposed by another state
regulatory commission, if the credit ratings on our senior
unsecured debt were to fall below investment grade from either
Standard & Poor’s Corporation (BBB-),
Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings,
Ltd. (BBB-), our ability to issue any type of debt securities
under the registration statement would be suspended until an
investment grade rating from all three credit rating agencies
was achieved.
We were in compliance with all of our debt covenants as of
June 30, 2007. Our debt covenants are described in
Note 4 to the unaudited condensed consolidated financial
statements.
Table of Contents
Our credit ratings directly affect our ability to obtain
short-term and long-term financing, in addition to the cost of
such financing. In determining our credit ratings, the rating
agencies consider a number of quantitative factors, including
debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and
pension liabilities and funding status. In addition, the rating
agencies consider qualitative factors such as consistency of our
earnings over time, the quality of our management and business
strategy, the risks associated with our utility and nonutility
businesses and the regulatory structures that govern our rates
in the states in which we operate.
Our debt is rated by three rating agencies: Standard &
Poor’s Corporation (S&P), Moody’s Investors
Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). Our
current debt ratings are all considered investment grade and are
as follows:
Currently, with respect to our unsecured senior long-term debt,
Moody’s and Fitch maintain their stable outlook. In June
2007, S&P upgraded their outlook from stable to positive.
None of our ratings are currently under review.
A credit rating is not a recommendation to buy, sell or hold
securities. The highest investment grade credit rating for
S&P is AAA, Moody’s is Aaa and Fitch is AAA. The
lowest investment grade credit rating for S&P is BBB-,
Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may
be revised or withdrawn at any time by the rating agencies, and
each rating should be evaluated independent of any other rating.
There can be no assurance 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.
As noted above, our capitalization is a leading quantitative
factor used to determine our credit ratings. The following table
presents our capitalization as of June 30,
2007 September 30, 2006 and June 30, 2006.
Total debt as a percentage of total capitalization, including
short-term debt, was 55.0 percent at June 30, 2007,
60.9 percent at September 30, 2006 and
59.9 percent at June 30, 2006. The decrease in the
debt to capitalization ratio primarily reflects the favorable
impact of our December 2006 equity offering and the absence of
short-term debt as of June 30, 2007, partially offset by
the timing of the repayment of our $300 million unsecured
floating rate senior notes. Had we been able to repay the notes
as of June 30, 2007, our total-debt-to-capitalization ratio
would have been 51.7 percent. Our ratio of total debt to
capitalization is typically greater during the winter heating
season as we make additional short-term borrowings to fund
natural gas purchases and meet our working capital requirements.
We intend to maintain our capitalization ratio in a target range
of 50 to 55 percent through cash flow generated from
operations, continued issuance of new common stock under our
Direct Stock Purchase Plan and Retirement Savings Plan and
access to the capital markets.
Table of Contents
Significant commercial commitments are described in Note 8
to the unaudited condensed consolidated financial statements.
There were no significant changes in our contractual obligations
and commercial commitments during the nine months ended
June 30, 2007, except for the issuance of our
$250 million ten year senior notes in June 2007 and the
repayment of our $300 million unsecured floating rate
senior notes in July 2007, as discussed in Note 4 to the
unaudited consolidated financial statements.
Additionally, in May 2006, we announced plans to construct a
natural gas gathering system in Eastern Kentucky, referred to as
the Straight Creek Project. This project has recently been
reconfigured and renamed the Phoenix Gas Gathering Project (the
“Phoenix Project”). The Phoenix Project, as currently
designed, would consist of approximately 40 miles of
12-inch and
20-inch pipe
with an initial throughput capacity of 50 MMcf/day but can
be expanded, if market conditions demand. We anticipate the
initial capital requirement to be approximately
$50 million. The inception of the project and the
in-service date are contingent on finalizing gathering
agreements covering sufficient minimum volumes to support the
project. We expect the project not to have a financial impact on
fiscal 2008 earnings.
We conduct risk management activities through both our utility
and natural gas marketing segments. In our utility segment, we
use a combination of storage, fixed physical contracts and fixed
financial contracts to reduce our exposure to unusually large
winter-period gas price increases. In our natural gas marketing
segment, we manage our exposure to the risk of natural gas price
changes and lock in our gross profit margin through a
combination of storage and financial derivatives, including
futures, over-the-counter and exchange-traded options and swap
contracts with counterparties. To the extent our inventory cost
and actual sales and actual purchases do not correlate with the
changes in the market indices we use in our hedges, we could
experience ineffectiveness or the hedges may no longer meet the
accounting requirements for hedge accounting, resulting in the
derivatives being treated as mark-to-market instruments through
earnings.
We record our derivatives as a component of risk management
assets and liabilities, which are classified as current or
noncurrent based upon the anticipated settlement date of the
underlying derivative. Substantially all of our derivative
financial instruments are valued using external market quotes
and indices. The following tables show the components of the
change in the fair value of our utility and natural gas
marketing commodity derivative contracts for the three and nine
months ended June 30, 2007 and 2006:
Table of Contents
The fair value of our utility and natural gas marketing
derivative contracts at June 30, 2007, is segregated below
by time period and fair value source:
AEM participates in transactions in which it seeks to find and
profit from pricing differences that occur over time. AEM
purchases physical natural gas and then sells financial
contracts at advantageous prices to lock in a gross profit
margin, which we refer to as the economic gross profit. AEM is
able to capture the economic gross profit through the arbitrage
of pricing differences in various locations and by recognizing
pricing differences that occur over time.
Natural gas inventory is marked to market at the end of each
month with changes in fair value recognized as unrealized gains
and losses in the period of change. Derivatives associated with
our natural gas inventory, which are designated as fair value
hedges, are marked to market each month based upon the NYMEX
price with changes in fair value recognized as unrealized gains
and losses in the period of change. The changes in the
difference between the indices used to mark to market our
physical inventory (Gas Daily) and the related fair-value hedge
(NYMEX) is reported as a component of revenue and can result in
volatility in our reported net income. Over time, gains and
losses on the sale of storage gas inventory will be offset by
gains and losses on the fair-value hedges; therefore, the
economic gross profit AEM captured in the original transaction
remains essentially unchanged.
AEM continually manages its positions to enhance the economic
gross profit it captured in the original transaction. Therefore,
AEM may change its scheduled injection and withdrawal plans from
one time period to another based on market conditions or adjust
the amount of storage capacity it holds on a discretionary basis
in an effort to achieve this object | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||