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| ATO > SEC Filings for ATO > Form 10-Q on 7-Feb-2013 | All Recent SEC Filings |
7-Feb-2013
Quarterly Report
INTRODUCTION
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, 2012.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
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: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. 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.
OVERVIEW
Atmos Energy and its subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in nine states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. In August 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, representing approximately 64,000 customers. After the closing of this transaction, which we currently anticipate will occur during the third quarter of fiscal 2013, we will operate in eight states.
Through our nonregulated businesses, we provide natural gas management and transportation services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and
As discussed in Note 11, we operate the Company through the following three segments:
• the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
• the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline - Texas Division and
• the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
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, the 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 fiscal year ended September 30, 2012 and include the following:
• Regulation
• Unbilled revenue
• Financial instruments and hedging activities
• Fair value measurements
• Impairment assessments
• Pension and other postretirement plans
• Contingencies
Our critical accounting policies are reviewed periodically by the Audit Committee. There were no significant changes to these critical accounting policies during the three months ended December 31, 2012.
RESULTS OF OPERATIONS
We reported net income of $80.5 million, or $0.88 per diluted share for the three months ended December 31, 2012 compared with net income of $68.5 million, or $0.75 per diluted share in the prior-year quarter. Regulated operations contributed 90 percent of our net income during this period with our nonregulated operations contributing the remaining ten percent. Excluding the impact of unrealized margins, diluted earnings per share increased $0.13 compared with the prior-year quarter. The $0.13 per diluted share increase primarily reflects recent rate increases approved in our regulated transmission and storage segment and improved asset optimization margins in our nonregulated segment, coupled with an $8.1 million decrease in operating and maintenance expense and a $5.2 million decrease in interest expense due primarily from interest capitalized related to Rule 8.209 spending in the current quarter and the early redemption of the 5.125% $250 million senior notes due January 2013, with funds borrowed under a $260 million short-term debt facility in August 2012.
During the first quarter of fiscal 2013, we completed seven regulatory proceedings, which should result in a $63.7 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company's rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second quarters to be lower than in previous periods with operating income earned during the third and fourth quarters to be higher than in previous periods. Accordingly, we anticipate our fiscal 2013 period-over-period results will reflect the impact of these rate design changes.
We also took several steps during the first quarter and early part of the second quarter to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. We also terminated Atmos Energy Marketing's $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.
On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.
Three Months Ended
December 31
2012 2011
(In thousands, except per
share data)
Operating revenues $ 1,034,155 $ 1,083,994
Gross profit 362,362 355,392
Operating expenses 207,440 215,921
Operating income 154,922 139,471
Miscellaneous income (expense) 698 (2,016 )
Interest charges 30,522 35,726
Income from continuing operations before income taxes 125,098 101,729
Income tax expense 47,750 39,345
Income from continuing operations 77,348 62,384
Income from discontinued operations, net of tax 3,117 6,123
Net income $ 80,465 $ 68,507
Diluted net income per share from continuing operations $ 0.85 $ 0.68
Diluted net income per share from discontinued operations 0.03 0.07
Diluted net income per share $ 0.88 $ 0.75
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Our consolidated net income during the three months ended December 31, 2012 and 2011 was earned in each of our business segments as follows:
Three Months Ended
December 31
2012 2011 Change
(In thousands)
Natural gas distribution segment $ 56,210 $ 50,624 $ 5,586
Regulated transmission and storage segment 16,105 13,414 2,691
Nonregulated segment 8,150 4,469 3,681
Net income $ 80,465 $ 68,507 $ 11,958
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Three Months Ended December 31
2012 2011 Change
(In thousands, except per share data)
Regulated operations $ 69,198 $ 57,915 $ 11,283
Nonregulated operations 8,150 4,469 3,681
Net income from continuing operations 77,348 62,384 14,964
Net income from discontinued operations 3,117 6,123 (3,006 )
Net income $ 80,465 $ 68,507 $ 11,958
Diluted EPS from continuing regulated operations $ 0.76 $ 0.63 $ 0.13
Diluted EPS from nonregulated operations 0.09 0.05 0.04
Diluted EPS from continuing operations 0.85 0.68 0.17
Diluted EPS from discontinued operations 0.03 0.07 (0.04 )
Consolidated diluted EPS $ 0.88 $ 0.75 $ 0.13
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Three Months Ended December 31, 2012 compared with Three Months Ended December 31, 2011
Natural Gas Distribution Segment
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 96 percent of our residential and commercial meters in the following states for the following time periods:
Georgia, Kansas, West Texas October - May
Kentucky, Mississippi, Tennessee, Mid-Tex November - April
Louisiana December - March
Virginia January - December
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Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without a 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 does include franchise fees and gross receipts 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 associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
In August 2012, we announced that we had entered into a definitive agreement to sell substantially all of our natural gas distribution operations in Georgia. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these service areas was completed in August 2012. The results of these operations have been separately reported in the following tables as discontinued operations and exclude general corporate overhead and interest expense that would normally be allocated to these operations.
During the first quarter of fiscal 2013, we completed seven regulatory proceedings, which should result in a $63.7 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase in the base customer charge and a decrease in the commodity charged applied to customer consumption. The effect of this change in rate design allows the Company's rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second quarters to be lower than in previous periods while operating income earned during the third and fourth quarters to be higher than in previous periods. Accordingly, we anticipate our 2013 period-over-period results will reflect the impact of these rate design changes.
Review of Financial and Operating Results
Financial and operational highlights for our natural gas distribution segment
for the three months ended December 31, 2012 and 2011 are presented below.
Three Months Ended December 31
2012 2011 Change
(In thousands, unless otherwise noted)
Gross profit $ 279,631 $ 283,595 $ (3,964 )
Operating expenses 170,547 180,170 (9,623 )
Operating income 109,084 103,425 5,659
Miscellaneous expense (131 ) (1,897 ) 1,766
Interest charges 23,563 28,139 (4,576 )
Income from continuing operations before
income taxes 85,390 73,389 12,001
Income tax expense 32,297 28,888 3,409
Income from continuing operations 53,093 44,501 8,592
Income from discontinued operations, net of
tax 3,117 6,123 (3,006 )
Net income $ 56,210 $ 50,624 $ 5,586
Consolidated natural gas distribution sales
volumes from continuing operations - MMcf 78,753 83,367 (4,614 )
Consolidated natural gas distribution
transportation volumes from continuing
operations - MMcf 32,889 32,277 612
Consolidated natural gas distribution
throughput from continuing operations - MMcf 111,642 115,644 (4,002 )
Consolidated natural gas distribution
throughput from discontinued operations - MMcf 2,057 6,104 (4,047 )
Total consolidated natural gas distribution
throughput - MMcf 113,699 121,748 (8,049 )
Consolidated natural gas distribution average
transportation revenue per Mcf $ 0.47 $ 0.45 $ 0.02
Consolidated natural gas distribution average
cost of gas per Mcf sold $ 4.93 $ 4.78 $ 0.15
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The $4.0 million decrease in natural gas distribution gross profit primarily reflects the following:
• $4.6 million net decrease in rate adjustments, primarily in the Mid-Tex Division due to the rate design approved in our most recent Mid-Tex rate case, which includes an increase in the base customer charge and a decrease in the commodity charge applied to customer consumption.
• $2.7 million decrease in revenue related taxes in our Mid-Tex and West Texas Divisions, primarily due to lower revenues on which the tax is calculated.
These decreases were partially offset by a $2.4 million increase from colder weather, primarily in the Mid-Tex service area.
• $2.8 million decrease in legal costs, primarily due to the absence of prior-year settlement costs.
• $1.9 million decrease in franchise fees due to lower revenue on which the tax is calculated.
• $1.7 million decrease due to the establishment of regulatory assets for pension and postretirement costs.
• $1.0 million decrease in operating expenses due to increased capital spending.
Interest charges decreased $4.6 million, primarily from interest capitalized related to Rule 8.209 spending in the current quarter and the early redemption of the 5.125% $250 million senior notes due January 2013, with funds borrowed under a $260 million short-term debt facility in August 2012.
The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended December 31, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
Three Months Ended December 31
2012 2011 Change
(In thousands)
Mid-Tex $ 45,577 $ 48,449 $ (2,872 )
Kentucky/Mid-States 15,705 11,382 4,323
Louisiana 16,885 15,201 1,684
West Texas 9,578 10,675 (1,097 )
Mississippi 11,613 10,132 1,481
Colorado-Kansas 8,744 8,179 565
Other 982 (593 ) 1,575
Total $ 109,084 $ 103,425 $ 5,659
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Recent Ratemaking Developments
Significant ratemaking developments that occurred during the three months ended December 31, 2012 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a final order from a commission or other governmental authority.
Annual net operating income increases totaling $63.7 million resulting from ratemaking activity became effective in the quarter ended December 31, 2012 as summarized below:
Annual Increase to
Rate Action Operating Income
(In thousands)
Rate case filings $ 56,700
Infrastructure programs 3,605
Annual rate filing mechanisms 3,441
$ 63,746
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