SPIRE INC
10-Ks and 10-Qs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.
FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended
September 30, 2013
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.
FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended
September 30, 2013
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
|
[ X ]
|
ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2013
|
OR
|
[ ]
|
TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from __________ to __________
|
Commission File Number 1-16681
THE LACLEDE GROUP, INC.
(Exact name of registrant as specified in its charter)
|
Missouri
(State of Incorporation)
|
74-2976504
(I.R.S. Employer Identification number)
|
|
720 Olive Street
St. Louis, MO 63101
(Address and zip code of principal executive offices)
314-342-0500
(Registrant’s telephone number, including area code)
|
|
Securities registered pursuant to Section 12(b) of the Act
|
Title of Each Class
|
Name of Each Exchange On Which
Registered
|
|
Common Stock $1.00 par value
|
New York Stock Exchange
|
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant:
is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ X ] No [ ]
is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [ X ]
(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 report) and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]
has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( X )
Indicate by check mark whether the registrant:
is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
|
|
Large accelerated filer
|
[ X ]
|
|
Accelerated filer
|
[ ]
|
|
|
Non-accelerated filer
|
[ ]
|
|
Smaller reporting company
|
[ ]
|
is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [ X ]
The aggregate market value of the voting stock held by non-affiliates of The Laclede Group, Inc.
amounted to $906,985,448 as of March 31, 2013.
As of November 21, 2013, there were 32,709,763 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.
Document Incorporated by Reference:
Portions of Proxy Statement dated December 18, 2013 — Part III
Index to Exhibits
is found on page 102.
|
TABLE OF CONTENTS
|
Page No.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
3
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this report, excluding historical information, include forward-looking statements. Certain words, such as “may,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “seek,” and similar words and expressions identify forward-looking statements that involve uncertainties and risks. Future developments may not be in accordance with our current expectations or beliefs and the effect of future developments may not be those anticipated. Among the factors that may cause results to differ materially from those contemplated in any forward-looking statement are:
|
•
|
weather conditions and catastrophic events, particularly severe weather in the natural gas producing areas of the country;
|
|
•
|
volatility in gas prices, particularly sudden and sustained changes in natural gas prices, including the related impact on margin deposits associated with the use of natural gas derivative instruments;
|
|
•
|
the impact of changes and volatility in natural gas prices on our competitive position in relation to suppliers of alternative heating sources, such as electricity;
|
|
•
|
changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells, expiration of existing supply and transportation arrangements that are not replaced with contracts with similar terms and pricing, as well as other changes that impact supply for and access to the markets in which our subsidiaries transact business;
|
|
•
|
legislative, regulatory and judicial mandates and decisions, some of which may be retroactive, including those affecting
|
|
•
|
allowed rates of return
|
|
•
|
incentive regulation
|
|
•
|
industry structure
|
|
•
|
purchased gas adjustment provisions
|
|
•
|
rate design structure and implementation
|
|
•
|
regulatory assets
|
|
•
|
non-regulated and affiliate transactions
|
|
•
|
franchise renewals
|
|
•
|
environmental or safety matters, including the potential impact of legislative and regulatory actions related to climate change and pipeline safety
|
|
•
|
taxes
|
|
•
|
pension and other postretirement benefit liabilities and funding obligations
|
|
•
|
accounting standards;
|
|
•
|
the results of litigation;
|
|
•
|
retention of, ability to attract, ability to collect from, and conservation efforts of, customers;
|
|
•
|
capital and energy commodity market conditions, including the ability to obtain funds with reasonable terms for necessary capital expenditures and general operations and the terms and conditions imposed for obtaining sufficient gas supply;
|
|
•
|
discovery of material weakness in internal controls; and
|
|
•
|
employee workforce issues.
|
Readers are urged to consider the risks, uncertainties, and other factors that could affect our business as described in this report. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. We do not, by including this statement, assume any obligation to review or revise any particular forward-looking statement in light of future events.
4
Overview
The Laclede Group, Inc. (Laclede Group or the Company) is a public utility holding company formed through a corporate restructuring that became effective October 1, 2001. The Company has two key business segments: Gas Utility and Gas Marketing. The Gas Utility segment includes the regulated operations of Laclede Gas Company (the Utility), Laclede Group’s largest subsidiary. Laclede Gas Company is a public utility engaged in the retail distribution and sale of natural gas, and is the largest natural gas distribution utility in Missouri, serving more than 1.13 million residential, commercial and industrial customers. The Utility serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy (MGE), whose assets were acquired by the Utility on September 1, 2013. The Gas Marketing segment includes Laclede Energy Resources, Inc. (LER), a wholly owned subsidiary engaged in the marketing of natural gas and related activities on a non-regulated basis. As of
September 30, 2013
, Laclede Group had 2,326 employees, including 49 part-time employees.
Consolidated operating revenues contributed by each segment for the last three fiscal years are presented below. For more detailed financial information regarding the segments, see
Note 15
of the Notes to Consolidated Financial Statements.
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Gas Utility
|
$
|
847,224
|
|
$
|
763,447
|
|
$
|
913,190
|
|
||
|
Gas Marketing
|
165,146
|
|
358,145
|
|
669,375
|
|
|||||
|
Other
|
4,649
|
|
3,883
|
|
20,742
|
|
|||||
|
Total Operating Revenues
|
$
|
1,017,019
|
|
$
|
1,125,475
|
|
$
|
1,603,307
|
|
||
Laclede Group’s common stock is listed on The New York Stock Exchange and trades under the ticker symbol “LG.”
The following table reflects shares issued during the periods indicated:
|
|
2013
|
2012
|
|||
|
Common Stock Issuance
|
10,005,000
|
|
—
|
|
|
|
DRIP
|
44,074
|
|
46,107
|
|
|
|
Equity Incentive Plan
|
108,331
|
|
62,590
|
|
|
|
Total Shares Issued
|
10,157,405
|
|
108,697
|
|
|
Shares were issued during 2013 to effect the acquisition of the MGE assets as well as historically consistent levels for Laclede Group's Dividend Reinvestment and Stock Purchase Plan (DRIP) and its Equity Incentive Plan.
The information we file or furnish to the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K and their amendments, are available on our website,
www.TheLacledeGroup.com
, in the Investor Services section under SEC Filings as soon as reasonably practical after the information is filed or furnished to the SEC.
Gas Utility
NATURAL GAS SUPPLY
The Utility focuses its gas supply portfolio around a number of large natural gas suppliers with equity ownership or control of assets strategically situated to complement its regionally diverse firm transportation arrangements.
The Utility's fundamental gas supply strategy is to meet the two-fold objective of 1) ensuring that the gas supplies it acquires are dependable and will be delivered when needed and 2) insofar as is compatible with that dependability, purchasing gas that is economically priced. In structuring its natural gas supply portfolio, Laclede Gas continues to focus on natural gas assets that are strategically positioned to meet the Utility’s primary objectives. Laclede Gas utilizes both Mid-Continent and Gulf Coast gas sources to provide a level of supply diversity that facilitates the optimization of pricing differentials as well as protecting against the potential of regional supply disruptions. MGE utilizes both Mid-Continent and Rocky Mountain gas sources to provide a level of supply diversity that accesses low cost supplies while providing a natural gas price arbitrage.
5
In fiscal year
2013
, the Utility purchased natural gas from 35 different suppliers to meet current gas sales and storage injection requirements. The Utility entered into firm agreements with suppliers including major producers and marketers providing flexibility to meet the temperature sensitive needs of its customers. Natural gas purchased by the Laclede Gas for delivery to its service area through the Enable Mississippi River Transmission LLC (MRT) system totaled 55.0 billion cubic feet (Bcf). Laclede Gase also holds firm transportation on several other interstate pipeline systems that provide access to gas supplies upstream of MRT. In addition to deliveries from MRT, 8.6 Bcf of gas was purchased on MO Gas, 13.4 Bcf on the Southern Star Central Gas Pipeline, Inc. (Southern Star Central), 0.03 Bcf on the Panhandle Eastern Pipe Line Company system, and 0.1 BCF on the Postrock system. Some of the Utility’s commercial and industrial customers purchased their own gas with the Utility transporting 17.0 Bcf to them through the Utility’s distribution system.
The fiscal year
2013
peak day sendout of natural gas to Laclede Gas customers, including transportation customers, occurred on January 22, 2013, when the average temperature was 16 degrees Fahrenheit in St. Louis. On that day, Laclede Gas customers consumed 0.766 Bcf of natural gas. About 91% of this peak day demand was met with natural gas transported to St. Louis through the MRT, MO Gas, and Southern Star transportation systems, and the other 9% was met from Laclede Gas' on-system storage and peak shaving resources.
UNDERGROUND NATURAL GAS STORAGE
The Utility has a contractual right to store 23.1 Bcf of gas in MRT’s storage facility located in Unionville, Louisiana, 16.3 Bcf of gas storage in Southern Star Central system storage facilities located in Kansas and Oklahoma, and 1.4 Bcf of firm storage on Panhandle Eastern Pipe Line Company
’
s system storage. MRT’s tariffs allow injections into storage from May 16 through November 15 and require the withdrawal from storage of all but 2.2 Bcf from November 16 through May 15. Southern Star Central tariffs allow both injections and withdrawals into storage year round with ratchets that restrict the associated flows dependent upon the underlying inventory level per the contracts.
In addition, the Utility supplements flowing pipeline gas with natural gas withdrawn from its own underground storage field located in St. Louis and St. Charles Counties in Missouri. The field is designed to provide 0.3 Bcf of natural gas withdrawals on a peak day and annual withdrawals of approximately 4.0 Bcf of gas based on the inventory level that Laclede plans to maintain.
REGULATORY MATTERS
For details on regulatory matters, see the
Regulatory and Other Matters
discussion in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on page
36
of this Form 10-K.
OTHER PERTINENT MATTERS
The Utility's business has monopoly characteristics in that it is the only distributor of natural gas within its franchised service areas. The principal competition are the local electric companies. Other competitors in the Utility's service areas include suppliers of fuel oil, coal, propane, natural gas pipelines which can directly connect to large volume customers, and district steam systems in the downtown areas of both St. Louis and Kansas City.
The Utility’s residential, commercial, and small industrial markets represent approximately 85% of the Utility's operating revenue. Given the current level of natural gas supply and market conditions, the Utility believes that the relative comparison of natural gas equipment and operating costs with those of competitive fuels will not change significantly in the foreseeable future, and that these markets will continue to be supplied by natural gas. In new multi-family and commercial rental markets, the Utility's competitive exposure is presently limited to space and water heating applications. Certain alternative heating systems can be cost competitive in traditional markets.
Coal is price competitive as a fuel source for very large boiler plant loads, but environmental requirements for coal have shifted the economic advantage to natural gas. Oil and propane can be used to fuel boiler loads and certain direct-fired process applications, but these fuels require on-site storage, thus limiting their competitiveness. In certain cases, district steam has been competitive with gas for downtown St. Louis and Kansas City area heating users. The Utility offers gas transportation service to its large user industrial and commercial customers. The tariff approved for that type of service
produces a margin similar to that which the Utility would have received under its regular sales rates.
6
*****
The Utility is subject to various environmental laws and regulations that, to date, have not materially affected the Company’s financial position and results of operations. For a detailed discussion of environmental matters, see
Note 16
of the Notes to Consolidated Financial Statements.
*****
Laclede Gas has labor agreements with Locals 884, 11-6 and 11-194 of the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union (Union), which represent approximately 67% of Laclede Gas’ employees. The agreements with Locals 11-6 and 11-194 will expire at midnight on July 31, 2014. Laclede Gas and Local 884 have a labor agreement that expires on midnight on July 31, 2015.
MGE has labor agreements with Locals 12561, 14228 and 11-267 of the United Steelworkers (Union), which represents 26% of Missouri Gas Energy employees; Gasworkers Metal Trades Local 781 of the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada, A.F. of L. - C.I.O. (Union) which represents approximately 34% of Missouri Gas Energy employees; and Local 53 of the International Brotherhood of Electrical Workers (Union) which represents approximately 13% of Missouri Gas Energy employees. Missouri Gas Energy and Locals 12561, 14228, and 11-267, 781, and 53 have labor agreements that will expire at 11:59 p.m. on April 30, 2014.
*****
The business of the Utility is subject to seasonal fluctuations with the peak period occurring in the winter season.
*****
Revenues, therms sold and transported, and customers of the Utility for the last three fiscal years are as follows (before intersegment eliminations):
|
Gas Utility Operating Revenues
|
|||||||||||
|
(Thousands)
|
2013*
|
2012
|
2011
|
||||||||
|
Residential
|
$
|
556,818
|
|
$
|
487,529
|
|
$
|
584,788
|
|
||
|
Commercial & Industrial
|
184,101
|
|
161,866
|
|
202,017
|
|
|||||
|
Interruptible
|
3,524
|
|
2,105
|
|
3,659
|
|
|||||
|
Transportation
|
15,293
|
|
14,094
|
|
14,426
|
|
|||||
|
Off-System and Capacity Release
|
90,188
|
|
92,477
|
|
100,225
|
|
|||||
|
Other
|
7,838
|
|
6,580
|
|
8,075
|
|
|||||
|
Total
|
$
|
857,762
|
|
$
|
764,651
|
|
$
|
913,190
|
|
||
|
Gas Utility Therms Sold and Transported
|
|
||||||||||
|
(Thousands)
|
2013*
|
2012
|
2011
|
||||||||
|
Residential
|
496,623
|
|
385,317
|
|
497,171
|
|
|||||
|
Commercial & Industrial
|
229,562
|
|
183,536
|
|
228,080
|
|
|||||
|
Interruptible
|
3,149
|
|
3,013
|
|
5,098
|
|
|||||
|
Transportation
|
160,411
|
|
146,117
|
|
155,067
|
|
|||||
|
System Therms Sold and Transported
|
889,745
|
|
717,983
|
|
885,416
|
|
|||||
|
Off-System
|
229,358
|
|
314,473
|
|
223,000
|
|
|||||
|
Total Therms Sold and Transported
|
1,119,103
|
|
1,032,456
|
|
1,108,416
|
|
|||||
|
Gas Utility Customers (End of Period)
|
|
||||||||||
|
|
2013*
|
2012
|
2011
|
||||||||
|
Residential
|
1,027,556
|
|
588,061
|
|
584,926
|
|
|||||
|
Commercial & Industrial
|
99,960
|
|
39,741
|
|
39,995
|
|
|||||
|
Interruptible
|
17
|
|
15
|
|
15
|
|
|||||
|
Transportation
|
1,003
|
|
140
|
|
141
|
|
|||||
|
Total Customers
|
1,128,536
|
|
627,957
|
|
625,077
|
|
|||||
*Includes MGE for the month of September 2013, and for the end of the period.
7
*****
The Utility has franchises in nearly all of the 236 Missouri communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows the Utility, among other things, to install pipes and construct other facilities in the community. Certain franchise agreements have expired, including Clayton (in 2008), St. Charles County (in 2013), North Kansas City (in 2013), Cameron (in 2013), and Riverside (in 2013) and since that time the Utility has continued to provide service in those communities without formal franchises. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of the Utility's current public utility business in the State of Missouri.
Gas Marketing
LER is engaged in the marketing of natural gas and providing energy services to both on-system utility transportation customers and customers outside of the Utility’s traditional service area. During fiscal year 2013, LER utilized 12 interstate pipelines and 93 suppliers to market natural gas to its customers primarily in the Midwest. LER served more than 205 retail customers and 100 wholesale customers. Through its retail operations, LER offers natural gas marketing services to large industrial customers, while its wholesale business consists of buying and selling natural gas to other marketers, producers, utilities, power generators, pipelines, and municipalities. Wholesale activities currently represent a large majority of LER’s total business. LER also serves power plants that use natural gas to generate electricity.
In the course of its business, LER enters into agreements to purchase natural gas at a future date in order to lock up supply to cover future sales commitments to its customers. To secure access to the markets it serves, LER contracts for transportation capacity on pipelines. During fiscal year 2013, LER had several long-term transportation contracts that came up for renewal and was able to lower its overall transportation costs through renegotiation of contracts at lower rates. In addition, LER further reduced its costs by allowing certain transportation contracts to lapse. To provide additional operational flexibility, LER enters into park and loan transactions with pipeline companies, whereby it pays a fee to deliver natural gas to the pipeline that is redelivered to LER at a future date, at which time LER sells the natural gas to a third party. Furthermore, beginning in August 2013, LER contracted for storage capacity in northeastern Louisiana under a long-term agreement to meet the future needs of the growing gas-fired power generation market.
Historically, LER’s business has been primarily comprised of physically settled sales of natural gas to its wholesale and retail customers, whereby LER purchased natural gas at one location and transported it on its pipeline capacity to a higher-priced location. In order to transport gas on pipelines, LER incurred fuel and commodity charges on each of the movements from one location to another. As a result of new pipeline infrastructure and an abundance of natural gas supply, regional price differences have narrowed and overall price volatility has been reduced. This reduction in regional price differentials allows LER to satisfy its commitments without incurring fuel costs to transport natural gas to a different location. As a result, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically, so many transactions entered into in fiscal year 2013 are designated as trading activities for financial reporting purposes. Results of operations from trading activities are reported on a net basis in Gas Marketing Operating Revenues. This presentation has no effect on operating income or net income.
LER’s strategy is to leverage its market expertise and risk management skills to manage and optimize the value of its portfolio of commodity, transportation, park and loan, and storage contracts while controlling costs and acting on new marketplace opportunities. LER was profitable in fiscal year 2013, despite a challenging market.
Looking forward, market conditions continue to be challenging with low market volatility and historically small price differentials between geographic regions which drive transportation values and also seasonal spreads which drive storage and park and loan values.
OTHER
Laclede Pipeline Company, a wholly owned subsidiary, operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction. This pipeline connects the propane storage and vaporization facilities of the Utility to third-party propane supply terminal facilities located in Illinois, which allows the Utility to receive propane that is vaporized to supplement its natural gas supply and meet peak demands on its distribution system. Laclede Pipeline Company also provides transportation services to third parties.
8
Other also includes Laclede Group’s subsidiaries that are engaged in, among other activities, oil production, real estate development, compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. The Other category also includes the Utility’s non-regulated propane services business which involves providing propane-related services and storage to third parties and its affiliate, Laclede Pipeline Company. Beginning July 1, 2013, propane-related services are included within Gas Utility operations pursuant to the Utility's new rate case.
Laclede Group’s business and financial results are subject to a number of risks and uncertainties, including those set forth below. The risks described below are those the Company considers to be material. When considering any investment in Laclede Group securities, investors should carefully consider the following information, as well as information contained in the caption "Forward-Looking Statements,"
Item 7A
, and other documents Laclede files with the SEC. This list is not exhaustive, and Laclede Group's management places no priority or likelihood based on the risk descriptions, order of presentation or grouping by subsidiary.
RISKS AND UNCERTAINTIES THAT RELATE TO THE BUSINESS AND FINANCIAL RESULTS OF LACLEDE GROUP AND ITS SUBSIDIARIES
As a holding company, Laclede Group depends on its operating subsidiaries to meet its financial obligations.
Laclede Group is a holding company with no significant assets other than the stock of its operating subsidiaries and cash investments. Laclede Group, and the Utility prior to Laclede Group’s formation, have paid dividends continuously since 1946. However, Laclede Group relies exclusively on dividends from its subsidiaries, on intercompany loans from its non-utility subsidiaries, and on the repayments of principal and interest from intercompany loans made to its subsidiaries for its cash flows. Laclede Group’s ability to pay dividends to its shareholders is dependent on the ability of its subsidiaries to generate sufficient net income and cash flows to pay upstream dividends and make loans or loan repayments.
A downgrade in Laclede Group’s credit ratings may negatively affect its ability to access capital.
Currently, Laclede Group has investment grade credit ratings, which are subject to review and change by the rating agencies. Laclede Group has working capital lines of credit to meet the short-term liquidity needs of its subsidiaries. If the rating agencies lowered Laclede Group’s credit rating, particularly below investment grade, it might significantly limit its ability to secure new or additional credit facilities and would increase its costs of borrowing. Laclede Group’s ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on its subsidiaries’ ability to execute their operating strategies. In the fourth quarter of 2013, Standard & Poor’s and Fitch Ratings each lowered their ratings of Laclede Group by one notch to A- and BBB+, respectively. There are no implications of this downgrade on our corporate funding ability or our ability to access the capital markets, nor does this downgrade trigger any collateralization requirements under our corporate guarantees. There is no assurance that such credit ratings will be issued or remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant. For additional credit rating information, see
Item 7
, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources.”
Unexpected losses may adversely affect Laclede Group’s financial condition and results of operations.
As with most businesses, there are operations and business risks inherent in the activities of Laclede Group’s subsidiaries. If, in the normal course of business, Laclede Group becomes a party to litigation, such litigation could result in substantial monetary judgments, fines, or penalties or be resolved on unfavorable terms. In accordance with customary practice, Laclede Group and its subsidiaries maintain insurance against a significant portion of, but not all, risks and losses. In addition, in the normal course of its operations, Laclede Group and its subsidiaries may be exposed to loss from other sources, such as bad debt expense or the failure of a counterparty to meet its financial obligations. Laclede Group and its operating companies employ many strategies to gain assurance that such risks are appropriately managed, mitigated, or insured, as appropriate. To the extent a loss is not fully covered by insurance or other risk mitigation strategies, that loss could adversely affect the Company’s financial condition and results of operations.
9
Increased inter-dependence on technology may adversely hinder Laclede Group’s business operations and affect its financial condition and results of operations if such technologies fail or are compromised.
Over the last several years, Laclede Group and its subsidiaries have implemented a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. In fiscal year 2013, the Company completed its implementation of a Company-wide enterprise resource planning (ERP) system. These tools and systems support critical functions including the Company’s integrated planning, scheduling and dispatching of field resources, its automated meter reading system, customer care and billing, procurement and accounts payable, operational plant logistics, management reporting, and external financial reporting. The failure of these or other similarly important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations. Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts to date would protect against all potential issues related to the loss of any such technologies or their use.
Furthermore, the Company is subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the Company in the normal course of business, as well as breaches in the technology that manages natural gas distribution operations and other business processes. A loss of confidential or proprietary data or security breaches of other technology business tools could adversely affect the Company’s reputation, diminish customer confidence, disrupt operations, and subject the Company to possible financial liability, any of which could have a material affect on the Company’s financial condition and results of operations. The Company closely monitors both preventive and detective measures to manage these risks and maintains cyber risk insurance to mitigate a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these cyber events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.
The Company has also completed the acquisition of the assets and liabilities of MGE in Kansas City. Through fiscal 2015, the Utility will be integrating MGE’s data into Laclede’s systems. During this time the Utility will also be evaluating the security controls both process and tool based in place at MGE.
Resources expended to pursue business acquisitions, investments or other business arrangements may adversely affect Laclede Group’s financial position and results of operations and return on investments made may not meet expectations.
From time to time, Laclede Group may seek to grow through strategic acquisitions, investments or other business arrangements, including the Missouri Gas Energy transaction completed in fiscal year 2013. Attractive acquisition candidates may be difficult to acquire on economically acceptable terms. It is possible for Laclede Group to expend considerable resources pursuing an acquisition candidate, but for a variety of reasons such as changes in economic conditions, changes in the acquisition candidate’s business or concerns arising out of due diligence review, decide not to consummate a definitive transaction. To the extent that acquisitions are made, such acquisitions involve a number of risks, including but not limited to, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, securing adequate capital to support the transaction, and regulatory approval. Uncertainties exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to complete an acquisition successfully, or to integrate future acquisitions that it may choose to undertake could have an adverse effect on its financial condition, results of operations and the market’s perception of the Company’s execution of its strategy.
In order to manage and diversify the risks of certain development projects, Laclede Group may use partnerships or other investments. Such business arrangements may limit Laclede Group’s ability to fully direct the management and policies of the business relationship. These arrangements may cause additional risks such as operating agreements limiting Laclede Group's control or Laclede Group's ability to appropriately value the business drivers or assets of the business arrangement. While Laclede Group would pursue strategies to mitigate these risks and enforce its interests, these risks may adversely impact the projects and Laclede Group’s financial condition, results of operations and cash flows.
10
Changes in accounting standards may adversely impact the Utility's financial condition and results of operations.
Laclede group is subject to changes in U.S. Generally Accepted Accounting Principles (GAAP), SEC regulations and other interpretations of financial reporting requirements for public utilities. The company has no control over the impact these changes may have on our financial condition or results of operations nor the timing of such changes. The potential issues associated with rate-regulated accounting, along with other potential changes considered by U.S. Financial Accounting Standards Board continues to consider various changes to U.S. GAAP may be significant.
RISKS RELATED TO THE COMPANY'S ACQUISITION OF MISSOURI GAS ENERGY (MGE) ASSETS AND LIABILITIES AS WELL AS THE ACQUISITION AGREEMENTS WITH SOUTHERN UNION COMPANY AND ALGONQUIN POWER & UTILITIES CORP REGARDING NEW ENGLAND GAS ASSETS AND LIABILITIES.
The New England Gas (NEG) transaction may not be completed or may be approved subject to unfavorable regulatory conditions, which could adversely affect anticipated benefits and/or Laclede Group's business, financial condition, results of operations and/or stock price.
On December 14, 2012, Laclede Group, through a wholly owned subsidiary, Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts), entered into an acquisition agreement to acquire from Southern Union Company (SUG) substantially all of the assets and liabilities of New England Gas Company (NEG). On February 11, 2013, the Company entered into an agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary, through its acquisition of the stock of Plaza Massachusetts, to acquire the Company's rights to purchase the assets of NEG, subject to certain approvals and conditions. In order to close the NEG transaction, approval by the Massachusetts Department of Public Utilities (MDPU) of the acquisition of the assets of NEG by the APUC subsidiary must be received.
The sale of NEG to APUC is still pending before the MDPU. The acquisition agreement contains certain termination rights for both the Company and SUG, including, among others, the right to terminate if the transaction is not completed by October 14, 2013 (subject to up to four 30-day extensions under certain circumstances related to obtaining required regulatory approvals). The Company and SUG have agreed to extend the NEG purchase agreement twice until December 14, 2013 to enable the MDPU to complete its review process. Nonetheless, there can be no assurance that APUC will be able to satisfy all of the required conditions on or before the end of the extension periods. The Company's agreement to acquire NEG remains in effect if APUC cannot satisfy the conditions for closing before the expiration of the extension periods.
The pending transaction with APUC and SUG for the NEG assets subjects Laclede Group to a number of additional risks, including the following:
|
•
|
the Company’s estimate of the costs to complete the sale of NEG may vary significantly from actual results;
|
|
•
|
both before and after the sale of NEG to APUC, the attention of management may be diverted to the closing of the sale of NEG rather than to current operations, the integration of MGE or the pursuit of other opportunities that could be beneficial to the Company;
|
|
•
|
the potential loss of key employees of the Company or of NEG who may be uncertain about their future roles if and when the NEG sale is completed; and
|
|
•
|
the trading price of Laclede Group’s common stock may decline to the extent that the current market price reflects a market assumption that the transaction will be completed.
|
The occurrence of any of these events individually or in combination could have a material adverse effect on the Company's business, financial condition or results of operations or the trading price of its common stock.
On August 13, 2013, the Utility issued debt in the aggregate principal amount of $450 million to provide permanent financing for the acquisition of MGE and, as a result, the Company is subject to risks related to a higher level of indebtedness.
In connection with the MGE acquisition, the Utility incurred additional debt to pay a portion of the acquisition cost and transaction expenses. The Utility's total indebtedness as of September 30, 2013 was $1,011 million (including $121 million of short-term borrowings and $890 million of long-term debt).
The Utility’s debt service obligations with respect to this increased indebtedness could have an adverse impact on its earnings and cash flows (which after the acquisition include the earnings and cash flows of MGE) for as long as the indebtedness is outstanding.
11
Among other risks, the increase in indebtedness may:
|
•
|
make it more difficult for Laclede Group to pay or refinance its debts as they become due during adverse economic and industry conditions;
|
|
•
|
limit the Company’s flexibility to pursue other strategic opportunities or react to changes in its business and the industry in which it operates and, consequently, place it at a competitive disadvantage to competitors with less debt;
|
|
•
|
require an increased portion of the Company’s cash flows from operations of Laclede Group and the Utility to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, dividend payments and other general corporate purposes;
|
|
•
|
result in a downgrade in the credit rating of Laclede Group’s or the Utility's indebtedness, which could limit their ability to borrow additional funds or increase the interest rates applicable to their indebtedness;
|
|
•
|
result in higher interest expense in the event of an increase in market interest rates for both long-term debt and short-term commercial paper or bank loans at variable rates;
|
|
•
|
reduce the amount of credit available to support hedging activities; and
|
|
•
|
require that additional terms, conditions or covenants be placed on the Company.
|
Based upon current levels of operations, the Utility expects to be able to generate sufficient cash through earnings on a consolidated basis or through refinancing to make all of the principal and interest payments when such payments are due under its existing credit agreements, indentures and other instruments governing its outstanding indebtedness; but there can be no assurance that the Utility will be able to repay or refinance such borrowings and obligations in future periods.
In addition, in order to maintain investment-grade credit ratings, Laclede Group may consider it appropriate to reduce the amount of indebtedness outstanding following the acquisitions. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders hold in the combined company, increase the Company’s dividend payment obligations and might reduce the reported earnings per share.
The acquisition of MGE and associated costs and integration efforts may adversely affect the Company's business, financial condition or results of operations, which may negatively affect the market price of Laclede Group's common shares.
While management currently anticipates that the acquisition of MGE will be accretive to the Utility's net economic earnings in fiscal year 2014, and thereafter, this expectation is based on preliminary estimates which may materially change. Laclede Group may encounter additional transaction and integration-related costs, may fail to realize all of the anticipated synergies and benefits of the acquisitions or be subject to other factors that affect those preliminary estimates.
The process of integrating the operations of MGE could cause an interruption of, or loss of momentum in, the activities of one or more of those businesses and the possible loss of key personnel. Integration could take longer than anticipated and could result in inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements. The diversion of management's attention and any delays or difficulties encountered in connection with the transaction and the integration of the companies' operations could have an adverse effect on the business, results of operations, financial condition or prospects of Laclede Group after the acquisitions are ultimately consummated.
The Company expects to incur costs associated with integrating the operations of the utilities, and management’s estimate of the costs and the operating performance after the transaction closes may vary significantly from actual results. In accordance with the Unanimous Stipulation and Agreement, the Utility may amortize and recover certain transition costs in future rate case proceedings subject to review of other parties’ and the Missouri Public Service Commission’s (MoPSC or Commission) approval of the Company’s quantification of such cost. Potential differences regarding these quantifications may impact the Company’s financial results. Additional unanticipated costs may be incurred in the integration of the businesses.
Any of these factors could cause a decrease in the price of Laclede Group's common shares.
The acquisition of MGE may not achieve its intended results, including anticipated synergies and cost savings.
Although we expect that the acquisition of MGE will result in various benefits, including a significant amount of synergies, cost savings and other financial and operational benefits, there can be no assurance regarding when or the extent to which we will be able to realize these synergies, cost savings or other benefits. Achieving the anticipated benefits, including synergies and cost savings, is subject to a number of uncertainties, including whether the assets acquired can be operated in the manner we intend. Events outside of our control, including but not limited to regulatory changes or developments, could also adversely affect our ability to realize the anticipated benefits from the MGE acquisition.
12
Thus the integration of MGE may be unpredictable, subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to integration, synergies or cost savings as a result of the MGE acquisition will materialize. In addition, our anticipated costs to achieve the integration of MGE may differ significantly from our current estimates. The integration may place an additional burden on our management and internal resources, and the diversion of management’s attention during the integration process could have an adverse effect on our business, financial condition and expected operating results.
We are dependent on ETE and SUG for certain transitional services for MGE to be provided pursuant to a continuing services agreement. The failure of ETE or SUG to perform its obligations under this agreement could adversely affect our business, financial results and financial condition.
We are initially dependent upon ETE and SUG to continue to provide certain shared services and business support functions in areas such as technology and human resources for a period of time after the close of the acquisition to facilitate the integration of MGE. The terms of these arrangements are governed by a continuing services agreement. If ETE or SUG fails to perform its obligations under the continuing services agreement, we may not be able to perform such services or obtain such services from third parties on favorable terms or at all. In addition, upon termination of the continuing services agreement, if we are unable to perform such services or obtain such services from third parties, it could adversely affect our business, financial results and financial condition.
In connection with the MGE acquisition, the Utility recorded goodwill and long-lived assets that could become impaired and adversely affect its financial condition and results of operations.
Laclede Group will assess goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company assesses its long-lived assets for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets becomes impaired, the Company may be required to incur impairment charges that could have a material impact on its results of operations. No impairment of long-lived assets was recorded during 2013.
Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of our reporting units, as interest rates rise, the calculated fair values decrease and future impairments may occur. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, Laclede Group cannot provide assurance that future analyses will not result in impairment. These assumptions and estimates include projected cash flows, current and future rates for contracted capacity, growth rates, weighted average cost of capital and market multiples. For additional information, see
Item 7
, “Critical Accounting Policies.”
RISKS THAT RELATE TO THE GAS UTILITY DISTRIBUTION SEGMENT
Regulation of the Utility business may impact rates it is able to charge, costs, and profitability.
The Missouri Public Service Commission (MoPSC or Commission) regulates many aspects of the Utility’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that the Utility may charge customers, the terms of service to its customers, transactions with its affiliates, and the rate of return that it is allowed to realize; as well as the accounting treatment for certain aspects of its operations. For further discussion of these accounting matters, see
Critical Accounting Policies
pertaining to the Utility operations, beginning on page
34
. The Utility's ability to obtain and timely implement rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion. There can be no assurance that it will be able to obtain rate increases or rate supplements or continue earning the current authorized rates of return. Furthermore, in accordance with the Unanimous Stipulation and Agreement, the Utility will not file a general rate case, other than the currently pending MGE rate case, for non-gas costs prior to October 1, 2015 unless a significant, unusual event impacts any of its operations. The first general rate case filed after October 1, 2015, requires that it be for both Laclede Gas and MGE.
The Utility could incur additional costs if required to adjust to new laws or regulations, revisions to existing laws or regulations or changes in interpretations of existing laws or regulations such as the Dodd-Frank Act. In addition, as the regulatory environment for the natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If the Utility fails to comply with applicable laws and regulations, whether existing or new, it could be subject to fines, penalties or other enforcement action by the authorities that regulate its operations.
13
The Utility is involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect our results of operations, cash flows and financial condition.
The Utility is involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require the Utility to make payments in excess of amounts provided for in our financial statements, or to the extent they are not covered by insurance, could adversely affect the Utility's results of operations, cash flows and financial condition.
The Utility's liquidity may be adversely affected by delays in recovery of its costs, due to regulation.
In the normal course of business, there may be a lag between when the Utility incurs increases in certain of its costs and the time in which those costs are considered for recovery in the ratemaking process. Cash requirements for increased operating costs, increased funding levels of defined benefit pension and postretirement costs, capital expenditures, and other increases in the costs of doing business may require outlays of cash prior to the authorization of increases in rates charged to customers, as approved by the MoPSC. Accordingly, the Utility’s liquidity may be adversely impacted to the extent higher costs are not timely recovered from its customers. In accordance with the Unanimous Stipulation and Agreement, the Utility will not file a general rate case for non-gas costs prior to October 1, 2015 unless a significant, unusual event impacts any of its operations. The first general rate case filed after October 1, 2015, is required to be for both Laclede Gas and MGE.
The Utility's ability to meet its customers’ natural gas requirements may be impaired if contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner.
In order to meet its customers’ annual and seasonal natural gas demands, the Utility must obtain sufficient supplies, interstate pipeline capacity, and storage capacity. If it is unable to obtain these, either from its suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, the Utility's financial condition and results of operations may be adversely impacted. If a substantial disruption in interstate natural gas pipelines’ transmission and storage capacity were to occur during periods of heavy demand, the Utility’s financial results could be adversely impacted.
The Utility's liquidity and, in certain circumstances, its results of operations may be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
Laclede Gas’ and MGE's tariff rate schedules contain Purchased Gas Adjustment (PGA) Clauses that permit it to file for rate adjustments to recover the cost of purchased gas. Changes in the cost of purchased gas are flowed through to customers and may affect uncollectible amounts and cash flows and can therefore impact the amount of capital resources. Currently, Laclede Gas and MGE are allowed to adjust the gas cost component of their rates up to four times each year. The Utility must make a mandatory gas cost adjustment at the beginning of the winter, in November, and during the next twelve months it may make up to three additional discretionary gas cost adjustments, so long as each of these adjustments is separated by at least two months.
The MoPSC typically approves the Utility’s PGA changes on an interim basis, subject to refund and the outcome of a subsequent audit and prudence review. Due to such review process, there is a risk of a disallowance of full recovery of these costs. Any material disallowance of purchased gas costs would adversely affect revenues. Increases in the prices the Utility charges for gas may also adversely affect revenues because they could lead customers to reduce usage and cause some customers to have trouble paying the resulting higher bills. These higher prices may increase bad debt expenses and ultimately reduce earnings. The Utility has used short-term borrowings in the past to finance storage inventories and purchased gas costs, and expects to do so in the future. Rapid increases in the price of purchased gas may result in an increase in short-term debt.
To lower financial exposure to commodity price fluctuations, the Utility enters into contracts to hedge the forward commodity price of its natural gas supplies. As part of this strategy, the Utility may use fixed-price, forward, physical purchase contracts, swaps, futures, and option contracts. However, the Utility does not hedge the entire exposure of energy assets or positions to market price volatility, and the coverage will vary over time. Any costs, gains, or losses experienced through hedging procedures, including carrying costs, generally flow through the PGA Clause, thereby limiting the Utility’s exposure to earnings volatility. However, variations in the timing of collections of such gas costs under the PGA Clause and the effect of cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments may cause short-term cash requirements to vary. These procedures remain subject to prudence review by the MoPSC.
14
The Utility may be adversely affected by economic conditions.
Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Utility's revenues and cash flows or restrict its future growth. Economic conditions in its service territory may also adversely impact the Utility’s ability to collect its accounts receivable resulting in an increase in bad debt expenses.
The Utility is dependent on bank lines of credit and continued access to capital markets to successfully execute its operating strategies.
In addition to longer-term debt that is issued by the Utility under its mortgage and deed of trust dated February 1, 1945, the Utility has relied, and continues to rely, upon shorter term borrowings or commercial paper supported by bank lines of credit to finance the execution of a portion of its operating strategies. The Utility is dependent on these capital sources to purchase its natural gas supply and maintain its properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to the Utility, or it may not be able to obtain funds at a reasonable cost in the future. the Utility's ability to borrow under its existing lines of credit depends on its compliance with the Utility’s obligations under the lines of credit. If the Utility were to breach any of the financial or other covenants under these agreements, its debt repayment obligations under them could be accelerated. The Utility's ability to issue commercial paper supported by its lines of credit, to issue long-term bonds, or to obtain new lines of credit also depends on current conditions in the credit markets. The Utility’s access to funds under committed short-term credit facilities, which are currently provided by a number of banks, is dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity. Disruptions in the bank or capital financing markets as a result of economic uncertainty, changing or increased regulation of the financial sector, or failure of major financial institutions could adversely affect the Utility’s access to capital and negatively impact its ability to run its business and make strategic investments.
A downgrade in the Utility’s credit rating may negatively affect its ability to access capital.
Standard & Poor’s, Moody’s Investors Service, and Fitch Ratings from time to time implement new requirements for various ratings levels. To maintain its current credit ratings in light of any new requirements, the Utility may find it necessary to take steps to change its business plans in ways that may affect its results of operations. The Utility’s credit ratings remain at investment grade, but are subject to review and change by the rating agencies. If the rating agencies lowered the Utility’s ratings, particularly below investment grade, it could significantly limit its ability to secure new or additional credit facilities and would increase its costs of borrowing. In addition, the Utility would likely be required to pay a higher interest rate in future long-term financings and the Utility’s potential pool of investors and funding sources would likely decrease. The Utility's ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on its ability to execute operating strategies.
Numerous environmental laws and regulations may require significant expenditures or increase operating costs.
The Utility is subject to federal, state and local environmental laws and regulations affecting many aspects of its present and future operations. These laws and regulations require the Utility to obtain and comply with a wide variety of environmental licenses, permits, inspections, and approvals. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may result in costs to the Utility in the form of fines, penalties or business interruptions, which may be material. In addition, existing environmental laws and regulations could be revised or reinterpreted and/or new laws and regulations could be adopted or become applicable to the Utility or its facilities, thereby impacting the Utility’s cost of compliance. The discovery of presently unknown environmental conditions, including former manufactured gas plant sites, and claims against the Utility under environmental laws and regulations may result in expenditures and liabilities, which could be material. To the extent environmental compliance costs are not fully covered by insurance or recovered in rates from the Utility’s customers, those costs may have an adverse effect on the Utility's financial condition and results of operations.
The Utility is subject to pipeline safety and system integrity laws and regulations that may require significant expenditures or significant increases in operating costs.
Such laws and regulations affect various aspects of the Utility's present and future operations. These laws and regulations require the Utility to maintain pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers in rates.
15
Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers in rates and could result in a material effect on the Utility's financial condition and results of operations.
Transporting, distributing, and storing natural gas and transporting and storing propane involves numerous risks that may result in accidents and other operating risks and costs.
There are inherent in gas distribution activities a variety of hazards and operations risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to the Utility. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. Similar risks also exist for the Utility's propane storage and transmission operations. These activities may subject the Utility to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties against the Utility or be resolved on unfavorable terms. In accordance with customary industry practices, the Utility maintains insurance against a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Utility’s financial condition and results of operations.
Changes in the wholesale costs of purchased natural gas supplies may adversely impact the Utility’s competitive position compared with alternative energy sources.
The Utility is the only distributor of natural gas within its franchised service area. Nevertheless, the changes in wholesale natural gas prices compared with prices for electricity, fuel oil, coal, propane, or other energy sources may affect the Utility’s retention of natural gas customers and adversely impact its financial condition and results of operations.
Significantly warmer-than-normal weather conditions, the effects of global warming and climate change, and other factors that influence customer usage may affect the Utility’s sale of heating energy and adversely impact its financial position and results of operations.
The Utility's earnings are primarily generated by the sale of heating energy. The Utility has weather mitigation rate designs, approved by the MoPSC, which provide better assurance of the recovery of the Utility’s fixed costs and margins during winter months despite variations in sales volumes due to the impacts of weather and other factors that affect customer usage.
However, significantly warmer-than-normal weather conditions in the Utility’s service area and other factors, such as global warming, climate change and alternative energy sources, may result in reduced profitability and decreased cash flows attributable to lower gas sales. Furthermore, continuation of the weather mitigation rate design at Laclede Gas or the straight fixed variable rate design at MGE are subject to regulatory discretion. In addition, the promulgation of regulations by the U.S. Environmental Protection Agency or the potential enactment of Congressional legislation addressing global warming and climate change may result in future additional compliance costs that could impact the Utility’s financial condition and results of operations.
Regional supply/demand fluctuations and changes in national pipeline infrastructure, as well as regulatory discretion, may adversely affect the Utility's ability to profit from off-system sales and capacity release.
The Utility's income from off-system sales and capacity release is subject to fluctuations in market conditions and changing supply and demand conditions in areas the Utility holds pipeline capacity rights. Specific factors impacting the Utility’s income from off-system sales and capacity release include the availability of attractively-priced natural gas supply, availability of pipeline capacity, and market demand. Income from off-system sales and capacity release is shared with customers. The Utility is allowed to retain 15% to 25% of the first $6 million in annual income earned (depending on the level of income earned) and 30% of income exceeding $6 million annually. In accordance with the MoPSC agreement to suspend the procedural schedule in Laclede Gas’ base rate proceeding, the Utility deferred, until fiscal year 2017, its ability to retain 15% of the first $2 million. MGE is allowed to retain 15% to 25% of the first $3.6 million in annual income earned (depending on the level of income earned) and 30% of income exceeding $3.6 million annually. The Utility’s ability to retain such income in the future is subject to regulatory discretion in a base rate proceeding.
16
Workforce risks may affect the Utility's financial results.
The Utility is subject to various workforce risks, including, but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.
Catastrophic events may adversely affect the Utility's facilities and operations.
Catastrophic events such as fires, earthquakes, explosions, floods, tornados, terrorist acts, or other similar occurrences could adversely affect the Utility's facilities and operations. The Utility has emergency planning and training programs in place to respond to events that could cause business interruptions. However, unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate response to events may have an adverse impact on the Utility’s operations, financial condition, and results of operations. The availability of insurance covering catastrophic events may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.
RISKS THAT RELATE TO THE GAS MARKETING SEGMENT
Increased competition, fluctuations in natural gas commodity prices, expiration of existing supply and transportation arrangements, and pipeline infrastructure projects may adversely impact LER’s future profitability.
Competition in the marketplace and fluctuations in natural gas commodity prices have a direct impact on LER’s business. Changing market conditions and prices, the narrowing of regional and seasonal price differentials, and limited future price volatility may adversely impact LER’s sales margins or affect LER’s ability to procure gas supplies and/or to serve certain customers, which may reduce sales profitability and/or increase certain credit requirements caused by reductions in netting capability. Also, LER’s profitability may be impacted by the effects of the expiration, in the normal course of business, of certain of its natural gas supply contracts if those contracts cannot be replaced and/or renewed with arrangements with similar terms and pricing. Although the FERC regulates the interstate transportation of natural gas and establishes the general terms and conditions under which LER may use interstate gas pipeline capacity to purchase and transport natural gas, LER must occasionally renegotiate its transportation agreements with a concentrated group of pipeline companies. Renegotiated terms of new agreements, or increases in FERC-authorized rates of existing agreements, may impact LER’s future profitability. Profitability may also be adversely impacted if pipeline capacity or future storage capacity secured by LER is not fully utilized and/or its costs are not fully recovered.
Reduced access to credit and/or capital markets may prevent LER from executing operating strategies.
LER relies on its cash flows, netting capability, parental guarantees, and access to Laclede Group’s liquidity resources to satisfy its credit and working capital requirements. LER’s ability to rely on parental guarantees is dependent upon Laclede Group’s financial condition and credit ratings. If the rating agencies lowered Laclede Group’s credit ratings, particularly below investment grade, counterparty acceptance of parental guarantees may diminish, resulting in decreased availability of credit. Additionally, under such circumstances, certain counterparties may require LER to provide prepayments or cash deposits, amounts of which would be dependent upon natural gas market conditions. Reduced access to credit or increased credit requirements, which may also be caused by factors such as higher overall natural gas prices, may limit LER’s ability to enter into certain transactions. In addition, LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk in certain individually significant counterparties. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations.
Risk management policies, including the use of derivative instruments, may not fully protect LER’s sales and results of operations from volatility and may result in financial losses.
In the course of its business, LER enters into contracts to purchase and sell natural gas at fixed prices and index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments.
17
LER currently manages the commodity price risk associated with fixed-price commitments for the purchase or sale of natural gas by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. These exchange-traded/cleared contracts may be designated as cash flow hedges of forecasted transactions. However, market conditions and regional price changes may cause ineffective portions of matched positions to result in financial losses. Additionally, to the extent that LER’s natural gas contracts are classified as trading activities or do not otherwise qualify for the normal purchases or normal sales designation (or the designation is not elected), the contracts are recorded as derivatives at fair value each period. Accordingly, the associated gains and losses are reported directly in earnings and may cause volatility in results of operations. Gains or losses (realized and unrealized) on certain wholesale purchase and sale contracts, consisting of those classified as trading activities, are required to be presented on a net basis (instead of a gross basis) in the statements of consolidated income. Such presentation could result in reductions to and/or volatility in the Company’s operating revenues.
LER’s ability to meet its customers’ natural gas requirements may be impaired if contracted gas supplies and interstate pipeline services are not available or delivered in a timely manner.
LER’s ability to deliver natural gas to its customers is contingent upon the ability of natural gas producers, other gas marketers, and interstate pipelines to fulfill their delivery obligations to LER under firm contracts. If these counterparties fail to perform, they have a contractual obligation to reimburse LER for any adverse consequences. LER will attempt to use such reimbursements to obtain the necessary supplies so that LER may fulfill its customer obligations. To the extent that it is unable to obtain the necessary supplies, LER’s financial position and results of operations may be adversely impacted.
Regulatory and legislative developments pertaining to the energy industry may adversely impact LER’s results of operations, financial condition and cash flows.
LER’s business is non-regulated in that the rates it charges its customers are not established by or subject to approval by any regulatory body. However, LER is subject to various laws and regulations affecting the energy industry. New regulatory and legislative actions may adversely impact LER’s results of operations, financial condition, and cash flows by potentially reducing customer growth opportunities and/or increasing the costs of doing business.
LER could incur additional costs to comply with new laws and regulations, such as the Dodd-Frank Act. In addition, as the regulatory environment for the natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If LER fails to comply with applicable laws and regulations, whether existing or new ones, it could be subject to fines, penalties or other enforcement action by the authorities that regulate its operations.
None.
The principal properties of the Utility consist of more than 30,000 miles of gas main and related service pipes, meters, and regulators. Other physical properties include regional service centers and related buildings. Extensive underground natural gas and propane storage facilities and equipment are located in an area in North St. Louis County extending under the Missouri River into St. Charles County. Substantially all of the Utility's utility plant is subject to the liens of its mortgage.
All of the properties of the Utility are held in fee, or by easement, or under lease agreements. The principal lease agreements include underground storage rights that are of in
definite duration, the downtown St. Louis office building and MGE's Kansas City, Missouri office building. The current lease on the downtown St. Louis office building extends through February 2015 with the option to renew for a term of five additional years. The current lease on MGE's Kansas City office lease extends through November 30, 2015 with the option to renew for four additional terms of five years each.
For further information on the Utility’s leases see
Note 16
, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.
Other properties of Laclede Group, including LER, do not constitute a significant portion of its properties.
18
For a description of environmental matters, see
Note 16
, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Group, see the
Regulatory and Other Matters
discussion in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on page
36
.
Laclede Group and its subsidiaries are involved in litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes the final outcome will not have a material effect on the consolidated financial position or results of operations reflected in the consolidated financial statements presented herein.
19
EXECUTIVE OFFICERS OF THE REGISTRANT
– Listed below are executive officers as defined by the SEC for Laclede Group. Their ages, at
September 30, 2013
, and positions are listed below along with their business experience during the past five years.
|
Name, Age, and Position with Company *
|
Appointed (1)
|
||
|
|
|
|
|
|
S. Sitherwood, Age 53
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
President and Chief Executive Officer
|
February 2012
|
|
|
|
President (2)
|
|
September 2011
|
|
|
|
|
|
|
|
Laclede Gas
|
|
|
|
|
Chairman of the Board and Chief Executive Officer (2)
|
October 2012
|
|
|
Chairman of the Board, Chief Executive Officer and President
|
February 2012
|
||
|
|
|
|
|
|
S. L. Lindsey, Age 47
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
Executive Vice President, Chief Operating Officer, Distribution Operations
|
October 2012
|
|
|
|
|
|
|
|
|
Laclede Gas
|
|
|
|
|
President (3)
|
October 2012
|
|
|
|
|
|
|
|
S. P. Rasche, Age 53
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
Senior Vice President, Chief Financial Officer
|
October 2013
|
|
|
Senior Vice President, Finance and Accounting
|
May 2012
|
||
|
|
|
|
|
|
|
Laclede Gas
|
|
|
|
|
Chief Financial Officer
|
May 2012
|
|
|
Vice President, Finance (4)
|
November 2009
|
||
|
M. C. Darrell, Age 55
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
Senior Vice President, General Counsel and Chief Compliance Officer
|
May 2012
|
|
|
|
General Counsel (5)
|
May 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
M. C. Kullman, Age 53
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
Senior Vice President, Chief Administrative Officer and Corporate Secretary
|
May 2012
|
|
|
|
Chief Governance Officer and Corporate Secretary
|
February 2004
|
|
|
|
|
|
|
|
|
Laclede Gas
|
|
|
|
|
Senior Vice President, Assistant Corporate Secretary
|
October 2013
|
|
|
|
Corporate Secretary
|
May 2012
|
|
|
Chief Governance Officer and Corporate Secretary
|
February 2004
|
||
20
|
M. R. Spotanski, Age 53
|
|
||
|
|
|
|
|
|
|
Laclede Group
|
|
|
|
|
Senior Vice President, Chief Integration and Innovation Officer (6)
|
May 2012
|
|
|
*
|
The information provided relates to the Company and its principal subsidiaries. Many of the executive officers have served or currently serve as officers or directors for other subsidiaries of the Company.
|
|
(1)
|
Officers of Laclede are normally reappointed at the Annual Meeting of the Board of Directors in January of each year.
|
|
(2)
|
Ms. Sitherwood served as President of Atlanta Gas Light Company, Chattanooga Gas Company, and Florida City Gas, all of which are subsidiaries of AGL Resources, Inc., from November 2004 to September 2011. During that time, she also served as Senior Vice President of Southern Operations for AGL Resources, Inc. From September 2011 to February 2012, Ms. Sitherwood served as President of The Laclede Group, Inc. and became its President and Chief Executive Officer effective February 1, 2012.
|
|
(3)
|
Mr. Lindsey served as Senior Vice President, Southern Operations of AGL Resources, Inc. and President of its Atlanta Gas Light, Chattanooga Gas and Florida City Gas subsidiaries since December 2011. He also served as Vice President and General Manager of Atlanta Gas Light and Chattanooga Gas from 2005 to 2011.
|
|
(4)
|
Mr. Rasche served as the Chief Financial Officer for TLCVision Corporation from 2004 to May 2009.
|
|
(5)
|
Mr. Darrell previously served as Senior Vice President and General Counsel of Laclede Gas Company since October 2007.
|
|
(6)
|
Mr. Spotanski previously served as Senior Vice President – Operations and Marketing of Laclede Gas Company since October 2007.
|
Mr. M. D. Waltermire, former Executive Vice President, Chief Financial Officer, retired from the Company and its subsidiaries effective October 1, 2013.
21
Laclede Group’s common stock trades on The New York Stock Exchange under the symbol “LG.” The high and the low sales price for the common stock for each quarter in the two most recent fiscal years are:
|
|
Fiscal 2013
|
Fiscal 2012
|
||||||||||
|
|
High
|
Low
|
High
|
Low
|
||||||||
|
1st Quarter
|
$
|
44.04
|
|
$
|
37.35
|
|
$
|
42.81
|
|
$
|
37.23
|
|
|
2nd Quarter
|
42.89
|
|
37.43
|
|
43.00
|
|
38.58
|
|
||||
|
3rd Quarter
|
48.50
|
|
41.83
|
|
40.39
|
|
36.53
|
|
||||
|
4th Quarter
|
47.84
|
|
42.84
|
|
43.47
|
|
39.63
|
|
||||
The number of holders of record as of
September 30, 2013
was 4,015.
Dividends declared on the common stock for the two most recent fiscal years were:
|
|
Fiscal 2013
|
Fiscal 2012
|
||||
|
1st Quarter
|
$
|
0.425
|
|
$
|
0.415
|
|
|
2nd Quarter
|
0.425
|
|
0.415
|
|
||
|
3rd Quarter
|
0.425
|
|
0.415
|
|
||
|
4th Quarter
|
0.425
|
|
0.415
|
|
||
For disclosures related to securities authorized for issuance under equity compensation plans, see
Item 12
, page
94
.
22
The Laclede Group, Inc.
|
|
Fiscal Years Ended September 30
|
||||||||||||||||||
|
(Thousands, Except Per Share Amounts)
|
2013
|
2012
|
2011
|
2010
|
2009
|
||||||||||||||
|
Income statement data
|
|
|
|
|
|
||||||||||||||
|
Operating Revenues:
|
|
|
|
|
|
||||||||||||||
|
Gas Utility
|
$
|
847,224
|
|
$
|
763,447
|
|
$
|
913,190
|
|
$
|
864,297
|
|
$
|
1,053,993
|
|
||||
|
Gas Marketing
|
165,146
|
|
358,145
|
|
669,375
|
|
858,782
|
|
836,865
|
|
|||||||||
|
Other
|
4,649
|
|
3,883
|
|
20,742
|
|
11,950
|
|
4,340
|
|
|||||||||
|
Total Operating Revenues
|
1,017,019
|
|
1,125,475
|
|
1,603,307
|
|
1,735,029
|
|
1,895,198
|
|
|||||||||
|
Operating Expenses:
|
|
|
|
|
|
||||||||||||||
|
Gas Utility
|
|
|
|
|
|
||||||||||||||
|
Natural and propane gas
|
433,442
|
|
397,304
|
|
549,947
|
|
519,905
|
|
699,984
|
|
|||||||||
|
Other operation and maintenance expenses
|
180,342
|
|
167,351
|
|
172,938
|
|
169,239
|
|
174,360
|
|
|||||||||
|
Depreciation and amortization
|
48,283
|
|
40,739
|
|
39,214
|
|
37,572
|
|
36,751
|
|
|||||||||
|
Taxes, other than income taxes
|
60,079
|
|
53,672
|
|
60,752
|
|
61,407
|
|
68,639
|
|
|||||||||
|
Total Gas Utility Operating Expenses
|
722,146
|
|
659,066
|
|
822,851
|
|
788,123
|
|
979,734
|
|
|||||||||
|
Gas Marketing
|
176,554
|
|
353,283
|
|
652,567
|
|
836,687
|
|
787,056
|
|
|||||||||
|
Other
|
21,825
|
|
2,524
|
|
9,642
|
|
5,353
|
|
3,344
|
|
|||||||||
|
Total Operating Expenses
|
920,525
|
|
1,014,873
|
|
1,485,060
|
|
1,630,163
|
|
1,770,134
|
|
|||||||||
|
Operating Income
|
96,494
|
|
110,602
|
|
118,247
|
|
104,866
|
|
125,064
|
|
|||||||||
|
Other Income and (Income Deductions) - Net
|
2,444
|
|
3,272
|
|
177
|
|
3,120
|
|
1,453
|
|
|||||||||
|
Interest Charges
|
28,602
|
|
24,945
|
|
25,417
|
|
26,852
|
|
29,746
|
|
|||||||||
|
Income Before Income Taxes and Dividends on Laclede Gas Redeemable Preferred Stock
|
70,336
|
|
88,929
|
|
93,007
|
|
81,134
|
|
96,771
|
|
|||||||||
|
Income Tax Expense
|
17,578
|
|
26,289
|
|
29,182
|
|
27,094
|
|
32,509
|
|
|||||||||
|
Dividends on Laclede Gas Redeemable Preferred Stock
|
—
|
|
—
|
|
—
|
|
—
|
|
15
|
|
|||||||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
$
|
54,040
|
|
$
|
64,247
|
|
||||
|
Common stock data
|
|||||||||||||||||||
|
Weighted Average No. of Common Shares Outstanding:
|
|
|
|
|
|
||||||||||||||
|
Basic
|
25,875
|
|
22,262
|
|
22,099
|
|
21,986
|
|
21,893
|
|
|||||||||
|
Diluted
|
25,952
|
|
22,340
|
|
22,171
|
|
22,039
|
|
21,960
|
|
|||||||||
|
Basic Earnings Per Share of Common Stock
|
$
|
2.03
|
|
$
|
2.80
|
|
$
|
2.87
|
|
$
|
2.43
|
|
$
|
2.90
|
|
||||
|
Diluted Earnings Per Share of Common Stock
|
$
|
2.02
|
|
$
|
2.79
|
|
$
|
2.86
|
|
$
|
2.43
|
|
$
|
2.89
|
|
||||
|
Dividends Declared Per Share of Common Stock
|
$
|
1.70
|
|
$
|
1.66
|
|
$
|
1.62
|
|
$
|
1.58
|
|
$
|
1.54
|
|
||||
|
Statements of financial position data
|
|||||||||||||||||||
|
Net Utility Plant
|
1,776,630
|
|
1,019,299
|
|
928,683
|
|
884,084
|
|
855,929
|
|
|||||||||
|
Other Property and Investments
|
313,078
|
|
56,814
|
|
55,373
|
|
54,777
|
|
49,034
|
|
|||||||||
|
Total Assets
|
3,125,386
|
|
1,880,262
|
|
1,783,082
|
|
1,840,196
|
|
1,762,018
|
|
|||||||||
|
Current Liabilities
|
353,178
|
|
252,124
|
|
231,934
|
|
333,924
|
|
299,140
|
|
|||||||||
|
Deferred Credits and Other Liabilities
|
813,214
|
|
687,111
|
|
613,460
|
|
606,397
|
|
556,608
|
|
|||||||||
|
Long-Term Debt (less current portion)
|
912,712
|
|
339,416
|
|
364,357
|
|
364,298
|
|
389,240
|
|
|||||||||
|
Cash flow data
|
|||||||||||||||||||
|
Net cash provided by operating activities
|
163,914
|
|
128,101
|
|
167,187
|
|
106,915
|
|
228,753
|
|
|||||||||
|
Net cash used in investing activities
|
(1,108,299
|
)
|
(105,404
|
)
|
(67,007
|
)
|
(60,773)
|
|
(52,254)
|
|
|||||||||
|
Net cash provided by (used in) financing activities
|
969,909
|
|
(38,517
|
)
|
(143,822
|
)
|
(33,814)
|
|
(116,807)
|
|
|||||||||
|
Consolidated Net Economic Earnings Data (a)
|
|||||||||||||||||||
|
Net Income (GAAP)
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
$
|
54,040
|
|
$
|
64,247
|
|
||||
|
Unrealized loss (gain) on energy-related derivatives
|
614
|
|
(314
|
)
|
(1,415
|
)
|
2,125
|
|
(3,441
|
)
|
|||||||||
|
Lower of cost or market inventory adjustments
|
868
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Realized (gain) loss on economic hedges prior to the sale of the physical commodity
|
(25
|
)
|
163
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Acquisition, divestiture and restructuring activities
|
10,797
|
|
123
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Net Economic Earnings (Non-GAAP)
|
$
|
65,012
|
|
$
|
62,612
|
|
$
|
62,410
|
|
$
|
56,165
|
|
$
|
60,806
|
|
||||
|
Diluted Earnings per Share of Common Stock:
|
|||||||||||||||||||
|
Net Income (GAAP)
|
$
|
2.02
|
|
$
|
2.79
|
|
$
|
2.86
|
|
$
|
2.43
|
|
$
|
2.89
|
|
||||
|
Unrealized loss (gain) on energy-related derivatives
|
0.02
|
|
(0.02
|
)
|
(0.07
|
)
|
0.09
|
|
(0.15
|
)
|
|||||||||
|
Lower of cost or market inventory adjustments
|
0.03
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Realized loss on economic hedges prior to the sale of the physical commodity
|
—
|
|
0.01
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Acquisition, divestiture and restructuring activities
|
0.42
|
|
0.01
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Weighted Average Shares Adjustment
|
0.38
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Net Economic Earnings (Non-GAAP)
|
$
|
2.87
|
|
$
|
2.79
|
|
$
|
2.79
|
|
$
|
2.52
|
|
$
|
2.74
|
|
||||
23
|
(a)
|
This section contains the non-GAAP financial measures of net economic earnings and net economic earnings per share. Refer to the
Earnings
section of Management’s Discussion and Analysis of Financial Condition and Results of Operations on page
28
for a discussion regarding the use of non-GAAP measures.
|
24
THE LACLEDE GROUP, INC.
INTRODUCTION
This section analyzes the financial condition and results of operations of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. It includes management’s view of factors that affect its business, explanations of past financial results including changes in earnings and costs from the prior year periods, and their effects on the Company’s overall financial condition and liquidity.
The Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s consolidated financial statements and the notes thereto.
RESULTS OF OPERATIONS
Overview
Laclede Group’s earnings are primarily derived from its Gas Utility segment, which reflects the regulated activities of Laclede Gas Company (the Utility), Missouri’s largest natural gas distribution company. The Utility is regulated by the Missouri Public Service Commission (MoPSC) and serves the City of St. Louis and eastern Missouri through Laclede Gas and Kansas City and western Missouri through Missouri Gas Energy (MGE). The Utility delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The Utility’s earnings are primarily generated by the sale of heating energy. The Utility’s weather mitigation rate design and MGE's straight fixed variable rate design lessen the impact of weather volatility on its customers during cold winters and stabilizes the Utility’s earnings by recovering fixed costs more evenly during the heating season. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated in the November through April period, which generally corresponds with the heating season.
On December 14, 2012, Laclede Group, through two wholly owned subsidiaries, Plaza Missouri Acquisition, Inc. (Plaza Missouri) and Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts), entered into acquisition agreements to acquire from Southern Union Company (SUG) substantially all of the assets and liabilities of MGE and New England Gas Company (NEG). Subsequently, on January 11, 2013, the Company and Plaza Missouri, with consent of SUG, entered into an agreement with the Utility to assign the MGE agreement to the Utility. On February 11, 2013, the Company entered into an agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary, through its acquisition of the stock of Plaza Massachusetts, to acquire the Company's rights to purchase the assets of NEG, subject to certain approvals and conditions. In order to close the NEG transaction, approval by the Massachusetts Department of Public Utilities (MDPU) of the acquisition of the assets of NEG by the APUC subsidiary must be received.
On July 2, 2013, the Utility and other parties to the case filed a Unanimous Stipulation and Agreement with the MoPSC that authorized the Utility to complete the acquisition of MGE, subject to certain conditions, including restrictions relative to the timing of filing for general rate increases and reporting requirements. This Unanimous Stipulation and Agreement was approved by the MoPSC on July 17, 2013. Effective September 1, 2013, the Utility closed on the purchase of MGE assets and liabilities.
The sale of NEG to APUC is still pending before the MDPU. The acquisition agreement contains certain termination rights for both the Company and SUG, including, among others, the right to terminate if the transaction is not completed by October 14, 2013 (subject to up to four 30-day extensions under certain circumstances related to obtaining required regulatory approvals). The Company and SUG agreed to extend the NEG purchase agreement until December 14, 2013 to enable the MDPU to complete its review process. Nonetheless, there can be no assurance that APUC will be able to satisfy all of the required conditions on or before the end of the extension periods. The Company's agreement to acquire NEG remains in effect if APUC cannot satisfy the conditions for closing before the expiration of the extension periods.
Laclede Energy Resources, Inc. (LER) is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas to both on-system utility transportation customers and customers outside of the Utility’s traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LER entered into a new 10 year contract for 1 Bcf of natural gas storage effective August 1, 2013 and has an additional 1 Bcf storage contracted through January 2014.
25
On July 3, 2013, the Company announced that Mark D. Waltermire, Laclede Group's Executive Vice President and Chief Financial Officer, would retire effective October 1, 2013, after the end of the current fiscal year. On July 9, 2013, the Company announced that the board of directors named Steven P. Rasche, Senior Vice President of Finance and Accounting, as Laclede Group's Senior Vice President and Chief Financial Officer effective October 1, 2013.
Based on the nature of the business of the Company and its subsidiaries, as well as current economic conditions, management focuses on the following key variables in evaluating the financial condition and results of operations and managing the business:
Gas Utility Segment:
|
•
|
the Utility’s ability to recover the costs of purchasing and distributing natural gas from its customers;
|
|
•
|
the impact of weather and other factors, such as customer conservation, on revenues and expenses;
|
|
•
|
changes in the regulatory environment at the federal, state, and local levels, as well as decisions by regulators, that impact the Utility’s ability to earn its authorized rate of return in all service territories it serves;
|
|
•
|
the Utility’s ability to access credit markets and maintain working capital sufficient to meet operating requirements;
|
|
•
|
the effect of natural gas price volatility on the business; and,
|
|
•
|
the ability to integrate the operations of all acquisitions.
|
Gas Marketing Segment:
|
•
|
the risks of competition;
|
|
•
|
fluctuations in natural gas prices;
|
|
•
|
new national pipeline infrastructure projects;
|
|
•
|
the ability to procure firm transportation and storage services at reasonable rates;
|
|
•
|
credit and/or capital market access;
|
|
•
|
counterparty risks; and,
|
|
•
|
the effect of natural gas price volatility on the business.
|
Further information regarding how management seeks to manage these key variables is discussed below.
The Utility provides reliable natural gas service at a reasonable cost, while maintaining and building a secure and dependable infrastructure. The Utility’s strategy focuses on improving both performance and the ability to recover its authorized distribution costs and rate of return. The Utility’s distribution costs are the essential, primarily fixed, expenditures it must incur to operate and maintain more than 30,000 miles of mains and services comprising its natural gas distribution system and related storage facilities. The Utility’s distribution costs include wages and employee benefit costs, depreciation and maintenance expenses, and other regulated utility operating expenses, excluding natural and propane gas expense. Distribution costs are considered in the ratemaking process, and recovery of these types of costs is included in revenues generated through the Utility’s tariff rates, as approved by the MoPSC.
The Utility’s income from off-system sales and capacity release remains subject to fluctuations in market conditions. The Utility is allowed to retain the following annual income (shown by legacy company):
|
Laclede Gas
|
||
|
Pre-tax Income
|
Customer Share
|
Company Share
|
|
First $2 million
|
100%
|
—%
|
|
Next $2 million
|
80%
|
20%
|
|
Next $2 million
|
75%
|
25%
|
|
Amounts exceeding $6 million
|
70%
|
30%
|
|
MGE
|
||
|
Pre-tax Income
|
Customer Share
|
Company Share
|
|
First $1.2 million
|
85%
|
15%
|
|
Next $1.2 million
|
80%
|
20%
|
|
Next $1.2 million
|
75%
|
25%
|
|
Amounts exceeding $3.6 million
|
70%
|
30%
|
26
Some of the factors impacting the level of off-system sales include the availability and cost of the Utility’s natural gas supply, the weather in its service area, and the weather in other markets. When the Utility’s service area experiences warmer-than-normal weather while other markets experience colder weather or supply constraints, some of the Utility’s natural gas supply is available for off-system sales. See the
Regulatory and Other Matters
section on page 36 of this report for additional information on Laclede Gas' off-system sales.
The Utility works actively to reduce the impact of wholesale natural gas price volatility on its costs by strategically structuring its natural gas supply portfolio to increase its gas supply availability and pricing alternatives and through the use of derivative instruments to protect its customers from significant changes in the commodity price of natural gas. Nevertheless, the overall cost of purchased gas remains subject to fluctuations in market conditions. The Utility’s Purchased Gas Adjustment (PGA) Clause allows the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of derivative instruments to hedge the purchase price of natural gas, as well as gas inventory carrying costs. The Utility believes it will continue to be able to obtain sufficient gas supply. The price of natural gas supplies and other economic conditions may affect sales volumes, due to the conservation efforts of customers, and cash flows associated with the timing of collection of gas costs and related accounts receivable from customers.
The Utility relies on both short-term credit and long-term capital markets, as well as cash flows from operations, to satisfy its seasonal cash requirements and fund its capital expenditures. The Utility's ability to issue commercial paper supported by lines of credit, to issue long-term bonds, or to obtain new lines of credit is dependent on current conditions in the credit and capital markets. Management focuses on maintaining a strong balance sheet and believes it currently has adequate access to credit and capital markets and will have sufficient capital resources to meet its foreseeable obligations. See the
Liquidity and Capital Resources
section on page 39 for additional information.
LER provides both on-system Utility transportation customers and customers outside of the Utility's traditional service area with another choice in non-regulated natural gas suppliers. LER utilizes its natural gas supply agreements, transportation agreements, park and loan agreements, storage agreements, and other executory contracts to support a variety of services to its customers at competitive prices. It closely monitors and manages the natural gas commodity price and volatility risks associated with providing such services to its customers through the use of a variety of risk management activities, including the use of exchange-traded/cleared derivative instruments and other contractual arrangements. LER is committed to managing commodity price risk, while it seeks to expand the services that it now provides. Nevertheless, income from LER’s operations is more subject to fluctuations in market conditions than the Utility’s operations. LER’s business is directly impacted by the effects of competition in the marketplace, the impacts of new pipeline infrastructure and surplus natural gas supplies on natural gas commodity prices. Management expects that LER's net economic earnings (a non-GAAP measure, as discussed below) will continue to be negatively impacted by the expiration of favorable long-term natural gas supply contracts with the last such contract expiring on September 30, 2013.
In addition to its operating cash flows, LER relies on Laclede Group’s parental guarantees to secure its purchase and sales obligations of natural gas. LER also has access to Laclede Group’s liquidity resources. A large portion of LER’s receivables are from customers in the energy industry. LER also enters into netting arrangements with many of its energy counterparties to reduce overall credit and collateral exposure. Although LER’s uncollectible amounts are closely monitored and have not been significant, increases in uncollectible amounts from customers are possible and could adversely affect LER’s liquidity and results.
LER carefully monitors the creditworthiness of counterparties to its transactions. LER performs in-house credit reviews of potential customers and may require credit assurances such as prepayments, letters of credit, or parental guarantees when appropriate. Credit limits for customers are established and monitored.
As a result of new pipeline infrastructure, and an abundance of natural gas supply, regional price differences have narrowed resulting in reduced price volatility. This reduction in regional price differentials presents an opportunity for LER in its transportation capacity to enter into subsequent offsetting purchase or sale transactions at the same location. These arrangements allow LER to satisfy its commitments without incurring fuel costs to transport natural gas to a different location. Thus, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically. As such, certain transactions entered into in fiscal year 2013 are designated as trading activities for financial reporting purposes, due to their settlement characteristics, rather than elected for normal purchases or normal sales designations under generally accepted accounting principles (GAAP). Results of operations from trading activities are reported on a net basis in Gas Marketing Operating Revenues, which may cause reductions in and/or volatility in the Company’s operating revenues, but has no effect on operating income or net income.
27
In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. In accordance with GAAP, some of LER’s purchase and sale transactions are not recognized in earnings until the natural gas is physically delivered, while other energy-related transactions, including those designated as trading activities, are required to be accounted for as derivatives, with the changes in their fair value (representing unrealized gains or losses) recorded in earnings in periods prior to settlement. Because related transactions of a purchase and sale strategy may be accounted for differently, there may be timing differences in the recognition of earnings under GAAP and economic earnings realized upon settlement. The Company reports both GAAP and net economic earnings (non-GAAP), as discussed below.
EARNINGS
The Laclede Group reports net income and earnings per share determined in accordance with GAAP. Management also uses the non-GAAP measures of net economic earnings and net economic earnings per share when internally evaluating results of operations. These non-GAAP measures exclude from net income the after-tax impacts of fair value accounting and timing adjustments associated with energy-related transactions as well as acquisition, divestiture, and restructuring activities. These adjustments include timing differences where the accounting treatment differs from the economic substance of the underlying transaction, including the following:
|
•
|
Net unrealized gains and losses on energy-related derivatives that are required by GAAP fair value accounting associated with current changes in the fair value of financial and physical transactions prior to their completion and settlement. These unrealized gains and losses result primarily from two sources:
|
|
1)
|
changes in the fair values of physical and/or financial derivatives prior to the period of settlement; and,
|
|
2)
|
ineffective portions of accounting hedges, required to be recorded in earnings prior to settlement, due to differences in commodity price changes between the locations of the forecasted physical purchase or sale transactions and the locations of the underlying hedge instruments;
|
|
•
|
Lower of cost or market adjustments to the carrying value of commodity inventories resulting when the market price of the commodity falls below its original cost, to the extent that those commodities are economically hedged; and,
|
|
•
|
Realized gains and losses resulting from the settlement of economic hedges prior to the sale of the physical commodity.
|
|
•
|
Acquisition, divestiture, and restructuring activities, when evaluating on-going performance
|
These adjustments eliminate the impact of timing differences and the impact of current changes in the fair value of financial and physical transactions prior to their completion and settlement. Unrealized gains or losses are recorded in each period until being replaced with the actual gains or losses realized when the associated physical transaction(s) occur. While management uses these non-GAAP measures to evaluate both the Utility and LER, the net effect of adjustments on the Utility’s earnings is minimal because gains or losses on its natural gas derivative instruments are deferred pursuant to its PGA Clause, as authorized by the MoPSC.
Management believes that excluding the earnings volatility caused by recognizing changes in fair value prior to settlement and other timing differences associated with related purchase and sale transactions provides a useful representation of the economic effects of only the actual settled transactions and their effects on results of operations. When calculating net economic earnings per share, management excludes from the weighted average number of shares the impact of the May 2013 equity issuance, completed relating to the MGE acquisition. Management believes that this presentation provides a useful representation of operating performance by facilitating comparisons of year-over-year results. These internal non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income. Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided below.
28
Overview – Net Income (Loss)
|
(Millions, except per share amounts)
|
Gas Utility
|
Gas Marketing
|
Other
|
Consolidated
|
Per Share Amounts**
|
||||||||||||||
|
Year Ended September 30, 2013
|
|
|
|
|
|
||||||||||||||
|
|
Net Income (Loss) (GAAP)
|
$
|
56.3
|
|
$
|
7.6
|
|
$
|
(11.1
|
)
|
$
|
52.8
|
|
2.02
|
|
||||
|
|
Unrealized loss on energy-related derivatives*
|
0.1
|
|
0.4
|
|
—
|
|
0.5
|
|
0.02
|
|
||||||||
|
|
Lower of cost or market inventory adjustments*
|
—
|
|
0.9
|
|
—
|
|
0.9
|
|
0.03
|
|
||||||||
|
Acquisition, divestiture and restructuring activities*
|
0.3
|
|
—
|
|
10.5
|
|
10.8
|
|
0.42
|
|
|||||||||
|
Weighted Average Shares Adjustment**
|
|
|
|
|
|
|
|
|
0.38
|
|
|||||||||
|
|
Net Economic Earnings (Losses) (Non-GAAP)
|
$
|
56.7
|
|
$
|
8.9
|
|
$
|
(0.6
|
)
|
$
|
65.0
|
|
2.87
|
|
||||
|
Year Ended September 30, 2012
|
|||||||||||||||||||
|
|
Net Income (GAAP)
|
$
|
48.2
|
|
$
|
12.3
|
|
$
|
2.1
|
|
$
|
62.6
|
|
2.79
|
|
||||
|
|
Unrealized gain on energy-related derivatives*
|
(0.1
|
)
|
(0.2
|
)
|
—
|
|
(0.3
|
)
|
(0.02
|
)
|
||||||||
|
|
Realized gain on economic hedges prior
to the sale of the physical commodity*
|
—
|
|
0.2
|
|
—
|
|
0.2
|
|
0.01
|
|
||||||||
|
Acquisition, divestiture and restructuring activities*
|
—
|
|
—
|
|
0.1
|
|
0.1
|
|
0.01
|
|
|||||||||
|
|
Net Economic Earnings (Non-GAAP)
|
$
|
48.1
|
|
$
|
12.3
|
|
$
|
2.2
|
|
$
|
62.6
|
|
2.79
|
|
||||
|
Year Ended September 30, 2011
|
|||||||||||||||||||
|
Net Income (GAAP)
|
46.9
|
|
10.4
|
|
6.5
|
|
63.8
|
|
2.86
|
|
|||||||||
|
Unrealized gain on energy-related derivatives*
|
—
|
|
(1.4
|
)
|
—
|
|
(1.4
|
)
|
(0.07
|
)
|
|||||||||
|
Net Economic Earnings (Non-GAAP)
|
46.9
|
|
9.0
|
|
6.5
|
|
62.4
|
|
2.79
|
|
|||||||||
|
*
|
Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the fiscal years ended
2013
,
2012
, and
2011
the net income tax effect included in the reconciling items above was $7.5 million, $0.0 million, and $0.9 million, respectively.
|
|
**
|
Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings (losses) in the GAAP diluted earnings per share calculation. Also, net economic earnings per share exclude the impact of the May 2013 equity offering to fund the pending acquisition of MGE. The weighted-average diluted shares used in the net economic earnings per share calculation for the fiscal year ended
September 30, 2013
was 22.5 million compared to 26.0 million in the GAAP EPS calculation.
|
2013 vs. 2012
Consolidated
Laclede Group’s net income was
$52.8 million
in fiscal year
2013
, including net income of $1.8 million related to MGE, compared with
$62.6 million
in fiscal year
2012
. Basic and diluted earnings per share were $2.03 and $2.02 respectively for fiscal year 2013 compared with basic and diluted earnings per share of $2.80 and $2.79 respectively for fiscal year 2012. Net economic earnings were
$65.0 million
in fiscal year
2013
, compared with
$62.6 million
in fiscal year
2012
. Net economic earnings per share were $2.87 in fiscal year 2013, compared with $2.79 for fiscal year 2012. Earnings decreased in fiscal year 2013 compared to fiscal year 2012 primarily due to acquisition costs incurred during the period recorded in Other partially offset by higher income reported by Gas Utility. Additionally, earnings were impacted by decreased income from the Gas Marketing Segment. The increase is primarily attributed to acquisition related items that are excluded from net economic earnings.
29
Gas Utility
Gas Utility net income and net economic earnings increased by $8.1 million and $8.6 million, respectively, in 2013, compared with 2012. Of the $8.1 million increase in net income, $1.8 million is attributed to the acquisition of MGE. The remaining increase was primarily due to (on a pre-tax basis) higher operating margin (a non-GAAP measure, as discussed below) of $18.9 million. These benefits were partially offset by higher depreciation and amortization expenses totaling $5.0 million, higher operation and maintenance expenses totaling $4.0 million, and higher interest expense totaling $1.0 million.
Gas Marketing
Gas Marketing reported GAAP earnings totaling $7.6 million, a decrease of $4.7 million compared with the same period last year. Net economic earnings for fiscal year 2013 decreased $3.4 million from fiscal year 2012. The decreases in net income and net economic earnings was primarily attributable to decreases in operating margin, as discussed below. On a GAAP basis, LER's results were further impacted by the effect of higher net unrealized losses from certain of LER's energy-related derivative contracts and the impact of lower of cost or market inventory adjustments.
Other
Other net income and other net economic earnings decreased $13.2 million and $2.8 million, respectively, compared with the same period last year. The decrease in net income is primarily due to incremental expenses in fiscal year 2013 as compared to fiscal year 2012 attributable to the acquisition of MGE and pending acquisition of NEG from SUG totaling $10.5 million, net of tax, and other minor variations.
Operating Revenues and Operating Expenses
In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utility passes on (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause to their customers. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on operating income. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.
30
|
(Millions)
|
Gas Utility
|
Gas Marketing
|
Other
|
Eliminations
|
Consolidated
|
|||||||||||
|
Year Ended September 30, 2013
|
|
|
|
|
||||||||||||
|
|
Operating Revenues
|
$
|
857.8
|
|
$
|
189.4
|
|
$
|
6.2
|
|
$
|
(36.4
|
)
|
$
|
1,017.0
|
|
|
|
Natural and propane gas expense
|
469.1
|
|
171.6
|
|
1.3
|
|
(35.8
|
)
|
606.2
|
|
|||||
|
Gross receipts tax expense
|
40.2
|
|
0.1
|
|
—
|
|
—
|
|
40.3
|
|
||||||
|
|
Operating margin (non-GAAP)
|
348.5
|
|
17.7
|
|
4.9
|
|
(0.6
|
)
|
370.5
|
|
|||||
|
Remaining operating expenses
|
248.9
|
|
4.9
|
|
20.8
|
|
(0.6
|
)
|
274.0
|
|
||||||
|
|
Operating income (GAAP)
|
$
|
99.6
|
|
$
|
12.8
|
|
$
|
(15.9
|
)
|
$
|
—
|
|
$
|
96.5
|
|
|
Year Ended September 30, 2012
|
|
|
|
|
|
|
|
|
||||||||
|
|
Operating revenues
|
$
|
764.7
|
|
$
|
373.5
|
|
$
|
4.9
|
|
$
|
(17.6
|
)
|
$
|
1,125.5
|
|
|
|
Natural and propane gas expense
|
414.8
|
|
348.4
|
|
—
|
|
(17.6
|
)
|
745.6
|
|
|||||
|
|
Gross receipts tax expense
|
35.5
|
|
0.1
|
|
—
|
|
—
|
|
35.6
|
|
|||||
|
Operating margin (non-GAAP)
|
314.4
|
|
25.0
|
|
4.9
|
|
—
|
|
344.3
|
|
||||||
|
Remaining operating expenses
|
226.3
|
|
4.8
|
|
2.6
|
|
—
|
|
233.7
|
|
||||||
|
|
Operating income (GAAP)
|
$
|
88.1
|
|
$
|
20.2
|
|
$
|
2.3
|
|
$
|
—
|
|
$
|
110.6
|
|
|
Year Ended September 30, 2011
|
|
|
|
|
|
|
|
|
||||||||
|
|
Operating revenues
|
$
|
913.2
|
|
$
|
669.4
|
|
$
|
20.7
|
|
$
|
—
|
|
$
|
1,603.3
|
|
|
|
Natural and propane gas expense
|
549.9
|
|
647.5
|
|
—
|
|
—
|
|
1,197.4
|
|
|||||
|
|
Gross receipts tax expense
|
42.9
|
|
0.1
|
|
—
|
|
—
|
|
43.0
|
|
|||||
|
Operating margin (non-GAAP)
|
320.4
|
|
21.8
|
|
20.7
|
|
—
|
|
362.9
|
|
||||||
|
Remaining operating expenses
|
230.1
|
|
5.0
|
|
9.6
|
|
—
|
|
244.7
|
|
||||||
|
|
Operating income (GAAP)
|
$
|
90.3
|
|
$
|
16.8
|
|
$
|
11.1
|
|
$
|
—
|
|
$
|
118.2
|
|
Consolidated
Laclede Group reported operating revenues of
$1,017.0 million
for the fiscal year ended
September 30, 2013
compared with
$1,125.5 million
for the same period last year. Laclede Group's operating margin increased $26.2 million for the twelve months ended
September 30, 2013
, compared to the same period last year primarily due, to higher Gas Utility operating margin, partially offset by lower operating margin reported by Gas Marketing as discussed below. Remaining operating expenses were
$274.0 million
for the twelve months end
September 30, 2013
, compared with
$233.7 million
last year. The increase was primarily due to additional expenses related to MGE, as well as, higher depreciation and amortization expenses totaling $5.0 million and higher operation and maintenance expenses totaling $4.0 million.
Gas Utility
Operating Revenues
-
Gas Utility Operating Revenues for fiscal year 2013 increased $93.1 million, compared to fiscal year 2012, was primarily attributable to the following factors:
|
(Millions)
|
|
||
|
Higher system sales volumes and other variations
|
$
|
101.3
|
|
|
Lower wholesale gas costs passed on to Utility customers
|
(30.6
|
)
|
|
|
Lower off-system sales volumes
|
(24.0
|
)
|
|
|
Higher prices charged for off-system sales
|
19.9
|
|
|
|
New customer revenue from MGE acquisition
|
22.0
|
|
|
|
Higher ISRS revenues
|
4.5
|
|
|
|
Total Variation
|
$
|
93.1
|
|
31
Temperatures experienced in the Utility’s service area during 2013 were 35.8% colder than the same period last year, which were the warmest on record. Total system therms sold and transported to the Utility’s customers within its service territory were 875.4 million for fiscal year 2013 compared with 718.0 million for fiscal year 2012. Total off-system therms sold and transported outside of the Utility’s service area were 229.4 million for fiscal year 2013 compared with 314.5 million for fiscal year 2012.
Operating Margin
- Gas Utility operating margin was $
348.5 million
for fiscal year 2013, a $34.1 million increase over the same period last year. Of the $34.1 million increase, $15.2 million is attributed to the acquisition of MGE. The remaining increase is primarily due to increased sales margins reflecting colder weather this year totaling $13.3 million, higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $4.5 million, and other minor variations of $1.1 million.
Operating Expenses
-
Remaining operating expenses in fiscal year 2013 increased $22.6 million from fiscal year 2012. Other operation and maintenance expenses increased $4.0 million primarily due to increased compensation and benefits, maintenance, IT and professional fees, partially offset by a lower provision for uncollectible accounts and a decrease in customer accounts expenses. Depreciation and amortization expense increased $5.0 million primarily due to additional depreciable property. Taxes, other than income and gross receipts tax, increased $1.0 million primarily due to higher payroll taxes related to aforementioned employee expenses. The remaining increase is attributed to the acquisition of MGE.
Gas Marketing
Operating Revenues -
Gas Marketing operating revenues decreased $184.1 million primarily due to the effect of recording certain transactions on a net basis, instead of a gross basis, partially offset by higher per unit gas prices and increases in volumes purchased and sold.
Operating Margin
- Gas Marketing operating margin was $17.7 million for fiscal year 2013, a $7.3 million decrease compared to the same period last year. The decrease in operating margin was primarily attributable to low price volatility and basis differentials in the current natural gas market, the expiration of a favorable supply contract, and lower of cost or market inventory adjustments. These factors were partially offset by the effect of higher volumes purchased and sold.
Other
Operating Revenue and Operating Expenses
-
Other operating revenue increased $1.3 million primarily due to the sale of propane inventory by Laclede Pipeline totaling $1.7 million in fiscal year 2013. Other operating expenses increased $19.5 million primarily due to the acquisition-related expenses discussed above and expenses associated with the propane sale.
Interest Charges
Interest charges during fiscal year 2013 increased $3.7 million from fiscal year 2012 primarily due to expenses associated with the Company's bridge loan facility and higher interest from the issuance of long-term debt, partially offset by a reduction in interest charges related to the recognition of previously unrecognized tax benefits. The higher interest on long-term debt reflects the net effect of the December 2012, March 2013, and August 2013 issuances of additional long-term debt of $25 million, $100 million, and $450 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for both fiscal years 2013 and 2012. Average short-term borrowings were $34.2 million and $43.8 million for fiscal years 2013 and 2012, respectively.
Income Taxes
Income tax expense decreased $8.7 million in fiscal year 2013 from fiscal year 2012 primarily due to lower pre-tax income, various property-related deductions and other minor variations.
2012 vs. 2011
Consolidated
Laclede Group’s net income was
$62.6 million
in fiscal year
2012
compared with $
63.8 million
in fiscal year
2011
. Basic and diluted earnings per share were $2.80 and $2.79, respectively for fiscal year 2012 compared with basic and diluted earnings per share of $2.87 and $2.86, respectively, for fiscal year 2011. Net economic earnings were
$62.6 million
for fiscal year 2012, compared with
62.4 million
for fiscal year 2011. Net economic earnings per share were $2.79 for both fiscal years 2012 and 2011.
32
Earnings decreased in fiscal year 2012 compared with fiscal year 2011 primarily due to the $6.1 million effect of an April 2011 non-regulated sale of propane inventory recorded in Other Operating income, partially offset by higher income reported by Laclede Group’s Gas Utility and Gas Marketing segments.
Gas Utility
Gas Utility net income and net economic earnings increased by $1.3 million and $1.2 million, respectively, in 2012, compared with 2011. The increase was primarily due to (on a pre-tax basis) lower operating margin (a non-GAAP measure, as discussed above) of $6.0 million and a decrease in operation and maintenance expenses, excluding pension and group insurance expenses, totaling $11.1 million These benefits were partially offset by higher pension and group insurance expenses totaling $5.5 million.
Gas Marketing
The Gas Marketing segment reported GAAP earnings totaling $12.3 million for fiscal 2012, an increase of $1.9 million compared with fiscal year 2011. Net economic earnings for fiscal year 2012 increased $3.3 million compared with fiscal year 2011. The increases in net income and net economic earnings was primarily attributable to LER's reduced transportation costs resulting from the renegotiation of contracts that were renewed during the latter halves of fiscal years 2011 and 2012. Increased transaction volume and LER's ability to procure gas supply at more favorable terms were largely offset by the effects of narrower regional price differences and reduced price volatility.
Other
Other net income and other net economic earnings decreased $4.4 million and $4.3 million, respectively, compared with the same period last year. The decrease was primarily due to the effect of Laclede Gas' April 2011 sale of 320,000 barrels of propane from inventory that were no longer required to serve utility customers. This transaction resulted in income, net of income taxes, totaling $6.1 million.
Operating Revenues and Operating Expenses
Gas Utility
Operating Revenues
-
Utility Operating Revenues for fiscal year 2012 decreased $148.5 million, compared to fiscal year 2011, primarily attributable to the following factors:
|
(Millions)
|
|
||
|
Lower system sales volumes and other variations
|
$
|
(114.5
|
)
|
|
Lower prices charged for off-system sales
|
(44.6
|
)
|
|
|
Higher off-system sales volumes
|
38.8
|
|
|
|
Lower wholesale gas costs passed on to Utility customers
|
(32.8
|
)
|
|
|
Higher ISRS revenues
|
4.6
|
|
|
|
Total Variation
|
$
|
(148.5
|
)
|
Temperatures experienced in the Utility’s service area during 2012, which were the warmest on record, were 27.9% warmer than in 2011. Total system therms sold and transported to the Utility’s customers within its service territory were 718.0 million for fiscal year 2012 compared with 885.4 million for fiscal year 2011. Total off-system therms sold and transported outside of the Utility’s service area were 308.0 million for fiscal year 2012 compared with 223.0 million for fiscal year 2011.
Operating Margin
- Gas Utility operating margin was
$314.4 million
for fiscal year 2012, a $6.0 million decrease over the same period last year. The decrease is primarily due to decreased sales margins reflecting warmer weather totaling $7.8 million in 2012 compared to fiscal year 2011 as 2012 was the warmest on record, partially offset by increased ISRS revenues of $4.6 million.
Operating Expenses
-
Remaining
operating expenses in fiscal year 2012 decreased $3.8 million, from fiscal year 2011. Other operation and maintenance expenses decreased $5.6 million, primarily due to a higher rate of overheads capitalized, decreased maintenance charges, a lower provision for uncollectible accounts, and a decrease in customer accounts expenses.
33
These factors were partially offset by higher pension and group insurance expenses. Depreciation and amortization expense increased $1.5 million, primarily due to additional depreciable property. Taxes, other than income taxes and gross receipts tax, increased $0.3 million, primarily due to higher payroll taxes.
Gas Marketing
Operating Revenues -
Gas Marketing operating revenues and decreased $311.2 million primarily due to the effect of recording certain transactions on a net basis, instead of gross, and due to lower per unit gas prices.
Operating Margin
- Gas Marketing operating margin was $25.0 million for fiscal year 2012, a $3.2 million increase compared to the same period last year. The increase was primarily attributable to LER's reduced transportation costs resulting from the renegotiation of contracts that were renewed during the latter halves of fiscal years 2011 and 2012. Increased transaction volume and LER's ability to procure gas supply at more favorable terms were largely offset by the effects of narrower regional price differences and reduced price volatility.
Other
Other Operating Revenues and Operating Expenses -
Other operating revenues and other operating expenses decreased $16.9 million and $7.1 million, respectively, in fiscal year 2012 compared to fiscal year 2011. These year-to-year variations were primarily attributable to non-regulated sales of propane inventory in fiscal year 2011. These transactions resulted in pre-tax income of $10.0 million in fiscal year 2011. This type of transaction did not recur in fiscal year 2012.
Other Income and (Income Deductions)-Net
Other Income and (Income Deductions)–Net increased $3.1 million in fiscal year 2012 (compared to fiscal year 2011) primarily due to higher net investment gains, partially offset by increased charitable contributions.
Interest Charges
Interest charges decreased $0.5 million in fiscal year 2012 (from fiscal year 2011). The decrease was primarily due to lower interest on long-term debt, attributable to the November 2010 maturity of $25 million principal amount of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for fiscal years 2012 and 2011. Average short-term borrowings were $43.8 million and $54.7 million for fiscal years 2012 and 2011, respectively.
Income Taxes
Income tax expense decreased $2.9 million in fiscal year 2012 compared to fiscal year 2011. The decrease is primarily due to lower pre-tax income, as well as, net changes in unrecognized tax benefits recorded in earnings and various property-related deductions.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), which requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. We believe the following represent the more significant items requiring the use of judgment and estimates in preparing our consolidated financial statements:
Accounts Receivable and Allowance for Doubtful Accounts
– Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectibility of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.
34
Goodwill -
For the MGE acquisition, goodwill was calculated as of the date of the acquisition, September 1, 2013, measured as the excess of the consideration transferred over the net amount of assets acquired less liabilities assumed. Goodwill will be tested for impairment beginning in fiscal year 2014 on an annual basis, or more frequently if circumstances surrounding the goodwill valuation change. The goodwill impairment test compares the fair value of a reporting unit, or operating segment, to its carrying amount, including goodwill.
Employee Benefits and Postretirement Obligations
– Pension and postretirement obligations are calculated by actuarial consultants that utilize several statistical factors and other assumptions provided by management related to future events, such as discount rates, returns on plan assets, compensation increases, and mortality rates. For the Utility, the amount of expense recognized and the amounts reflected in other comprehensive income are dependent upon the regulatory treatment provided for such costs, as discussed further below. Certain liabilities related to group medical benefits and workers’ compensation claims, portions of which are self-insured and/or contain “stop-loss” coverage with third-party insurers to limit exposure, are established based on historical trends.
The table below reflects the sensitivity of Laclede’s plans to potential changes in key assumptions:
|
Pension Plan Benefits:
|
|
|
|
||||||||
|
Actuarial Assumptions
|
Increase/(Decrease)
|
Estimated Increase/(Decrease) to Projected Benefit Obligation (Thousands)
|
Estimated Increase/ (Decrease) to Annual Net Pension Cost* (Thousands)
|
||||||||
|
Discount Rate
|
0.25
|
%
|
$
|
(13,210
|
)
|
$
|
400
|
|
|||
|
|
(0.25
|
)
|
13,510
|
|
(440
|
)
|
|||||
|
Rate of Future Compensation Increase
|
0.25
|
%
|
5,840
|
|
350
|
|
|||||
|
|
(0.25
|
)
|
(5,720
|
)
|
(350
|
)
|
|||||
|
Expected Return on Plan Assets
|
0.25
|
%
|
—
|
|
(930
|
)
|
|||||
|
|
(0.25
|
)
|
—
|
|
930
|
|
|||||
|
Postretirement Benefits:
|
|
|
|
||||||||
|
Actuarial Assumptions
|
Increase/(Decrease)
|
Estimated Increase/(Decrease) to Projected Postretirement Benefit Obligation (Thousands)
|
Estimated Increase/(Decrease) to Annual Net Postretirement Benefit Cost* (Thousands)
|
||||||||
|
Discount Rate
|
0.25
|
%
|
$
|
(4,000
|
)
|
$
|
(181
|
)
|
|||
|
|
(0.25
|
)
|
4,080
|
|
180
|
|
|||||
|
Expected Return on Plan Assets
|
0.25
|
%
|
—
|
|
(240
|
)
|
|||||
|
|
(0.25
|
)
|
—
|
|
240
|
|
|||||
|
Annual Medical Cost Trend
|
1.00
|
%
|
7,060
|
|
1,520
|
|
|||||
|
|
(1.00
|
)
|
(6,580
|
)
|
(1,390
|
)
|
|||||
* Excludes the impact of regulatory deferral mechanism. See
Note 3
, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements for information regarding the regulatory treatment of these costs.
Gas Utility
Operations
– The Utility accounts for its regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. Management believes the following represent the more significant items recorded through the application of this accounting guidance:
35
PGA Clause
The Utility’s PGA Clause allows Laclede Gas and MGE to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including the costs, cost reductions, and related carrying costs associated with the Utility’s use of natural gas derivative instruments to hedge the purchase price of natural gas. The difference between actual costs incurred and costs recovered through the application of the PGA clauses are recorded as regulatory assets and regulatory liabilities that are recovered or refunded in a subsequent period. The PGA Clauses also permit the application of carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, and also provide for a portion of income from off-system sales and capacity release revenues to be flowed through to customers. Laclede Gas' PGA Clause also authorizes the Utility to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.
Asset Retirement Obligations
Asset retirement obligations are recorded in accordance with GAAP using various assumptions related to the timing, method of settlement, inflation, and profit margins that third parties would demand to settle the future obligations. These assumptions require the use of judgment and estimates and may change in future periods as circumstances dictate. As authorized by the MoPSC, the Utility accrues future removal costs associated with its property, plant and equipment through its depreciation rates, even if a legal obligation does not exist as defined by GAAP. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognizable pursuant to GAAP is a timing difference between the recovery of these costs in rates and their recognition for financial reporting purposes.
Defined Pension Benefit and Other Postretirement Benefits
The amount of net periodic pension and other postretirement benefit cost recognized in the financial statements related to the Utility’s qualified pension plans and other postretirement benefit plans is based upon allowances, as approved by the MoPSC, which have been established in the rate-making process for the recovery of these costs from customers. The differences between these amounts and actual pension and other postretirement benefit costs incurred for financial reporting purposes are deferred as regulatory assets or regulatory liabilities. GAAP also requires that changes that affect the funded status of pension and other postretirement benefit plans, but that are not yet required to be recognized as components of pension and other postretirement benefit cost, be reflected in other comprehensive income. For the Utility’s qualified pension plans and other postretirement benefit plans, amounts that would otherwise be reflected in other comprehensive income are deferred with entries to regulatory assets or regulatory liabilities. Accordingly, these differences are deferred as regulatory liabilities.
Gas Marketing Energy Contracts
– LER routinely enters into contracts associated with the physical purchase or sale of natural gas in a future period. In determining the appropriate accounting treatment for these contracts, management is required to assess the contract terms and various other factors to determine if the contracts are subject to the derivative accounting guidance in ASC Topic 815, “Derivatives and Hedging.” If a contract is deemed to meet the definition of derivative, management’s judgment may be further required in determining if the contract is eligible for the normal purchases or normal sales election. Pursuant to GAAP, contracts not designated as normal purchases or normal sales are required to be accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. In the absence of quoted prices in active markets for identical assets or liabilities, determining the fair value of a derivative contract requires judgment as to the appropriateness of various market inputs and involves making assumptions regarding how market participants would price the asset or liability. In addition to these physical contracts, LER also utilizes natural gas futures, swap, and option contracts traded on or cleared through the New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) to manage the price risk associated with certain of its fixed-price commitments. These contracts may be designated for hedge accounting treatment, as discussed in
Note 11
, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.
For further discussion of significant accounting policies, see
Note 1
, Summary of Significant Accounting Policies, of the Notes to Consolidated Financial Statements.
REGULATORY AND OTHER MATTERS
The MoPSC Staff previously proposed disallowances related to Laclede Gas' recovery of its purchased gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC Staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules.
36
Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism. For a three-year period ending September 3, 2016, Laclede Gas' share of the first $2 million in net margin is reduced from 15% to 0%. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first $2 million in net margins returns to 15%. The stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.
On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC's May 2011 penalty case was dismissed.
On December 21, 2012, Laclede Gas filed tariff sheets in a new general rate case proceeding that were designed to increase total revenues by $58.4 million, less the current annualized ISRS revenues that were already being recovered from customers. On June 26, 2013, the MoPSC approved a Unanimous Stipulation and Agreement in which the Utility will incorporate its then current annualized ISRS revenues of $14.8 million into its base rates, effective September 1, 2013. At that time, the ISRS charge was reset to zero, and the Utility will be permitted to make future ISRS filings for any qualifying expenditures incurred after January 31, 2013.
On January 14, 2013, the Company filed an application with the MoPSC for approval to acquire the assets of MGE from Southern Union Company (SUG). On July 2, 2013, the Utility and other parties to the proceeding filed a Unanimous Stipulation and Agreement (Agreement) with the MoPSC resolving all matters in the case, which was approved by the Commission on July 17, 2013. The Agreement authorizes Laclede Gas to acquire MGE and obtain the necessary financing, subject to various conditions set forth in the Agreement. Under the Agreement, the Utility would generally be precluded from filing a general rate case for either Laclede Gas or MGE prior to October 1, 2015, except that a general rate case for the MGE service territory could be filed no later than September 18, 2013. ISRS filings and the collection of gas costs under Laclede Gas' PGA Clause would not be impacted. The Agreement also allows for the deferral for future recovery of a portion of one-time costs incurred associated with the integration of MGE. The Agreement sets forth a number of other conditions including those related to credit ratings, gas supply, service quality, gas safety, and reporting requirements.
A petition was filed with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the Company's acquisition of NEG. An amended petition was filed with DPU on February 19, 2013 requesting that the DPU authorize the sale of NEG to Liberty Utilities, a subsidiary of Algonquin Power Utilities Corporation. Evidentiary hearings were held in June and August 2013. The matter is now awaiting a decision by the DPU.
On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.
On September 16, 2013, MGE filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $23.4 million, less the current annualized ISRS revenues of $6.3 million that were already being recovered from customers. Consistent with its normal practice, the MoPSC suspended implementation of the MGE proposed rates on September 17, 2013 and set the case for hearing in April 2014.
37
ACCOUNTING PRONOUNCEMENTS
The Company has evaluated or is in the process of evaluating the impact that recently issued accounting standards will have on the Company’s financial position or results of operations upon adoption. For disclosures related to the adoption of new accounting standards, see the New Accounting Standards section of
Note 1
of the Notes to Consolidated Financial Statements.
The Company continues to monitor the developments of the Financial Accounting Standards Board (FASB) relative to possible changes in accounting standards. Currently, the FASB is considering various changes to U. S. GAAP, some of which may be significant, as part of a joint effort with the International Accounting Standards Board to converge accounting standards. Future developments, depending on the outcome, have the potential to impact the Company’s financial condition and results of operations.
INFLATION
The accompanying consolidated financial statements reflect the historical costs of events and transactions, regardless of the purchasing power of the dollar at the time. Due to the capital-intensive nature of the business of the Company, the most significant impact of inflation is on the depreciation of utility plant. Rate regulation, to which the Utility is subject, allows recovery through its rates of only the historical cost of utility plant as depreciation. The Utility expects to incur significant capital expenditures during the next few years, primarily related to a significant software replacement project to enhance technology, customer service, and business processes and the planned increased replacements of distribution plant. The Company believes that any higher costs experienced upon replacement of existing facilities will be recovered through the normal regulatory process.
FINANCIAL CONDITION
CASH FLOWS
The Company’s short-term borrowing requirements typically peak during colder months when the Utility borrows money to cover the lag between when it purchases its natural gas and when its customers pay for that gas. Changes in the wholesale cost of natural gas, including cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments, variations in the timing of collections of gas cost under the Utility’s PGA Clause, the seasonality of accounts receivable balances, and the utilization of storage gas inventories cause short-term cash requirements to vary during the year and from year to year, and may cause significant variations in the Company’s cash provided by or used in operating activities.
Net cash provided by operating activities for fiscal years 2013, 2012 and 2011 was
$163.9 million
, $128.1 million and $167.2 million, respectively. The increase in net cash provided by operating activities in fiscal year 2013 as compared to fiscal year 2012 is primarily attributable to variations associated with the timing of collections of gas cost under the Utility’s PGA Clause, including the net effect of increased cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments. The variation also reflects decreased cash payments for the funding of pension plans and for the payment of income taxes. These benefits were partially offset by changes in delayed and advanced customer billings. The decrease in net cash provided by operating activities in fiscal year 2012 as compared to fiscal year 2011 is primarily attributable to variations associated with the timing of collections of gas cost under the Utility’s PGA Clause, including the net effect of increased cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments and changes in the cost of natural gas storage inventories. The decrease is also attributable to the effect of a non-regulated sale of propane inventory in fiscal year 2011 and increased cash payments for the funding of pension plans in 2012.
Net cash used in investing activities for fiscal years 2013, 2012 and 2011 was
$1,108.3 million
, $105.4 million and $67.0 million, respectively. Net cashed used in 2013 includes $975.0 million for the acquisition of MGE. The remaining net cash used in investing activities primarily reflected capital expenditures in all periods. The variations primarily reflect additional capital expenditures for distribution plant and information technology investments.
Net cash provided in financing activities for fiscal years 2013 was
$969.9 million
and the net cash used in financing activities for 2012 and 2011 was $38.5 million, and $143.8 million, respectively. The increase in net cash provided in financing activities in fiscal year 2013 from fiscal year 2012 primarily reflects the May 2013 common stock issuance of 10.0 million shares and issuance of long-term debt of $450.0 million for the acquisition of MGE. The decrease in net cash used in fiscal 2012 from fiscal year 2011 primarily reflects decreased repayments of short-term debt and the effect of the maturity of long-term debt in 2011.
38
LIQUIDITY AND CAPITAL RESOURCES
Cash and Cash Equivalents
Laclede Group had no temporary cash investments as of
September 30, 2013
. During fiscal year 2013, short-term investments were diversified among highly-rated money market funds, interest-bearing deposits, and commercial paper issues. The money market funds were accessible by the Company on demand. The bank deposits were also generally available on demand, though the banks reserve the right to require seven days’ notice for a withdrawal. These funds were used to support the working capital needs of the Company’s subsidiaries and as a store of liquidity in advance of the MGE acquisition. The balance of short-term investments ranged between $0 and $969.4 million during fiscal year
2013
and ranged between $5.3 million and $23.3 million during fiscal year
2012
. Due to lower yields available to Laclede Group on its short-term investments, Laclede Group elected to provide a portion of the Utility’s short-term funding through intercompany lending during fiscal years
2013
and
2012
.
The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At September 30, 2012, Laclede Gas had a syndicated line of credit in place of $300 million from seven banks. On September 3, 2013, the Utility entered into a new syndicated line of credit for $450 million with nine banks, which will expire in September 2018. The previous syndicated line of credit was terminated at that time. The largest portion provided by a single bank under the current line is 15.6%. The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 48% of total capitalization on
September 30, 2013
.
Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On
September 30, 2012
, Laclede Group had a syndicated line of credit for $50 million from seven banks. On September 3, 2013, Laclede Group entered into a new $150 million syndicated line of credit, which expires in September 2018. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 49% on
September 30, 2013
. Laclede Group’s line may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s line during fiscal years
2013
and
2012
.
Information about Laclede Group’s consolidated short-term borrowings during the 12 months ended
September 30, 2013
and
2012
and as of
September 30, 2013
and
2012
, is presented below:
|
|
Commercial Paper Borrowings
|
|
Twelve Months Ended September 30, 2013
|
|
|
Weighted average borrowings outstanding
|
$34.2 million
|
|
Weighted average interest rate
|
0.3%
|
|
Range of borrowings outstanding
|
$0 – $99.4 million
|
|
As of September 30, 2013
|
|
|
Borrowings outstanding at end of period
|
$74.0 million
|
|
Weighted average interest rate
|
0.3%
|
|
Twelve Months Ended September 30, 2012
|
|
|
Weighted average borrowings outstanding
|
$43.8 million
|
|
Weighted average interest rate
|
0.3%
|
|
Range of borrowings outstanding
|
$0 – $133.5 million
|
|
As of September 30, 2012
|
|
|
Borrowings outstanding at end of period
|
$40.1 million
|
|
Weighted average interest rate
|
0.2%
|
Based on average short-term borrowings for the 12 months ended
September 30, 2013
, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.3 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.
39
Long-term Debt and Equity
Laclede Group issued $25 million of 3.31% 10-year unsecured notes in a private placement on December 14, 2012, which had been committed to in August 2012. The proceeds of all the issue were used for general corporate purposes.
On March 15, 2013, the Utility issued $100 million of first mortgage bonds in a private placement that also had been committed to in August 2012. Of this, $55 million were issued at 3.00% for a 10-year term, maturing in March 2023, and $45 million were issued at 3.40% for a 15-year term, maturing in March 2028. The proceeds of both the issues were used for the repayment of short-term debt and general corporate purposes.
On May 29, 2013 the Laclede Group received approximately $428 million from the issuance of 10.0 million common shares to fund a portion of the purchase of MGE. These funds were invested in high quality, short-term instruments until the MGE acquisition was completed on September 3, 2013.
On August 13, 2013 Laclede Gas Company issued $450 million of first mortgage bonds. Of this, $100 million was issued at 2.00% maturing in August 2018, $250 million was issued at 3.40% maturing in August 2023, and $100 million was issued at 4.625% maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.
The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization was originally effective through June 30, 2013. In August 2012, Laclede Gas filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension became effective on November 23, 2012. During the year ended September 30, 2013, pursuant to this authority, the Utility sold 11,745 shares of its common stock to Laclede Group for $476.5 million. As of November 26, 2013, $370.8 million remains available under this authorization.
At September 30, 2013, the Company had fixed-rate long-term debt totaling $915 million. On October 15, 2012, the Utility paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. While the remaining long-term debt issues are fixed-rate, they are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility’s regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Company’s $915 million in long-term debt, $50 million have no call option, $435 million have make-whole call options, $350 million are callable at par three to six months prior to maturity and $80 million are callable at par beginning in October 2013. None of the debt has any put options.
Shelf Registration Statement
On August 6, 2013, Laclede Gas and Laclede Group filed with the SEC a joint shelf registration statement on Form S-3 ASR for issuance of debt and equity securities, which expires August 5, 2016. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions. Laclede Gas' $450 million issuance of bonds on August 13, 2013 was under this registration statement.
Laclede Group also has a registration statement on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 194,246 and 186,919 shares at September 30, 2013 and November 26, 2013, respectively, remaining available for issuance under its Form S-3.
Other
The Company’s and the Utility’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company and the Utility remain at investment grade, but are subject to review and change by the rating agencies.
The Utility's capital expenditures were $128.5 million for fiscal 2013, compared with $106.7 million and $67.3 million for fiscal years 2012 and 2011, respectively. The increases in capital expenditures, compared with prior periods, are primarily attributable to additional expenditures for distribution plant and information technology investments.
40
Non-utility capital expenditures for fiscal year 2013 were $2.3 million compared with $2.1 million in fiscal year 2012 and $0.3 million in fiscal year 2011, and are estimated to be approximately $10 million for fiscal year 2014. The Utility's capital expenditures are expected to be approximately $175 million in fiscal year 2014.
Consolidated capitalization at September 30, 2013 consisted of
53.4%
Laclede Group common stock equity and
46.6%
of long-term debt, compared to
63.9%
Laclede Group common stock equity and
36.1%
of long-term debt at September 30, 2012.
Laclede Group’s ratio of earnings to fixed charges was
3.3
for fiscal year 2013 and 4.4 for fiscal years 2012 and 2011.
It is management’s view that the Company has adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.
CONTRACTUAL OBLIGATIONS
As of September 30, 2013, Laclede Group had contractual obligations with payments due as summarized below (in millions):
|
|
Payments due by period
|
||||||||||||||||||
|
|
|
Less than
|
1-3
|
3-5
|
More than
|
||||||||||||||
|
Contractual Obligations
|
Total
|
1 Year
|
Years
|
Years
|
5 Years
|
||||||||||||||
|
Principal Payments on Long-Term Debt
|
$
|
915.0
|
|
$
|
—
|
|
$
|
—
|
|
$
|
100.0
|
|
$
|
815.0
|
|
||||
|
Interest Payments on Long-Term Debt
|
695.5
|
|
40.5
|
|
80.9
|
|
80.9
|
|
493.2
|
|
|||||||||
|
Capital Leases (a)
|
0.2
|
|
0.1
|
|
0.1
|
|
—
|
|
—
|
|
|||||||||
|
Operating Leases (a)
|
11.6
|
|
6.0
|
|
4.9
|
|
0.7
|
|
—
|
|
|||||||||
|
Purchase Obligations – Natural Gas (b)
|
981.2
|
|
528.6
|
|
231.0
|
|
149.4
|
|
72.2
|
|
|||||||||
|
Purchase Obligations – Other (c)
|
76.1
|
|
25.7
|
|
19.1
|
|
18.4
|
|
12.9
|
|
|||||||||
|
Other Long-Term Liabilities
|
159.2
|
|
15.2
|
|
30.9
|
|
31.5
|
|
81.6
|
|
|||||||||
|
Total (d)
|
$
|
2,838.8
|
|
$
|
616.1
|
|
$
|
366.9
|
|
$
|
380.9
|
|
$
|
1,474.9
|
|
||||
|
(a)
|
Lease obligations are primarily for office space, vehicles, and power operated equipment. Additional payments will be incurred if renewal options are exercised under the provisions of certain agreements.
|
|
(b)
|
These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Gas Utility and Gas Marketing segments including the LER ten-year storage agreement with Perryville Gas Storage. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using September 30, 2013 forward market prices. Laclede Gas recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA Clause, subject to prudence review by the MoPSC; however, variations in the timing of collections of gas costs from customers affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.
|
|
(c)
|
These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations.
|
|
(d)
|
Long-term liabilities associated with unrecognized tax benefits, totaling $2.4 million, have been excluded from the
|
table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. The Company expects to make contributions to its qualified, trusteed pension plans totaling $24.0 million in fiscal year 2014. The Utility anticipates a $0.3 million contribution relative to its non-qualified pension plans during fiscal year 2014. With regard to the postretirement benefits, the Company anticipates the Utility will contribute $19.2 million to the qualified trusts and $0.3 million directly to participants from the Utility's funds during fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to
Note 3
, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements.
41
MARKET RISK
Commodity Price Risk
The Utility’s commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of Laclede Gas' and MGE's PGA Clauses. The PGA Clauses allow the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. Laclede Gas and MGE also have risk management policies that allow for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. These policies prohibit speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see
Note 11
, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.
In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, enters into contracts to purchase and sell natural gas at fixed prices and natural gas index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments. In accordance with the risk management policy, LER manages the price risk associated with its fixed-price commitments. This risk is currently managed either by closely matching the offsetting physical purchase or sale of natural gas at fixed-prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. At
September 30, 2013
and
2012
, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations.
As mentioned above, LER uses natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to manage the commodity price risk associated with its fixed-price natural gas purchase and sale commitments. These derivative instruments may be designated as cash flow hedges of forecasted purchases or sales. Such accounting treatment, if elected, generally permits a substantial portion of the gain or loss to be deferred from recognition in earnings until the period that the associated forecasted purchase or sale is recognized in earnings. To the extent a hedge is effective, gains or losses on the derivatives will be offset by changes in the value of the hedged forecasted transactions. Information about the fair values of LER’s exchange-traded/cleared natural gas derivative instruments is presented below:
|
(Thousands)
|
Derivative
Fair
Values
|
Cash
Margin
|
Derivatives
and Cash
Margin
|
||||||||
|
Net balance of derivative assets at September 30, 2012
|
$
|
(3,515
|
)
|
$
|
5,489
|
|
$
|
1,974
|
|
||
|
Changes in fair value
|
5,044
|
|
—
|
|
5,044
|
|
|||||
|
Settlements/purchases - net
|
1,114
|
|
—
|
|
1,114
|
|
|||||
|
Changes in cash margin
|
—
|
|
(5,235
|
)
|
(5,235
|
)
|
|||||
|
Net balance of derivative assets at September 30, 2013
|
$
|
2,643
|
|
$
|
254
|
|
$
|
2,897
|
|
||
|
(Thousands)
|
As of September 30, 2013
|
||||||||||||||
|
|
Maturity by Fiscal Year
|
||||||||||||||
|
|
Total
|
2014
|
2015
|
2016
|
|||||||||||
|
Fair values of exchange-traded/cleared natural gas derivatives - net
|
$
|
2,643
|
|
$
|
2,632
|
|
$
|
11
|
|
$
|
—
|
|
|||
|
MMBtu – net long futures/swap/option positions
|
(11,058
|
)
|
(11,198
|
)
|
125
|
|
15
|
|
|||||||
Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement.
42
Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2016:
|
(Thousands)
|
|
||
|
Net balance of derivative assets at September 30, 2012
|
$
|
2,741
|
|
|
Changes in fair value
|
16
|
|
|
|
Settlements
|
(2,658
|
)
|
|
|
Net balance of derivative assets at September 30, 2013
|
$
|
99
|
|
For further details related to LER’s derivatives and hedging activities, see
Note 11
, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.
Counterparty Credit Risk
LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. LER is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see
Note 12
, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.
Interest Rate Risk
The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during fiscal year
2013
, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $0.3 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At
September 30, 2013
, Laclede Gas had fixed-rate long-term debt totaling $890 million. Additionally, Laclede Group had fixed-rate long-term debt totaling $25 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility’s regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.
The Company entered into and settled certain interest rate swap transactions to protect itself against adverse movements in interest rates associated with the issuance of long-term debt to fund the acquisition of MGE. Refer to
Note 11
, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements for additional details on these interest rate swap transactions.
ENVIRONMENTAL MATTERS
The Utility owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs. For information relative to environmental matters, see
Note 16
, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.
OFF-BALANCE SHEET ARRANGEMENTS
Laclede Group has no off-balance sheet arrangements.
43
For this discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Market Risk
, on page
42
of this report.
44
|
Item 8. Financial Statements and Supplementary Data
|
|
||
|
|
|
|
2013 10-K Page
|
|
|
|
|
|
|
|
|
||
|
|
|
||
|
|
|
|
|
|
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
For Years Ended September 30, 2013, 2012, and 2011:
|
|
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
As of September 30, 2013 and 2012:
|
|
|
|
|
||
|
|
|
||
|
|
|
Notes to Consolidated Financial Statements:
|
|
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
45
Management Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2013. In making this assessment, management used the crit
eria in
Internal Control - Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. As permitted, that assessment excluded the business operations of Missouri Gas Energy (MGE), which was completed on September 3, 2013, and whose financial statements constitute 50 percent and 36 percent of net and total assets, respectively, 2 percent of revenues, and 3 percent of net income, of the consolidated financial statement amounts as of and for the year ended September 30, 2013. Refer to Note 2, Acquisition of MGE in the Notes to Consolidated Financial Statements for further discussion of the acquisition. Based on that assessment, management concluded that the Company’s internal control over financial reporting was effective as of September 30, 2013. Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on the Company’s internal control over financial reporting, which is included herein.
46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
The Laclede Group, Inc.
St. Louis, Missouri
We have audited the internal control over financial reporting of The Laclede Group, Inc. and subsidiaries (the "Company") as of September 30, 2013, based on criteria established in
Internal Control - Integrated Framework(1992)
issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal controls over financial reporting at Missouri Gas Energy (“MGE”), which was acquired on September 3, 2013 and whose financial statements constitute 50 percent and 36 percent of net and total assets, respectively, two percent of total revenues, and three percent of net income of the consolidated financial statements as of and for the year ended September 30, 2013. Accordingly, our audit did not include the internal control over financial reporting at MGE. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on the criteria established in
Internal Control - Integrated Framework (1992)
issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended September 30, 2013 of the Company and our report dated November 26, 2013 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
St. Louis, Missouri
November 26, 2013
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
The Laclede Group, Inc.
St. Louis, Missouri
We have audited the accompanying consolidated balance sheets and statements of consolidated capitalization of The Laclede Group, Inc. and subsidiaries (the “Company”) as of September 30, 2013 and 2012, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Laclede Group, Inc. and subsidiaries as of September 30, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of September 30, 2013, based on the criteria established in
Internal Control-Integrated Framework (1992)
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
St. Louis, Missouri
November 26, 2013
48
|
THE LACLEDE GROUP, INC.
|
|
|
|
||||||||
|
STATEMENTS OF CONSOLIDATED INCOME
|
|
|
|
||||||||
|
(Thousands, Except Per Share Amounts)
|
|
|
|
||||||||
|
Years Ended September 30
|
2013
|
2012
|
2011
|
||||||||
|
Operating Revenues:
|
|
|
|
||||||||
|
Gas Utility
|
$
|
847,224
|
|
$
|
763,447
|
|
$
|
913,190
|
|
||
|
Gas Marketing
|
165,146
|
|
358,145
|
|
669,375
|
|
|||||
|
Other
|
4,649
|
|
3,883
|
|
20,742
|
|
|||||
|
Total Operating Revenues
|
1,017,019
|
|
1,125,475
|
|
1,603,307
|
|
|||||
|
Operating Expenses:
|
|
|
|
||||||||
|
Gas Utility
|
|
|
|
||||||||
|
Natural and propane gas
|
433,442
|
|
397,304
|
|
549,947
|
|
|||||
|
Other operation and maintenance expenses
|
180,342
|
|
167,351
|
|
172,938
|
|
|||||
|
Depreciation and amortization
|
48,283
|
|
40,739
|
|
39,214
|
|
|||||
|
Taxes, other than income taxes
|
60,079
|
|
53,672
|
|
60,752
|
|
|||||
|
Total Gas Utility Operating Expenses
|
722,146
|
|
659,066
|
|
822,851
|
|
|||||
|
Gas Marketing
|
176,554
|
|
353,283
|
|
652,567
|
|
|||||
|
Other
|
21,825
|
|
2,524
|
|
9,642
|
|
|||||
|
Total Operating Expenses
|
920,525
|
|
1,014,873
|
|
1,485,060
|
|
|||||
|
Operating Income
|
96,494
|
|
110,602
|
|
118,247
|
|
|||||
|
Other Income and (Income Deductions) – Net
|
2,444
|
|
3,272
|
|
177
|
|
|||||
|
Interest Charges:
|
|
|
|
||||||||
|
Interest on long-term debt
|
25,539
|
|
22,958
|
|
23,161
|
|
|||||
|
Other interest charges
|
3,063
|
|
1,987
|
|
2,256
|
|
|||||
|
Total Interest Charges
|
28,602
|
|
24,945
|
|
25,417
|
|
|||||
|
Income Before Income Taxes
|
70,336
|
|
88,929
|
|
93,007
|
|
|||||
|
Income Tax Expense
|
17,578
|
|
26,289
|
|
29,182
|
|
|||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
||||||||
|
Basic
|
25,875
|
|
22,262
|
|
22,099
|
|
|||||
|
Diluted
|
25,952
|
|
22,340
|
|
22,171
|
|
|||||
|
Basic Earnings Per Share of Common Stock
|
$
|
2.03
|
|
$
|
2.80
|
|
$
|
2.87
|
|
||
|
Diluted Earnings Per Share of Common Stock
|
$
|
2.02
|
|
$
|
2.79
|
|
$
|
2.86
|
|
||
See the accompanying
Notes to Consolidated Financial Statements
.
49
|
THE LACLEDE GROUP, INC.
|
|
|
|
||||||||
|
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
|
|
|
|||||||||
|
(Thousands)
|
|
|
|
||||||||
|
Years Ended September 30
|
2013
|
2012
|
2011
|
||||||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Other Comprehensive Income (Loss), Before Tax:
|
|
|
|
||||||||
|
Net gains (losses) on cash flow hedging derivative instruments:
|
|
|
|
||||||||
|
Net hedging gain arising during the period
|
5,047
|
|
4,802
|
|
5,581
|
|
|||||
|
Reclassification adjustment for (gains) losses included in net income
|
302
|
|
(8,397
|
)
|
1,861
|
|
|||||
|
Net unrealized (losses) gains on cash flow hedging derivative instruments
|
5,349
|
|
(3,595
|
)
|
7,442
|
|
|||||
|
Defined benefit pension and other postretirement benefit plans:
|
|
|
|
||||||||
|
Net actuarial (loss) gain arising during the period
|
(120
|
)
|
(3,397
|
)
|
339
|
|
|||||
|
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost
|
195
|
|
3,706
|
|
426
|
|
|||||
|
Net defined benefit pension and other postretirement benefit plans
|
75
|
|
309
|
|
765
|
|
|||||
|
Other Comprehensive (Loss) Income, Before Tax
|
5,424
|
|
(3,286
|
)
|
8,207
|
|
|||||
|
Income Tax (Benefit) Expense Related to Items of Other Comprehensive (Loss) Income
|
2,094
|
|
(1,270
|
)
|
3,170
|
|
|||||
|
Other Comprehensive (Loss) Income, Net of Tax
|
3,329
|
|
(2,016
|
)
|
5,037
|
|
|||||
|
Comprehensive Income
|
$
|
56,087
|
|
$
|
60,624
|
|
$
|
68,862
|
|
||
See the accompanying
Notes to Consolidated Financial Statements
.
50
|
THE LACLEDE GROUP, INC.
|
|
|
|||||
|
CONSOLIDATED BALANCE SHEETS
|
|
|
|||||
|
(Thousands)
|
|
|
|||||
|
September 30
|
2013
|
2012
|
|||||
|
ASSETS
|
|
|
|||||
|
Utility Plant
|
$
|
2,271,189
|
|
$
|
1,497,419
|
|
|
|
Less – Accumulated depreciation and amortization
|
494,559
|
|
478,120
|
|
|||
|
Net Utility Plant
|
1,776,630
|
|
1,019,299
|
|
|||
|
Non-utility property (net of accumulated depreciation and amortization, 2013, $5,886; 2012, $10,018)
|
7,694
|
|
6,039
|
|
|||
|
Goodwill
|
247,078
|
|
—
|
|
|||
|
Other investments
|
58,306
|
|
50,775
|
|
|||
|
Other Property and Investments
|
313,078
|
|
56,814
|
|
|||
|
Current Assets:
|
|
|
|||||
|
Cash and cash equivalents
|
52,981
|
|
27,457
|
|
|||
|
Accounts receivable:
|
|
|
|||||
|
Utility
|
101,118
|
|
64,027
|
|
|||
|
Non-utility
|
63,752
|
|
51,042
|
|
|||
|
Other
|
14,451
|
|
26,478
|
|
|||
|
Allowance for doubtful accounts
|
(8,046
|
)
|
(7,705
|
)
|
|||
|
Inventories:
|
|
|
|||||
|
Natural gas stored underground
|
182,035
|
|
92,729
|
|
|||
|
Propane gas
|
8,962
|
|
10,200
|
|
|||
|
Materials and supplies at average cost
|
8,154
|
|
3,543
|
|
|||
|
Natural gas receivable
|
18,782
|
|
22,377
|
|
|||
|
Derivative instrument assets
|
3,291
|
|
2,855
|
|
|||
|
Unamortized purchased gas adjustments
|
17,533
|
|
40,674
|
|
|||
|
Prepayments and other
|
12,867
|
|
9,339
|
|
|||
|
Total Current Assets
|
475,880
|
|
343,016
|
|
|||
|
Deferred Charges:
|
|
|
|||||
|
Regulatory assets
|
545,947
|
|
456,047
|
|
|||
|
Other
|
13,851
|
|
5,086
|
|
|||
|
Total Deferred Charges
|
559,798
|
|
461,133
|
|
|||
|
Total Assets
|
$
|
3,125,386
|
|
$
|
1,880,262
|
|
|
51
|
THE LACLEDE GROUP, INC.
|
|
|
|||||
|
CONSOLIDATED BALANCE SHEETS (Continued)
|
|
|
|||||
|
(Thousands)
|
|
|
|||||
|
September 30
|
2013
|
2012
|
|||||
|
CAPITALIZATION AND LIABILITIES
|
|
|
|||||
|
Capitalization:
|
|
|
|||||
|
Common stock equity
|
$
|
1,046,282
|
|
$
|
601,611
|
|
|
|
Long-term debt (less current portion)
|
912,712
|
|
339,416
|
|
|||
|
Total Capitalization
|
1,958,994
|
|
941,027
|
|
|||
|
Current Liabilities:
|
|
|
|||||
|
Notes payable
|
74,000
|
|
40,100
|
|
|||
|
Accounts payable
|
140,234
|
|
89,503
|
|
|||
|
Advance customer billings
|
23,736
|
|
25,146
|
|
|||
|
Current portion of long-term debt
|
—
|
|
25,000
|
|
|||
|
Wages and compensation accrued
|
20,807
|
|
13,908
|
|
|||
|
Dividends payable
|
14,556
|
|
9,831
|
|
|||
|
Customer deposits
|
15,062
|
|
8,565
|
|
|||
|
Interest accrued
|
8,335
|
|
8,590
|
|
|||
|
Taxes accrued
|
32,896
|
|
11,304
|
|
|||
|
Deferred income taxes
|
1,012
|
|
6,675
|
|
|||
|
Other
|
22,540
|
|
13,502
|
|
|||
|
Total Current Liabilities
|
353,178
|
|
252,124
|
|
|||
|
Deferred Credits and Other Liabilities:
|
|
|
|||||
|
Deferred income taxes
|
379,114
|
|
355,509
|
|
|||
|
Unamortized investment tax credits
|
2,900
|
|
3,113
|
|
|||
|
Pension and postretirement benefit costs
|
228,653
|
|
196,558
|
|
|||
|
Asset retirement obligations
|
74,554
|
|
40,368
|
|
|||
|
Regulatory liabilities
|
82,560
|
|
56,319
|
|
|||
|
Other
|
45,433
|
|
35,244
|
|
|||
|
Total Deferred Credits and Other Liabilities
|
813,214
|
|
687,111
|
|
|||
|
Commitments and Contingencies
(Note 16)
|
|
|
|||||
|
Total Capitalization and Liabilities
|
$
|
3,125,386
|
|
$
|
1,880,262
|
|
|
See the accompanying
Notes to Consolidated Financial Statements
.
52
|
THE LACLEDE GROUP, INC.
|
|
|
|||||
|
STATEMENTS OF CONSOLIDATED CAPITALIZATION
|
|
|
|||||
|
(Thousands, Except for Shares and Per Share Amounts)
|
|
|
|||||
|
September 30
|
2013
|
2012
|
|||||
|
Common Stock Equity:
|
|
|
|||||
|
Common stock, par value $1 per share:
|
|
|
|||||
|
Authorized – 2013 and 2012, 70,000,000 shares
|
|
|
|||||
|
Issued – 2013, 32,696,836 shares; and 2012, 22,539,431 shares
|
$
|
32,697
|
|
$
|
22,539
|
|
|
|
Paid-in capital
|
594,269
|
|
168,607
|
|
|||
|
Retained earnings
|
420,103
|
|
414,581
|
|
|||
|
Accumulated other comprehensive loss
|
(787
|
)
|
(4,116
|
)
|
|||
|
Total Common Stock Equity
|
1,046,282
|
|
601,611
|
|
|||
|
Long Term Debt - Laclede Group:
|
|||||||
|
3.31% Notes Payable, due December 15, 2022
|
25,000
|
|
—
|
|
|||
|
Long-Term Debt – Laclede Gas:
|
|
|
|||||
|
First Mortgage Bonds:
|
|
|
|||||
|
5-1/2% Series, due May 1, 2019
|
50,000
|
|
50,000
|
|
|||
|
7% Series, due June 1, 2029
|
25,000
|
|
25,000
|
|
|||
|
7.90% Series, due September 15, 2030
|
30,000
|
|
30,000
|
|
|||
|
6% Series, due May 1, 2034
|
100,000
|
|
100,000
|
|
|||
|
6.15% Series, due June 1, 2036
|
55,000
|
|
55,000
|
|
|||
|
6.35% Series, due October 15, 2038
|
80,000
|
|
80,000
|
|
|||
|
3% Series, due March 15, 2023
|
55,000
|
|
—
|
|
|||
|
3.40% Series, due March 15, 2028
|
45,000
|
|
—
|
|
|||
|
2% Series, due August 15, 2018
|
100,000
|
|
—
|
|
|||
|
3.40% Series, due August 15, 2023
|
250,000
|
|
—
|
|
|||
|
4.625% Series, due August 15, 2043
|
100,000
|
|
—
|
|
|||
|
Total
|
915,000
|
|
340,000
|
|
|||
|
Unamortized discount, net of premium, on long-term debt
|
(2,288
|
)
|
(584
|
)
|
|||
|
Total Long-Term Debt
|
912,712
|
|
339,416
|
|
|||
|
Total Capitalization
|
$
|
1,958,994
|
|
$
|
941,027
|
|
|
Long-term debt dollar amounts are exclusive of current portion.
See the accompanying
Notes to Consolidated Financial Statements
.
53
|
THE LACLEDE GROUP, INC.
|
|
|
|
|
|
|||||||||||||||||
|
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
|
|
|
|
|||||||||||||||||||
|
|
Common Stock Issued
|
Paid-in
|
Retained
|
Accum.
Other
Comp.
|
|
|||||||||||||||||
|
(Thousands, Except for Shares and Per Share Amounts)
|
Shares
|
Amount
|
Capital
|
Earnings
|
Income (Loss)
|
Total
|
||||||||||||||||
|
BALANCE OCTOBER 1, 2010
|
22,292,804
|
|
$
|
22,293
|
|
$
|
158,698
|
|
$
|
361,723
|
|
$
|
(7,137
|
)
|
$
|
535,577
|
|
|||||
|
Net income
|
—
|
|
—
|
|
—
|
|
63,825
|
|
—
|
|
$
|
63,825
|
|
|||||||||
|
Dividend reinvestment plan
|
43,354
|
|
43
|
|
1,571
|
|
—
|
|
—
|
|
$
|
1,614
|
|
|||||||||
|
Stock-based compensation costs
|
—
|
|
—
|
|
3,949
|
|
—
|
|
—
|
|
$
|
3,949
|
|
|||||||||
|
Equity Incentive Plan
|
94,576
|
|
95
|
|
840
|
|
—
|
|
—
|
|
$
|
935
|
|
|||||||||
|
Employees’ taxes paid associated with restricted
shares withheld upon vesting
|
—
|
|
—
|
|
(1,162
|
)
|
—
|
|
—
|
|
$
|
(1,162
|
)
|
|||||||||
|
Non-employee directors’ restricted stock awards
|
—
|
|
—
|
|
(494
|
)
|
—
|
|
—
|
|
$
|
(494
|
)
|
|||||||||
|
Tax benefit – stock compensation
|
—
|
|
—
|
|
300
|
|
—
|
|
—
|
|
$
|
300
|
|
|||||||||
|
Dividends declared:
|
|
|
|
|
|
|||||||||||||||||
|
Common stock ($1.62 per share)
|
—
|
|
—
|
|
—
|
|
(36,250
|
)
|
—
|
|
$
|
(36,250
|
)
|
|||||||||
|
Other comprehensive loss, net of tax
|
—
|
|
—
|
|
—
|
|
—
|
|
5,037
|
|
$
|
5,037
|
|
|||||||||
|
BALANCE SEPTEMBER 30, 2011
|
22,430,734
|
|
22,431
|
|
163,702
|
|
389,298
|
|
(2,100
|
)
|
573,331
|
|
||||||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
62,640
|
|
—
|
|
$
|
62,640
|
|
|||||||||
|
Dividend reinvestment plan
|
46,107
|
|
46
|
|
1,795
|
|
—
|
|
—
|
|
$
|
1,841
|
|
|||||||||
|
Stock-based compensation costs
|
—
|
|
—
|
|
2,702
|
|
—
|
|
—
|
|
$
|
2,702
|
|
|||||||||
|
Equity Incentive Plan
|
62,590
|
|
62
|
|
2,408
|
|
—
|
|
—
|
|
$
|
2,470
|
|
|||||||||
|
Employees’ taxes paid associated with restricted
shares withheld upon vesting
|
—
|
|
—
|
|
(1,203
|
)
|
—
|
|
—
|
|
$
|
(1,203
|
)
|
|||||||||
|
Non-employee directors’ restricted stock awards
|
—
|
|
—
|
|
(565
|
)
|
—
|
|
—
|
|
$
|
(565
|
)
|
|||||||||
|
Tax benefit – stock compensation
|
—
|
|
—
|
|
(232
|
)
|
—
|
|
—
|
|
$
|
(232
|
)
|
|||||||||
|
Dividends declared:
|
|
|
|
|
|
|
||||||||||||||||
|
Common stock ($1.66 per share)
|
—
|
|
—
|
|
—
|
|
(37,357
|
)
|
—
|
|
$
|
(37,357
|
)
|
|||||||||
|
Other comprehensive income, net of tax
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,016
|
)
|
$
|
(2,016
|
)
|
|||||||||
|
BALANCE SEPTEMBER 30, 2012
|
22,539,431
|
|
22,539
|
|
168,607
|
|
414,581
|
|
(4,116
|
)
|
601,611
|
|
||||||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
52,758
|
|
—
|
|
$
|
52,758
|
|
|||||||||
|
Common stock offering
|
10,005,000
|
|
10,005
|
|
417,157
|
|
—
|
|
—
|
|
$
|
427,162
|
|
|||||||||
|
Dividend reinvestment plan
|
44,074
|
|
44
|
|
1,803
|
|
—
|
|
—
|
|
$
|
1,847
|
|
|||||||||
|
Stock-based compensation costs
|
—
|
|
—
|
|
4,441
|
|
—
|
|
—
|
|
$
|
4,441
|
|
|||||||||
|
Equity Incentive Plan
|
108,331
|
|
109
|
|
2,565
|
|
—
|
|
—
|
|
$
|
2,674
|
|
|||||||||
|
Employees’ taxes paid associated with restricted
shares withheld upon vesting
|
—
|
|
—
|
|
(931
|
)
|
—
|
|
—
|
|
$
|
(931
|
)
|
|||||||||
|
Non-employee directors’ restricted stock awards
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
$
|
—
|
|
|||||||||
|
Tax benefit – stock compensation
|
—
|
|
—
|
|
627
|
|
—
|
|
—
|
|
$
|
627
|
|
|||||||||
|
Dividends declared:
|
|
|
|
|
|
|
||||||||||||||||
|
Common stock ($1.70 per share)
|
—
|
|
—
|
|
—
|
|
(47,236
|
)
|
—
|
|
$
|
(47,236
|
)
|
|||||||||
|
Other comprehensive loss, net of tax
|
—
|
|
—
|
|
—
|
|
—
|
|
3,329
|
|
$
|
3,329
|
|
|||||||||
|
BALANCE SEPTEMBER 30, 2013
|
32,696,836
|
|
$
|
32,697
|
|
$
|
594,269
|
|
$
|
420,103
|
|
$
|
(787
|
)
|
$
|
1,046,282
|
|
|||||
See the accompanying
Notes to Consolidated Financial Statements
.
54
|
THE LACLEDE GROUP, INC.
|
|
|
|
||||||||
|
STATEMENTS OF CONSOLIDATED CASH FLOWS
|
|
|
|
||||||||
|
(Thousands)
|
|
|
|
||||||||
|
Years Ended September 30
|
2013
|
2012
|
2011
|
||||||||
|
Operating Activities:
|
|
|
|
||||||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Adjustments to reconcile net income to
|
|
|
|
||||||||
|
net cash provided by (used in) operating activities:
|
|
|
|
||||||||
|
Depreciation, amortization and accretion
|
49,283
|
|
41,339
|
|
39,764
|
|
|||||
|
Deferred income taxes and investment tax credits
|
22,053
|
|
30,554
|
|
23,885
|
|
|||||
|
Other - net
|
957
|
|
75
|
|
3,431
|
|
|||||
|
Changes in assets and liabilities:
|
|
|
|
||||||||
|
Accounts receivable – net
|
(650
|
)
|
(9,359
|
)
|
3,106
|
|
|||||
|
Unamortized purchased gas adjustments
|
23,141
|
|
(14,955
|
)
|
(2,001
|
)
|
|||||
|
Deferred purchased gas costs
|
13,300
|
|
11,090
|
|
44,565
|
|
|||||
|
Accounts payable
|
35,445
|
|
(8,790
|
)
|
(4,860
|
)
|
|||||
|
Advance customer billings – net
|
(8,248
|
)
|
9,916
|
|
(1,579
|
)
|
|||||
|
Taxes accrued
|
3,666
|
|
(1,169
|
)
|
1,387
|
|
|||||
|
Natural gas stored underground
|
(30,626
|
)
|
22,441
|
|
(1,594
|
)
|
|||||
|
Other assets and liabilities
|
2,835
|
|
(15,681
|
)
|
(2,742
|
)
|
|||||
|
Net cash provided by operating activities
|
163,914
|
|
128,101
|
|
167,187
|
|
|||||
|
Investing Activities:
|
|
|
|
||||||||
|
Capital expenditures
|
(130,788
|
)
|
(108,843
|
)
|
(67,638
|
)
|
|||||
|
Other investments
|
(2,511
|
)
|
3,439
|
|
631
|
|
|||||
|
Acquisition of MGE
|
(975,000
|
)
|
—
|
|
—
|
|
|||||
|
Net cash used in investing activities
|
(1,108,299
|
)
|
(105,404
|
)
|
(67,007
|
)
|
|||||
|
Financing Activities:
|
|
|
|
||||||||
|
Issuance of first mortgage bonds
|
550,000
|
|
—
|
|
—
|
|
|||||
|
Maturity of first mortgage bonds
|
(25,000
|
)
|
—
|
|
(25,000
|
)
|
|||||
|
Issuance (Repayment) of short-term debt - net
|
33,900
|
|
(5,900
|
)
|
(83,650
|
)
|
|||||
|
Notes Payable Issued
|
25,000
|
|
—
|
|
—
|
|
|||||
|
Change in book overdrafts
|
(1,255
|
)
|
1,455
|
|
(545
|
)
|
|||||
|
Issuance of common stock
|
431,682
|
|
4,311
|
|
2,549
|
|
|||||
|
Non-employee directors’ restricted stock awards
|
—
|
|
(565
|
)
|
(494
|
)
|
|||||
|
Dividends paid
|
(42,518
|
)
|
(36,896
|
)
|
(35,821
|
)
|
|||||
|
Employees’ taxes paid associated with restricted shares withheld upon vesting
|
(931
|
)
|
(1,203
|
)
|
(1,162
|
)
|
|||||
|
Excess tax benefits from stock-based compensation
|
1,778
|
|
338
|
|
314
|
|
|||||
|
Other
|
(2,747
|
)
|
(57
|
)
|
(13
|
)
|
|||||
|
Net cash provided by (used in) financing activities
|
969,909
|
|
(38,517
|
)
|
(143,822
|
)
|
|||||
|
Net (Decrease) Increase in Cash and Cash Equivalents
|
25,524
|
|
(15,820
|
)
|
(43,642
|
)
|
|||||
|
Cash and Cash Equivalents at Beginning of Year
|
27,457
|
|
43,277
|
|
86,919
|
|
|||||
|
Cash and Cash Equivalents at End of Year
|
$
|
52,981
|
|
$
|
27,457
|
|
$
|
43,277
|
|
||
|
Supplemental Disclosure of Cash Paid (Refunded) During the Year for:
|
|
|
|
||||||||
|
Interest
|
$
|
26,304
|
|
$
|
24,557
|
|
$
|
25,332
|
|
||
|
Income taxes
|
(9,375
|
)
|
1,540
|
|
6,860
|
|
|||||
See the accompanying
Notes to Consolidated Financial Statements
.
55
THE LACLEDE GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION -
The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in
Note 15
, Information by Operating Segment.
NATURE OF OPERATIONS -
The Laclede Group, Inc. (NYSE: LG), headquartered in St. Louis, Missouri, is a public utility holding company. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy. Together they provide more than
1.13 million
residential, commercial and industrial customers with safe and reliable natural gas service. Laclede’s primary non-utility business, Laclede Energy Resources, Inc., included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries and the non-regulated activities of Laclede Gas are described in
Note 15
, Information by Operating Segment, and are included in the Other column.
USE OF ESTIMATES -
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
SYSTEM OF ACCOUNTS -
The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).
UTILITY PLANT, DEPRECIATION AND AMORTIZATION -
Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.
Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged
3.2%
of the original cost of depreciable and amortizable property, compared to
3.1%
in both fiscal years 2012 and 2011.
The Utility’s capital expenditures were
$128.5 million
,
$106.7 million
, and
$67.3 million
for fiscal years 2013,
2012
, and
2011
, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling
$4.7 million
at
September 30, 2013
,
$9.7 million
at
September 30, 2012
, and
$8.2 million
at
September 30, 2011
. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.
ASSET RETIREMENT OBLIGATIONS -
Laclede Group records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company has recorded asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.
56
Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.
As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.
The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Asset retirement obligations, beginning of year
|
$
|
40,368
|
|
$
|
27,495
|
|
|
|
Liabilities incurred during the period
|
801
|
|
851
|
|
|||
|
Liabilities settled during the period
|
(1,089
|
)
|
(601
|
)
|
|||
|
Accretion
|
2,322
|
|
1,637
|
|
|||
|
Revisions in estimated cash flows
|
—
|
|
10,986
|
|
|||
|
Addition of MGE asset retirement obligation
|
32,152
|
|
—
|
|
|||
|
Asset retirement obligations, end of year
|
$
|
74,554
|
|
$
|
40,368
|
|
|
REGULATED OPERATIONS -
The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (GAAP) for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).
The following regulatory assets and regulatory liabilities were reflected in the Consolidated Balance Sheets as of September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Regulatory Assets:
|
|
|
|||||
|
Future income taxes due from customers
|
$
|
112,912
|
|
$
|
118,997
|
|
|
|
Pension and postretirement benefit costs
|
381,395
|
|
304,446
|
|
|||
|
Unamortized purchased gas adjustments
|
17,533
|
|
40,674
|
|
|||
|
Purchased gas costs
|
18,249
|
|
18,386
|
|
|||
|
Compensated absences
|
8,004
|
|
7,836
|
|
|||
|
Other
|
25,387
|
|
6,382
|
|
|||
|
Total Regulatory Assets
|
$
|
563,480
|
|
$
|
496,721
|
|
|
|
Regulatory Liabilities:
|
|
||||||
|
Unamortized investment tax credits
|
$
|
2,900
|
|
$
|
3,113
|
|
|
|
Accrued cost of removal
|
59,066
|
|
55,103
|
|
|||
|
Other
|
23,494
|
|
1,216
|
|
|||
|
Total Regulatory Liabilities
|
$
|
85,460
|
|
$
|
59,432
|
|
|
The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately
$17.2 million
and
$7.8 million
, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed
15
years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.
57
As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of
$10.5 million
are being recovered and amortized on a straight-line basis over a
fifteen
-year period, without return on investment. Amortization of these costs totaled
$9.7 million
from December 27, 1999 through September 30, 2013.
NATURAL GAS STORED UNDERGROUND AND PROPANE GAS –
For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at
September 30, 2013
and
September 30, 2012
was less than the LIFO cost by
$13.3 million
and
$24.3 million
, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.
BUSINESS COMBINATIONS -
The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to
Note 2
, MGE Acquisition.
GOODWILL -
Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded
$247.1 million
of goodwill as part of the MGE acquisition.
REVENUE RECOGNITION -
The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at
September 30, 2013
and
2012
, for the Utility, were
$25.2 million
and
$11.6 million
, respectively.
Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.
In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to
Note 11
, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.
PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT –
As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:
|
•
|
The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.
|
|
•
|
The tariffs allow the Utility flexibility to make up to
three
discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least
two
months.
|
|
•
|
The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.
|
58
|
•
|
The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain
10%
of cost savings, up to a maximum of
$3.0 million
annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.
|
Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.
|
Laclede Gas
|
||
|
Pre-tax Income
|
Customer Share
|
Company Share
|
|
First $2 million
|
100%
|
—%
|
|
Next $2 million
|
80%
|
20%
|
|
Next $2 million
|
75%
|
25%
|
|
Amounts exceeding $6 million
|
70%
|
30%
|
|
MGE
|
||
|
Pre-tax Income
|
Customer Share
|
Company Share
|
|
First $1.2 million
|
85%
|
15%
|
|
Next $1.2 million
|
80%
|
20%
|
|
Next $1.2 million
|
75%
|
25%
|
|
Amounts exceeding $3.6 million
|
70%
|
30%
|
See the
Regulatory and Other Matters
section on page
36
of this report for additional information on Laclede Gas' off-system sales.
INCOME TAXES -
Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.
The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.
CASH AND CASH EQUIVALENTS -
All highly liquid debt instruments purchased with original maturities of
three
months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.
59
Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.
NATURAL GAS RECEIVABLE –
LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.
EARNINGS PER COMMON SHARE -
GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in
Note 5
, Earnings Per Common Share.
GROSS RECEIPTS AND SALES TAXES -
Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were
$40.8 million
,
$35.9 million
, and
$43.5 million
for fiscal years
2013
,
2012
, and
2011
, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.
Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated Balance Sheets.
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS –
Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectibility of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.
GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES -
The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.
FAIR VALUE MEASUREMENTS
– Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.
60
The levels of the hierarchy are described below:
|
•
|
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.
|
|
•
|
Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.
|
|
•
|
Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.
|
Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in
Note 3
, Pension Plans and Other Postretirement Benefits,
Note 9
, Fair Value of Financial Instruments, and
Note 10
, Fair Value Measurements.
STOCK-BASED COMPENSATION –
The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to
Note 4
, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.
NEW ACCOUNTING STANDARDS
– In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.
In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.
2. ACQUISITION OF MGE
Effective September 1, 2013, Laclede Group completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, Laclede Group acquired MGE for a purchase price of
$975 million
. The acquisition was supported through a combination of the issuance of
10.0 million
shares of Laclede Group common stock, completed on May 29, 2013, the issuance by Laclede Gas of
$450.0 million
of first mortgage bonds, completed on August 13, 2013, short-term borrowings, and available cash.
The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded
$247.1 million
of goodwill as an asset in the consolidated balance sheet, which has been assigned to the Company’s Gas Utility segment.
As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.
Under Topic 805, merger-related transaction costs (such as advisory, legal, valuation and other professional fees) are not included as components of consideration transferred but are accounted for as expenses in the periods in which the costs are incurred. During the years ended
September 30, 2013
and 2012, Laclede Group incurred
$17.0 million
and
$0.2 million
, respectively, of third party pre-tax expenses associated with the transaction. These expenses are included in the Statement of Consolidated Income, with
$15.1 million
included in Other Operating Expenses and
$1.9 million
included in Interest on Long-term Debt.
61
On November 13, 2013, in accordance with Section 3.2 of the purchase agreement for MGE, the Utility provided to SUG a reconciliation of certain balance sheet accounts as of August 31, 2013, the date immediately prior to the closing of the acquisition to the initial valuation date of September 30, 2012. The resulting difference adjusts for changes in the actual net assets transferred to the Utility at closing from the level at September 30, 2012. Section 3.2 also contains a process to resolve any disagreements among the parties, and the Utility plans to adjust cash and goodwill for any change as a result of this process upon final settlement, which is anticipated to be in the first quarter of fiscal 2014.
The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:
|
(Thousands, Except Per Share Amounts)
|
September 1, 2013 - September 30, 2013
|
||
|
Total net revenues
|
$
|
21,985
|
|
|
Net Income
|
1,795
|
|
|
|
Earnings/(loss) per share:
|
|||
|
Basic
|
$
|
0.07
|
|
|
Diluted
|
$
|
0.07
|
|
62
The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:
|
(Thousands)
|
|||
|
Assets:
|
|||
|
Utility plant
|
$
|
671,793
|
|
|
Non-utility property
|
238
|
|
|
|
Other investments
|
3,096
|
|
|
|
Goodwill
|
247,078
|
|
|
|
Other Property and Investments
|
922,205
|
|
|
|
Accounts receivable:
|
|||
|
Utility
|
19,963
|
|
|
|
Other
|
6,119
|
|
|
|
Delayed customer billings
|
10,701
|
|
|
|
Inventories:
|
|||
|
Natural gas stored underground
|
58,679
|
|
|
|
Materials and supplies at average cost
|
3,988
|
|
|
|
Prepayments and other
|
487
|
|
|
|
Total Current Assets
|
99,937
|
|
|
|
Deferred Charges:
|
|||
|
Regulatory assets
|
84,014
|
|
|
|
Other
|
4,928
|
|
|
|
Total Deferred Charges
|
88,942
|
|
|
|
Total Assets Acquired
|
$
|
1,111,084
|
|
|
Liabilities:
|
|||
|
Accounts payable
|
$
|
20,154
|
|
|
Wages and compensation accrued
|
5,088
|
|
|
|
Customer deposits
|
8,362
|
|
|
|
Interest accrued
|
183
|
|
|
|
Taxes accrued
|
17,197
|
|
|
|
Other
|
12,620
|
|
|
|
Total Current Liabilities
|
63,604
|
|
|
|
Pension and postretirement benefit costs
|
24,466
|
|
|
|
Asset retirement obligations
|
32,056
|
|
|
|
Regulatory liabilities
|
2,249
|
|
|
|
Other
|
13,709
|
|
|
|
Total Deferred Credits and Other Liabilities
|
72,480
|
|
|
|
Total Liabilities Assumed
|
$
|
136,084
|
|
|
Net Assets Acquired
|
$
|
975,000
|
|
63
The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.
|
Twelve Months Ended September 30,
|
|||||||
|
(Thousands, Except Per Share Amounts)
|
2013
|
2012
|
|||||
|
Total net revenues
|
$
|
1,518,201
|
|
$
|
1,581,425
|
|
|
|
Net Income
|
83,642
|
|
81,722
|
|
|||
|
Earnings per share:
|
|||||||
|
Basic
|
$
|
2.57
|
|
$
|
2.52
|
|
|
|
Diluted
|
$
|
2.56
|
|
$
|
2.51
|
|
|
3. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS
This footnote includes all pension plans of the Company whether historical plans or those acquired as part of the purchase of certain assets and liabilities of MGE on September 1, 2013. The net pension and postretirement obligations were remeasured at that time as well as at the fiscal year end.
Pension Plans
The Utility has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Plan assets consist primarily of corporate and U.S. government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.
Pension costs in 2013,
2012
, and
2011
amounted to
$17.5 million
,
$20.1 million
, and
$14.3 million
, respectively, including amounts charged to construction.
The net periodic pension costs include the following components:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Service cost – benefits earned during the period
|
$
|
9,209
|
|
$
|
9,203
|
|
$
|
9,553
|
|
||
|
Interest cost on projected benefit obligation
|
16,959
|
|
19,358
|
|
18,819
|
|
|||||
|
Expected return on plan assets
|
(19,358
|
)
|
(19,595
|
)
|
(18,849
|
)
|
|||||
|
Amortization of prior service cost
|
544
|
|
592
|
|
642
|
|
|||||
|
Amortization of actuarial loss
|
10,724
|
|
9,040
|
|
10,228
|
|
|||||
|
Loss on lump-sum settlements
|
26,996
|
|
20,051
|
|
943
|
|
|||||
|
Sub-total
|
45,074
|
|
38,649
|
|
21,336
|
|
|||||
|
Regulatory adjustment
|
(27,532
|
)
|
(18,579
|
)
|
(7,066
|
)
|
|||||
|
Net pension cost
|
$
|
17,542
|
|
$
|
20,070
|
|
$
|
14,270
|
|
||
Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Current year actuarial loss (gain)
|
$
|
17,030
|
|
$
|
32,884
|
|
$
|
(13,485
|
)
|
||
|
Amortization of actuarial loss
|
(10,724
|
)
|
(29,091
|
)
|
(11,171
|
)
|
|||||
|
Acceleration of loss recognized due to settlement
|
(26,996
|
)
|
—
|
|
—
|
|
|||||
|
Amortization of prior service cost
|
(544
|
)
|
(592
|
)
|
(642
|
)
|
|||||
|
Sub-total
|
(21,234
|
)
|
3,201
|
|
(25,298
|
)
|
|||||
|
Regulatory adjustment
|
21,159
|
|
(3,510
|
)
|
24,533
|
|
|||||
|
Total recognized in other comprehensive income
|
$
|
(75
|
)
|
$
|
(309
|
)
|
$
|
(765
|
)
|
||
64
Pursuant to the provisions of the Utility pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a MoPSC Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds
100%
of the sum of service and interest costs. Lump-sum payments recognized as settlements during fiscal year 2013,
2012
, and
2011
were
$79.5 million
,
$60.1 million
, and
$2.3 million
, respectively.
Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a
four
-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds
10%
of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plan is based on an annual allowance of
$4.8 million
effective August 1, 2007 and
$15.5 million
effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of
$10.0 million
effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Benefit obligation, beginning of year
|
$
|
412,171
|
|
$
|
384,163
|
|
|
|
Service cost
|
9,209
|
|
9,203
|
|
|||
|
Interest cost
|
16,959
|
|
19,358
|
|
|||
|
Actuarial (gain) loss
|
(23,921
|
)
|
52,161
|
|
|||
|
MGE acquisition
|
151,424
|
|
—
|
|
|||
|
Settlement loss
|
24,999
|
|
14,348
|
|
|||
|
Gross benefits paid *
|
(87,023
|
)
|
(67,062
|
)
|
|||
|
Benefit obligation, end of year
|
$
|
503,818
|
|
$
|
412,171
|
|
|
|
Accumulated benefit obligation, end of year
|
$
|
444,129
|
|
$
|
353,061
|
|
|
|
*
|
Includes
$79,484
and
$60,085
lump-sum payments recognized as settlements in fiscal years
2013
and
2012
, respectively.
|
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Fair value of plan assets, beginning of year
|
$
|
274,130
|
|
$
|
247,959
|
|
|
|
Actual return on plan assets
|
3,387
|
|
53,220
|
|
|||
|
Employer contributions
|
27,991
|
|
40,013
|
|
|||
|
MGE acquisition
|
126,958
|
|
—
|
|
|||
|
Gross benefits paid *
|
(87,023
|
)
|
(67,062
|
)
|
|||
|
Fair value of plan assets, end of year
|
$
|
345,443
|
|
$
|
274,130
|
|
|
|
Funded status of plans, end of year
|
$
|
(158,375
|
)
|
$
|
(138,041
|
)
|
|
|
*
|
Includes
$79,484
and
$60,085
lump-sum payments recognized as settlements in fiscal years
2013
and
2012
, respectively.
|
65
The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Current liabilities
|
$
|
(442
|
)
|
$
|
(468
|
)
|
|
|
Noncurrent liabilities
|
(157,933
|
)
|
(137,573
|
)
|
|||
|
Total
|
$
|
(158,375
|
)
|
$
|
(138,041
|
)
|
|
|
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
|
|
|
|||||
|
Net actuarial loss
|
$
|
115,775
|
|
$
|
136,464
|
|
|
|
Prior service costs
|
4,467
|
|
5,011
|
|
|||
|
Sub-total
|
120,242
|
|
141,475
|
|
|||
|
Adjustments for amounts included in Regulatory Assets
|
(116,686
|
)
|
(137,845
|
)
|
|||
|
Total
|
$
|
3,556
|
|
$
|
3,630
|
|
|
At
September 30, 2013
, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year
2014
:
|
(Thousands)
|
2014
|
||
|
Amortization of net actuarial loss
|
$
|
7,088
|
|
|
Amortization of prior service cost
|
497
|
|
|
|
Sub-total
|
7,585
|
|
|
|
Regulatory adjustment
|
(7,196
|
)
|
|
|
Total
|
$
|
389
|
|
The assumptions used to calculate net periodic pension costs are as follows:
|
|
2013
|
2012
|
2011
|
||
|
Weighted average discount rate*
|
3.95%
|
5.10%
|
4.75%
|
||
|
Weighted average rate of future compensation increase
|
3.00%
|
3.00%
|
3.00%
|
||
|
Expected long-term rate of return on plan assets
|
7.75%
|
7.75%
|
8.00%
|
||
|
*
|
Weighted average discount rate assumption for the MGE pension plan is
5.05%
.
|
The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.
The assumptions used to calculate the benefit obligations are as follows:
|
|
2013
|
2012
|
|
|
Weighted average discount rate *
|
4.70%
|
3.95%
|
|
|
Weighted average rate of future compensation increase
|
3.00%
|
3.00%
|
|
|
*
|
Weighted average discount rate assumption for the MGE pension plan is
5.00%
.
|
Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Projected benefit obligation
|
$
|
503,818
|
|
$
|
412,171
|
|
|
|
Accumulated benefit obligation
|
444,129
|
|
353,061
|
|
|||
|
Fair value of plan assets
|
345,443
|
|
274,130
|
|
|||
66
Following are the targeted and actual plan assets by category as of September 30 of each year:
|
Target
|
2013
Actual
|
2012
Actual
|
||||||
|
Growth Strategy
|
|
|
|
|||||
|
Equity Markets
|
42.5
|
%
|
45.9
|
%
|
37.3
|
%
|
||
|
Commodities
|
2.5
|
%
|
1.6
|
%
|
2.2
|
%
|
||
|
Real Estate
|
2.5
|
%
|
3.0
|
%
|
2.2
|
%
|
||
|
Inflation-Indexed Securities
|
2.5
|
%
|
1.4
|
%
|
2.2
|
%
|
||
|
Debt Securities
|
50.0
|
%
|
43.3
|
%
|
41.1
|
%
|
||
|
Other*
|
—
|
%
|
4.8
|
%
|
15.0
|
%
|
||
|
Total
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
||
* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was
due to a transition taking place between investment managers and was invested in debt securities in a matter of days.
The Utility's investment policy is designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and he Utility’s tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, U.S. government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. During 2012, exposures to additional asset types were added to the target portfolio: commodities, real estate and inflation-indexed securities. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. The assets acquired with the MGE pension plan include diversified funds that are equity-oriented and larger holdings of cash. These are being evaluated along with the liabilities of the MGE plan. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.
Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
|
(Millions)
|
Pensions from
Qualified Trust
|
Pensions from
Laclede Gas
Funds
|
|||||
|
2014
|
$
|
22.9
|
|
$
|
0.4
|
|
|
|
2015
|
25.3
|
|
0.5
|
|
|||
|
2016
|
27.2
|
|
0.5
|
|
|||
|
2017
|
30.8
|
|
0.6
|
|
|||
|
2018
|
34.2
|
|
0.6
|
|
|||
|
2019 – 2023
|
227.2
|
|
4.5
|
|
|||
The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Contributions to the pension plans in fiscal year
2014
are anticipated to be
$24.0 million
into the qualified trusts, and
$0.4 million
into the non-qualified plans.
Postretirement Benefits
The Utility provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age
65
. The transition obligation not yet includible in postretirement benefit cost is being amortized over
20
years. Postretirement benefit costs in 2013,
2012
, and
2011
amounted to
$9.5 million
,
$9.5 million
, and
$9.1 million
, respectively, including amounts charged to construction.
67
Net periodic postretirement benefit costs consisted of the following components:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Service cost – benefits earned during the period
|
$
|
10,162
|
|
$
|
8,060
|
|
$
|
7,676
|
|
||
|
Interest cost on accumulated postretirement benefit obligation
|
5,234
|
|
5,521
|
|
4,843
|
|
|||||
|
Expected return on plan assets
|
(4,447
|
)
|
(3,965
|
)
|
(3,646
|
)
|
|||||
|
Amortization of transition obligation
|
93
|
|
136
|
|
136
|
|
|||||
|
Amortization of prior service credit
|
3
|
|
(2,072
|
)
|
(2,328
|
)
|
|||||
|
Amortization of actuarial loss
|
5,300
|
|
4,261
|
|
4,443
|
|
|||||
|
Sub-total
|
16,345
|
|
11,941
|
|
11,124
|
|
|||||
|
Regulatory adjustment
|
(6,821
|
)
|
(2,417
|
)
|
(2,071
|
)
|
|||||
|
Net postretirement benefit cost
|
$
|
9,524
|
|
$
|
9,524
|
|
$
|
9,053
|
|
||
Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Current year actuarial loss
|
$
|
16,300
|
|
$
|
10,138
|
|
$
|
1,696
|
|
||
|
Amortization of actuarial loss
|
(5,300
|
)
|
(4,261
|
)
|
(4,443
|
)
|
|||||
|
Amortization of prior service credit
|
(3
|
)
|
2,072
|
|
2,328
|
|
|||||
|
Amortization of transition obligation
|
(93
|
)
|
(136
|
)
|
(136
|
)
|
|||||
|
Sub-total
|
10,904
|
|
7,813
|
|
(555
|
)
|
|||||
|
Regulatory adjustment
|
(10,904
|
)
|
(7,813
|
)
|
555
|
|
|||||
|
Total recognized in other comprehensive income
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
||
Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds
10%
of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' postretirement benefit plans is based on an annual allowance of
$7.6 million
effective August 1, 2007 and
$9.5 million
effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Benefit obligation, beginning of year
|
$
|
127,217
|
|
$
|
103,991
|
|
|
|
Service cost
|
10,162
|
|
8,060
|
|
|||
|
Interest cost
|
5,234
|
|
5,521
|
|
|||
|
Actuarial loss (gain)
|
17,514
|
|
15,895
|
|
|||
|
MGE acquisition
|
28,444
|
|
—
|
|
|||
|
Gross benefits paid
|
(8,449
|
)
|
(6,250
|
)
|
|||
|
Benefit obligation, end of year
|
$
|
180,122
|
|
$
|
127,217
|
|
|
68
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Fair value of plan assets at beginning of year
|
$
|
67,442
|
|
$
|
51,744
|
|
|
|
Actual return on plan assets
|
5,660
|
|
9,722
|
|
|||
|
Employer contributions
|
16,596
|
|
12,226
|
|
|||
|
MGE acquisition
|
30,396
|
|
—
|
|
|||
|
Gross benefits paid
|
(8,449
|
)
|
(6,250
|
)
|
|||
|
Fair value of plan assets, end of year
|
$
|
111,645
|
|
$
|
67,442
|
|
|
|
Funded status of plans, end of year
|
$
|
(68,477
|
)
|
$
|
(59,775
|
)
|
|
The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Noncurrent assets
|
$
|
2,543
|
|
$
|
—
|
|
|
|
Current liabilities
|
(300
|
)
|
(790
|
)
|
|||
|
Noncurrent liabilities
|
(70,720
|
)
|
(58,985
|
)
|
|||
|
Total
|
$
|
(68,477
|
)
|
$
|
(59,775
|
)
|
|
|
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
|
|
|
|||||
|
Net actuarial loss
|
$
|
63,573
|
|
$
|
52,573
|
|
|
|
Prior service credit
|
(27
|
)
|
(24
|
)
|
|||
|
Transition obligation
|
—
|
|
93
|
|
|||
|
Sub-total
|
63,546
|
|
52,642
|
|
|||
|
Adjustments for amounts included in Regulatory Assets
|
(63,546
|
)
|
(52,642
|
)
|
|||
|
Total
|
$
|
—
|
|
$
|
—
|
|
|
At
September 30, 2013
, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:
|
(Thousands)
|
|
||
|
Amortization of net actuarial loss
|
$
|
6,021
|
|
|
Amortization of prior service cost
|
(4
|
)
|
|
|
Sub-total
|
6,017
|
|
|
|
Regulatory adjustment
|
(6,017
|
)
|
|
|
Total
|
$
|
—
|
|
The assumptions used to calculate net periodic postretirement benefit costs are as follows:
|
|
2013
|
2012
|
2011
|
|||||
|
Weighted average discount rate *
|
3.80
|
%
|
5.05
|
%
|
4.70
|
%
|
||
|
Weighted average rate of future compensation increase
|
3.00
|
%
|
3.00
|
%
|
3.00
|
%
|
||
|
Expected long-term rate of return on plan assets **
|
7.75
|
%
|
7.75
|
%
|
8.00
|
%
|
||
|
*
|
Weighted average discount rate assumption for the MGE postretirement plan is
5.05%
.
|
** Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is
5.75%
.
The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.
69
The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:
|
|
2013
|
2012
|
|
|
Weighted average discount rate *
|
4.60%
|
3.80%
|
|
|
Weighted average rate of future compensation increase
|
3.00%
|
3.00%
|
|
|
*
|
Weighted average discount rate assumption for the MGE postretirement plan is
4.95%
.
|
The assumed medical cost trend rates at September 30 are as follows:
|
|
2013
|
2012
|
|
|
Medical cost trend assumed for next year
|
7.50%
|
7.00%
|
|
|
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)
|
5.00%
|
5.00%
|
|
|
Year the rate reaches the ultimate trend
|
2020
|
2017
|
|
The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:
|
(Thousands)
|
1% Increase
|
1% Decrease
|
|||||
|
Effect on net periodic postretirement benefit cost
|
$
|
1,520
|
|
$
|
(1,390
|
)
|
|
|
Effect on accumulated postretirement benefit obligation
|
7,060
|
|
(6,580
|
)
|
|||
Following are the targeted and actual plan assets by category as of September 30 of each year:
|
Target
|
2013
Actual
|
2012
Actual
|
||||||
|
Equity Securities
|
60.0
|
%
|
59.0
|
%
|
59.0
|
%
|
||
|
Debt Securities
|
40.0
|
%
|
39.0
|
%
|
39.0
|
%
|
||
|
Other
|
—
|
%
|
2.0
|
%
|
2.0
|
%
|
||
|
Total
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
||
Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association and Rabbi trusts as its external funding mechanisms. The Utility’s investment policy seeks to maximize investment returns consistent with the Utility's tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. The Utility's current investment policy targets an asset allocation of
60%
to equity securities and
40%
to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. The Utility currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across U.S. stock and bond markets.
Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
|
(Millions)
|
Benefits Paid
from
Qualified Trust
|
Benefits Paid
from Laclede Gas
Funds
|
|||||
|
2014
|
$
|
9.5
|
|
$
|
0.3
|
|
|
|
2015
|
9.9
|
|
0.3
|
|
|||
|
2016
|
10.7
|
|
0.3
|
|
|||
|
2017
|
11.7
|
|
0.4
|
|
|||
|
2018
|
12.8
|
|
0.4
|
|
|||
|
2019 – 2023
|
84.1
|
|
2.2
|
|
|||
The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year
2014
are anticipated to be
$19.2 million
to the qualified trusts, and
$0.3 million
paid directly to participants from Laclede Gas funds.
70
Other Plans
The Utility sponsors 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. The Utility provides a match of such contributions within specific limits. The cost of the defined contribution plans of the Utility amounted to
$5.0 million
,
$3.8 million
, and
$3.6 million
for fiscal years 2013,
2012
, and
2011
, respectively.
Fair Value Measurements of Pension and Other Postretirement Plan Assets
The table below categorizes the fair value measurements of the Utility's’ pension plan assets:
|
(Thousands)
|
Quoted
Prices in
Active
Markets
(Level 1)
|
Significant
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Total
|
|||||||||||
|
As of September 30, 2013
|
|
|
|
|
|||||||||||
|
Cash and cash equivalents
|
$
|
18,177
|
|
$
|
—
|
|
$
|
—
|
|
$
|
18,177
|
|
|||
|
Stock/Bond mutual fund
|
—
|
|
115,817
|
|
—
|
|
115,817
|
|
|||||||
|
Debt Securities
|
|
|
|
|
|||||||||||
|
U.S. bond mutual funds
|
17,682
|
|
—
|
|
—
|
|
17,682
|
|
|||||||
|
U.S. government
|
—
|
|
55,743
|
|
—
|
|
55,743
|
|
|||||||
|
U.S. corporate
|
—
|
|
110,925
|
|
—
|
|
110,925
|
|
|||||||
|
U.S. municipal
|
—
|
|
6,799
|
|
—
|
|
6,799
|
|
|||||||
|
International
|
—
|
|
21,594
|
|
—
|
|
21,594
|
|
|||||||
|
Derivative instruments (a)
|
—
|
|
(1,294
|
)
|
—
|
|
(1,294
|
)
|
|||||||
|
Total
|
$
|
35,859
|
|
$
|
309,584
|
|
$
|
—
|
|
$
|
345,443
|
|
|||
|
As of September 30, 2012
|
|
|
|
|
|||||||||||
|
Cash and cash equivalents
|
$
|
57,614
|
|
$
|
—
|
|
$
|
—
|
|
$
|
57,614
|
|
|||
|
Debt Securities
|
|
|
|
|
|||||||||||
|
U.S. bond mutual funds
|
36,767
|
|
—
|
|
—
|
|
36,767
|
|
|||||||
|
U.S. government
|
—
|
|
57,925
|
|
—
|
|
57,925
|
|
|||||||
|
U.S. corporate
|
—
|
|
93,169
|
|
—
|
|
93,169
|
|
|||||||
|
U.S. municipal
|
—
|
|
9,493
|
|
—
|
|
9,493
|
|
|||||||
|
International
|
—
|
|
18,885
|
|
—
|
|
18,885
|
|
|||||||
|
Derivative instruments (b)
|
—
|
|
277
|
|
—
|
|
277
|
|
|||||||
|
Total
|
$
|
94,381
|
|
$
|
179,749
|
|
$
|
—
|
|
$
|
274,130
|
|
|||
|
(a)
|
Derivative assets of
$4,186
net of cash margin payable of
$5,480
.
|
|
(b)
|
Derivative assets of
$3,027
net of cash margin payable of
$2,750
.
|
71
The table below categorizes the fair value measurements of The Utility's postretirement plan assets:
|
(Thousands)
|
Quoted
Prices in
Active
Markets
(Level 1)
|
Significant
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Total
|
|||||||||||
|
As of September 30, 2013
|
|
|
|
|
|||||||||||
|
Cash and cash equivalents
|
$
|
1,411
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1,411
|
|
|||
|
U.S. stock/bond mutual fund
|
110,234
|
|
—
|
|
—
|
|
110,234
|
|
|||||||
|
Total
|
$
|
111,645
|
|
$
|
—
|
|
$
|
—
|
|
$
|
111,645
|
|
|||
|
As of September 30, 2012
|
|
|
|
|
|||||||||||
|
Cash and cash equivalents
|
$
|
1,106
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1,106
|
|
|||
|
U.S. stock/bond mutual fund
|
66,336
|
|
—
|
|
—
|
|
66,336
|
|
|||||||
|
Total
|
$
|
67,442
|
|
$
|
—
|
|
$
|
—
|
|
$
|
67,442
|
|
|||
Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.
4. STOCK-BASED COMPENSATION
The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan) was amended and approved at the annual meeting of shareholders of Laclede Group on January 26, 2012, as discussed below. The purpose of the 2006 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2006 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2006 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. Effective February 1, 2012, members of the Company’s Board of Directors are also eligible to participate in the 2006 Plan and no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors. The 2006 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2006 Plan generally provides a minimum vesting period of at least
three
years for each type of award, with pro rata vesting permitted during the minimum
three
year vesting period. The maximum number of shares reserved for issuance under the 2006 Plan is
1,250,000
. The 2006 Plan replaced the Laclede Group Equity Incentive Plan (the 2003 Plan). Shares reserved under the 2003 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2006 Plan.
The Company issues new shares to satisfy employee restricted stock awards and stock option exercises. Prior to February 1, 2012, shares for non-employee directors were purchased on the open market.
Restricted Stock Awards
During fiscal year
2013
, the Company granted
108,419
performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of
$34.49
per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.
The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years
2012
and
2011
was
$36.55
and
$30.68
per share, respectively.
72
Fiscal year
2013
activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:
|
Shares/
Units
|
Weighted
Average
Grant Date
Fair Value
|
|||||
|
Nonvested at September 30, 2012
|
232,403
|
|
$
|
30.89
|
|
|
|
Granted (maximum shares that can be earned)
|
108,419
|
|
$
|
34.49
|
|
|
|
Vested
|
(47,436
|
)
|
$
|
27.61
|
|
|
|
Forfeited
|
(51,118
|
)
|
$
|
26.11
|
|
|
|
Nonvested at September 30, 2013
|
242,268
|
|
$
|
34.15
|
|
|
During fiscal year
2013
, the Company granted
43,924
shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of
$40.03
per share. These shares were awarded on October 1, 2012 and December 3, 2012 and vest October 1, 2014 and December 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year
2012
and
2011
was
$39.72
and
$35.93
per share, respectively.
During fiscal year
2013
, the Company granted
15,200
shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of
$39.92
per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years
2012
and
2011
was
$41.36
and
$39.48
per share, respectively. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquired the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant under The Laclede Group 2006 Equity Incentive Plan.
Time-vested restricted stock and stock unit activity for fiscal year
2013
is presented below:
|
Shares/
Units
|
Weighted
Average
Grant Date
Fair Value
|
|||||
|
Nonvested at September 30, 2012
|
115,115
|
|
$
|
36.54
|
|
|
|
Granted
|
59,124
|
|
$
|
40.00
|
|
|
|
Vested
|
(43,785
|
)
|
$
|
34.95
|
|
|
|
Forfeited
|
(11,050
|
)
|
$
|
38.61
|
|
|
|
Nonvested at September 30, 2013
|
119,404
|
|
$
|
38.64
|
|
|
During fiscal year
2013
,
91,221
shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2008, December 1, 2009, January 4, 2010, May 3, 2010, and July 1, 2010 vested. The Company withheld
23,311
of the vested shares at a weighted average price of
$39.96
per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year
2012
,
90,839
shares of restricted stock (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld
30,052
of these vested shares at a weighted average price of
$40.02
per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year
2011
,
94,500
shares of performance-contingent restricted stock, awarded on December 5, 2007, vested. The Company withheld
32,373
of these vested shares at a weighted average price of
$35.90
per share pursuant to elections by employees to satisfy tax withholding obligations.
The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years
2013
,
2012
, and
2011
was
$3.8 million
,
$4.2 million
, and
$3.6 million
, respectively, and the related actual tax benefit realized was
$1.4 million
,
$1.6 million
, and
$1.4 million
, respectively.
73
Stock Option Awards
No stock options were granted during fiscal years
2013
,
2012
, and
2011
. Stock option activity for fiscal year
2013
is presented below:
|
Stock
Options
|
Weighted
Average
Exercise
Price
|
Weighted
Average
Remaining
Contractual
Term
(Years)
|
Aggregate
Intrinsic
Value
($000)
|
|||||||||
|
Outstanding at September 30, 2012
|
214,000
|
|
$
|
31.02
|
|
|
|
|||||
|
Granted
|
—
|
|
$
|
—
|
|
|
|
|||||
|
Exercised
|
(80,500
|
)
|
$
|
29.61
|
|
|
|
|||||
|
Forfeited
|
—
|
|
$
|
—
|
|
|
|
|||||
|
Expired
|
—
|
|
$
|
—
|
|
|
|
|||||
|
Outstanding at September 30, 2013
|
133,500
|
|
$
|
31.87
|
|
2.8
|
$
|
1,752
|
|
|||
|
Fully Vested and Expected to Vest at September 30, 2013
|
133,500
|
|
$
|
31.87
|
|
2.8
|
$
|
1,752
|
|
|||
|
Exercisable at September 30, 2013
|
133,500
|
|
$
|
31.87
|
|
2.8
|
$
|
1,752
|
|
|||
Exercise prices of options outstanding at
September 30, 2013
range from
$28.85
to
$34.95
. During fiscal year
2013
, cash received from the exercise of stock options was
$2.7 million
, the intrinsic value of the options exercised was
$1.0 million
and the related actual tax benefit realized was
$0.4 million
. During fiscal year
2012
, cash received from the exercise of stock options was
$2.5 million
, the intrinsic value of the options exercised was
$1.0 million
and the related actual tax benefit realized was
$0.4 million
. During fiscal year
2011
, cash received from the exercise of stock options was
$0.9 million
, the intrinsic value of the options exercised was
$0.2
million and the related actual tax benefit realized was
$0.1
million.
The closing price of the Company’s common stock was
$45.00
at
September 30, 2013
.
Equity Compensation Costs
Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.
The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, is estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate U.S. Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years
2013
,
2012
, and
2011
was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:
|
|
2013
|
2012
|
2011
|
|||||
|
Risk free interest rate
|
0.32
|
%
|
0.39
|
%
|
0.79
|
%
|
||
|
Expected dividend yield of stock
|
—
|
|
—
|
|
—
|
|
||
|
Expected volatility of stock
|
19.60
|
%
|
23.21
|
%
|
33.42
|
%
|
||
|
Vesting period
|
2.8 years
|
|
2.8 years
|
|
2.8 years
|
|
||
74
The risk free interest rate was based on the yield on U.S. Treasury securities matching the vesting period. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.
The amounts of compensation cost recognized for share-based compensation arrangements are presented below:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Total equity compensation cost
|
$
|
4,453
|
|
$
|
2,707
|
|
$
|
3,980
|
|
||
|
Compensation cost capitalized
|
(1,366
|
)
|
(808
|
)
|
(924
|
)
|
|||||
|
Compensation cost recognized in net income
|
3,087
|
|
1,899
|
|
3,056
|
|
|||||
|
Income tax benefit recognized in net income
|
(1,182
|
)
|
(733
|
)
|
(1,179
|
)
|
|||||
|
Compensation cost recognized in net income, net of income tax
|
1,905
|
|
1,166
|
|
1,877
|
|
|||||
As of
September 30, 2013
, there was
$4.9 million
of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of
2.0
years.
5. EARNINGS PER COMMON SHARE
|
(Thousands, Except Per Share Amounts)
|
2013
|
2012
|
2011
|
||||||||
|
Basic EPS:
|
|
|
|
||||||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Less: Income allocated to participating securities
|
245
|
|
340
|
|
497
|
|
|||||
|
Net Income Available to Common Shareholders
|
$
|
52,513
|
|
$
|
62,300
|
|
$
|
63,328
|
|
||
|
Weighted Average Shares Outstanding
|
25,875
|
|
22,262
|
|
22,099
|
|
|||||
|
Earnings Per Share of Common Stock
|
$
|
2.03
|
|
$
|
2.80
|
|
$
|
2.87
|
|
||
|
Diluted EPS:
|
|
|
|
||||||||
|
Net Income
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Less: Income allocated to participating securities
|
245
|
|
340
|
|
496
|
|
|||||
|
Net Income Available to Common Shareholders
|
$
|
52,513
|
|
$
|
62,300
|
|
$
|
63,329
|
|
||
|
Weighted Average Shares Outstanding
|
25,875
|
|
22,262
|
|
22,099
|
|
|||||
|
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units
|
77
|
|
78
|
|
72
|
|
|||||
|
Weighted Average Diluted Shares
|
25,952
|
|
22,340
|
|
22,171
|
|
|||||
|
Earnings Per Share of Common Stock
|
$
|
2.02
|
|
$
|
2.79
|
|
$
|
2.86
|
|
||
|
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
|
|
|
|
||||||||
|
Antidilutive stock options
|
—
|
|
—
|
|
—
|
|
|||||
|
Restricted stock and stock units subject to performance and/or market conditions
|
188
|
|
195
|
|
203
|
|
|||||
|
Total
|
188
|
|
195
|
|
203
|
|
|||||
6. STOCKHOLDER'S EQUITY
Total shares of common stock outstanding were
32.70 million
and
22.54 million
at
September 30, 2013
and
2012
, respectively.
Common stock and paid-in capital increased
$435.8 million
in fiscal year
2013
. The issuance of
44,074
common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by
$1.8 million
. The remaining
$434.0 million
increase was due to the issuance of
10,005,000
shares in May 2013, stock-based compensation costs and the issuance of
108,331
shares of common stock under the Equity Incentive Plan. Common stock and paid-in capital increased
$5.0 million
in fiscal year
2012
. The issuance of
46,107
common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by
$1.8 million
. The remaining
$3.2 million
increase was primarily due to stock-based compensation costs and the issuance of
62,590
shares of common stock under the Equity Incentive Plan. Substantially all of the Utility's plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock.
75
These provisions are applicable regardless of whether the stock is publicly held or, as has been the case since the formation of Laclede Group, held solely by the Utility’s parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953, would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of
$8 million
plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953, to the last day of the quarter before the declaration or payment date for the dividends. As of
September 30, 2013
and
2012
, the amount under the mortgage’s formula that was available to pay dividends was
$833 million
and
$355 million
, respectively. Thus, all of the Utility’s retained earnings were free from such restrictions as of those dates. The substantial increase in 2013 was primarily due to the issuance of stock to Laclede Group to fund a portion of the MGE acquisition.
Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to
285,222
shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were
194,246
and
186,919
shares at
September 30, 2013
and November 26,
2013
, respectively, remaining available for issuance under this Form S-3. The Company filed this Form S-3 on July 29, 2011.
On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire August 5, 2016. Bonds totaling
$450 million
were issued by Laclede Gas from this shelf registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.
The Utility has authority from the MoPSC to issue up to
$518 million
in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional
two years
, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At
September 30, 2013
,
$370.8 million
remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.
The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the
Consolidated Balance Sheets at September 30 were as follows:
|
(Thousands)
|
Net Unrealized Gains (Losses) on Cash Flow Hedges
|
Defined Benefit Pension and Other
Postretirement
Benefit Plans
|
Total
|
||||||||
|
Balance at September 30, 2011
|
$
|
320
|
|
$
|
(2,420
|
)
|
$
|
(2,100
|
)
|
||
|
Current-period change
|
(2,206
|
)
|
190
|
|
(2,016
|
)
|
|||||
|
Balance at September 30, 2012
|
(1,886
|
)
|
(2,230
|
)
|
(4,116
|
)
|
|||||
|
Current-period change
|
3,281
|
|
48
|
|
3,329
|
|
|||||
|
Balance at September 30, 2013
|
1,395
|
|
(2,182
|
)
|
(787
|
)
|
|||||
Income tax expense (benefit) recorded for items of other comprehensive income reported in the Statements of Consolidated Comprehensive Income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period.
|
7.
|
LONG-TERM DEBT
|
Maturities on long-term debt for the five fiscal years subsequent to
September 30, 2013
are as follows:
|
2014
|
—
|
|
|
|
2015
|
—
|
|
|
|
2016
|
—
|
|
|
|
2017
|
—
|
|
|
|
2018
|
$
|
100
|
million
|
76
On October 15, 2012, the Utility paid at maturity
$25 million
principal amount of 6 1/2% first mortgage bonds. This maturity was funded through short-term borrowings. Laclede Group issued
$25 million
of
3.31%
10
-year unsecured notes in a private placement on December 14, 2012 and the Utility issued
$100 million
of first mortgage bonds in a private placement on March 15, 2013, that had been committed to in August 2012. Of this
$100 million
,
$55 million
were issued at
3.00%
for a
10
-year term, maturing in March 2023, and
$45 million
were issued at
3.40%
for a
15
-year term, maturing in March 2028. The proceeds were used for the repayment of short-term debt and general corporate purposes. The Utility issued
$450 million
of first mortgage bonds on August 13, 2013. Of this
$450 million
,
$100 million
was issued at
2.00%
maturing in August 2018,
$250 million
was issued at
3.40%
maturing in August 2023, and
$100 million
was issued at
4.625%
maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.
At
September 30, 2013
, the Company had fixed-rate long-term debt totaling
$915 million
. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of the Company’s
$915 million
in long-term debt,
$50 million
have no call options,
$435 million
have make-whole call options,
$350 million
are callable at par three to six months prior to maturity and
$80 million
are callable at par beginning in October 2013. None of the debt has any put options.
On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which expires August 5, 2016. Bonds totaling
$450 million
were issued by Laclede Gas from this registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under these shelf registrations will depend on cash requirements and market conditions.
The Utility has authority from the MoPSC to issue up to
$518 million
in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional
two
years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At November 26, 2013,
$370.8 million
remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.
Substantially all of the Utility plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock, which are described more fully in
Note 6
, Stockholders’ Equity.
At
September 30, 2013
and
2012
, the Utility had authorized
1,480,000
shares of preferred stock, but none were issued and outstanding.
For information on additional financing commitments, refer to
Note 16
, Commitments and Contingencies.
|
8.
|
NOTES PAYABLE AND CREDIT AGREEMENTS
|
The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. On September 3, 2013, the Utility entered into a new syndicated line of credit for
$450 million
with
nine
banks, which will expire in September 2018. The largest portion provided by a single bank is
15.6%
. The previous syndicated line of credit agreement was terminated at that time.
The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than
70%
of total capitalization. On
September 30, 2013
, total debt was
48%
of total capitalization.
77
Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for
2013
and
2012
:
|
|
Commercial Paper Borrowings
|
|
Twelve Months Ended September 30, 2013
|
|
|
Weighted average borrowings outstanding
|
$34.2 million
|
|
Weighted average interest rate
|
0.3%
|
|
Range of borrowings outstanding
|
$0 – $99.4 million
|
|
As of September 30, 2013
|
|
|
Borrowings outstanding at end of period
|
$74.0 million
|
|
Weighted average interest rate
|
0.3%
|
|
Twelve Months Ended September 30, 2012
|
|
|
Weighted average borrowings outstanding
|
$43.8 million
|
|
Weighted average interest rate
|
0.3%
|
|
Range of borrowings outstanding
|
$0 – $133.5 million
|
|
As of September 30, 2012
|
|
|
Borrowings outstanding at end of period
|
$40.1 million
|
|
Weighted average interest rate
|
0.2%
|
Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On September 3, 2013, Laclede Group entered into a new
$150 million
in a syndicated line of credit, which expires September 2018. The previous syndicated line of credit agreement was terminated at that time. Laclede Group's line of credit has covenants limiting the total debt of the consolidated Laclede Group to no more than
70%
of the Company’s total capitalization. This ratio stood at
49%
on September 30, 2013. Occasionally, Laclede Group’s lines may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s lines during fiscal years
2013
and
2012
.
|
9.
|
FAIR VALUE OF FINANCIAL INSTRUMENTS
|
The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at
September 30, 2013
and
2012
are as follows:
|
|
|
|
Classification of Estimated Fair Value
|
||||||||||||||||
|
(Thousands)
|
Carrying
Amount
|
Fair
Value
|
Quoted
Prices in Active Markets
(Level 1)
|
Significant Observable Inputs
(Level 2)
|
Significant Unobservable Inputs
(Level 3)
|
||||||||||||||
|
As of September 30, 2013
|
|
|
|
|
|
||||||||||||||
|
Cash and cash equivalents
|
$
|
52,981
|
|
$
|
52,981
|
|
$
|
52,824
|
|
$
|
157
|
|
$
|
—
|
|
||||
|
Short-term debt
|
74,000
|
|
74,000
|
|
—
|
|
74,000
|
|
—
|
|
|||||||||
|
Long-term debt, including current portion
|
912,712
|
|
954,126
|
|
—
|
|
954,126
|
|
—
|
|
|||||||||
|
As of September 30, 2012
|
|
|
|
|
|
||||||||||||||
|
Cash and cash equivalents
|
$
|
27,457
|
|
$
|
27,457
|
|
$
|
17,380
|
|
$
|
10,077
|
|
$
|
—
|
|
||||
|
Short-term debt
|
40,100
|
|
40,100
|
|
—
|
|
40,100
|
|
—
|
|
|||||||||
|
Long-term debt, including current portion
|
364,416
|
|
452,768
|
|
—
|
|
452,768
|
|
—
|
|
|||||||||
The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to
Note 10
, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.
78
10. FAIR VALUE MEASUREMENTS
The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.
|
(Thousands)
|
Quoted
Prices in
Active
Markets
(Level 1)
|
Significant
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Effects of Netting and Cash Margin Receivables
/Payables
|
Total
|
||||||||||||||
|
As of September 30, 2013
|
|
|
|
|
|
||||||||||||||
|
Assets
|
|
|
|
|
|
||||||||||||||
|
U. S. Stock/Bond Mutual Funds
|
$
|
14,500
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
14,500
|
|
||||
|
NYMEX/ICE natural gas contracts
|
4,333
|
|
330
|
|
—
|
|
(2,145
|
)
|
$
|
2,518
|
|
||||||||
|
OTCBB natural gas contracts
|
—
|
|
232
|
|
—
|
|
(232
|
)
|
—
|
|
|||||||||
|
NYMEX gasoline and heating oil contracts
|
105
|
|
—
|
|
—
|
|
(105
|
)
|
$
|
—
|
|
||||||||
|
Natural gas commodity contracts
|
—
|
|
1,129
|
|
150
|
|
(495
|
)
|
$
|
784
|
|
||||||||
|
Total
|
$
|
18,938
|
|
$
|
1,691
|
|
$
|
150
|
|
$
|
(2,977
|
)
|
$
|
17,802
|
|
||||
|
Liabilities
|
|
|
|
|
|
||||||||||||||
|
NYMEX/ICE natural gas contracts
|
$
|
3,687
|
|
$
|
321
|
|
$
|
—
|
|
$
|
(4,008
|
)
|
$
|
—
|
|
||||
|
OTCBB natural gas contracts
|
—
|
|
5,443
|
|
—
|
|
(232
|
)
|
$
|
5,211
|
|
||||||||
|
NYMEX gasoline and heating oil contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
$
|
—
|
|
||||||||
|
Natural gas commodity contracts
|
—
|
|
1,140
|
|
40
|
|
(495
|
)
|
$
|
685
|
|
||||||||
|
Total
|
$
|
3,687
|
|
$
|
6,904
|
|
$
|
40
|
|
$
|
(4,735
|
)
|
$
|
5,896
|
|
||||
|
As of September 30, 2012
|
|
|
|
|
|
||||||||||||||
|
Assets
|
|
|
|
|
|
||||||||||||||
|
U. S. Stock/Bond Mutual Funds
|
$
|
13,187
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
13,187
|
|
||||
|
NYMEX/ICE natural gas contracts
|
7,411
|
|
994
|
|
—
|
|
(8,405
|
)
|
$
|
—
|
|
||||||||
|
NYMEX gasoline and heating oil contracts
|
344
|
|
—
|
|
—
|
|
(344
|
)
|
$
|
—
|
|
||||||||
|
Natural gas commodity contracts
|
—
|
|
3,060
|
|
113
|
|
(299
|
)
|
$
|
2,874
|
|
||||||||
|
Total
|
$
|
20,942
|
|
$
|
4,054
|
|
$
|
113
|
|
$
|
(9,048
|
)
|
$
|
16,061
|
|
||||
|
Liabilities
|
|
|
|
|
|
||||||||||||||
|
NYMEX/ICE natural gas contracts
|
$
|
12,253
|
|
$
|
1,891
|
|
$
|
—
|
|
$
|
(14,144
|
)
|
$
|
—
|
|
||||
|
NYMEX gasoline and heating oil contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
$
|
—
|
|
||||||||
|
Natural gas commodity contracts
|
—
|
|
428
|
|
4
|
|
(299
|
)
|
$
|
133
|
|
||||||||
|
Total
|
$
|
12,253
|
|
$
|
2,319
|
|
$
|
4
|
|
$
|
(14,443
|
)
|
$
|
133
|
|
||||
The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Beginning of period
|
$
|
109
|
|
$
|
13
|
|
|
|
Settlements
|
(269
|
)
|
(54
|
)
|
|||
|
Net losses related to derivatives not held at end of period
|
(99
|
)
|
(68
|
)
|
|||
|
Net gains related to derivatives still held at end of period
|
369
|
|
218
|
|
|||
|
End of period
|
$
|
110
|
|
$
|
109
|
|
|
79
The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see
Note 11
, Derivative Instruments and Hedging Activities.
|
11.
|
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
|
The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to
70%
of its normal volumes purchased for up to a
36
-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.
From time to time, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At
September 30, 2013
, Laclede Gas held
0.3 million
gallons of gasoline futures contracts at an average price of
$2.23
per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.
In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At
September 30, 2013
, the fair values of
67.4 million
MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts,
58.5 million
MMBtu will settle during fiscal year 2014,
8.1 million
MMBtu will settle during fiscal year 2015, while the remaining
0.8 million
MMBtu will settle during fiscal year 2016. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins. At
September 30, 2013
, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.
Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at
September 30, 2013
, it is expected that approximately
$2.3 million
of pretax losses will be reclassified into the Statements of Consolidated Income during fiscal year 2014. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.
80
The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at
September 30, 2013
were as follows:
|
|
Laclede Gas Company
|
Laclede Energy
Resources, Inc.
|
|||||||||||
|
|
MMBtu
(millions)
|
Avg. Price
Per
MMBtu
|
MMBtu
(millions)
|
Avg. Price
Per
MMBtu
|
|||||||||
|
NYMEX/ICE open short futures/swap positions
|
|
|
|
|
|||||||||
|
Fiscal 2014
|
—
|
|
$
|
—
|
|
12.91
|
|
$
|
3.98
|
|
|||
|
Fiscal 2015
|
—
|
|
—
|
|
0.06
|
|
4.21
|
|
|||||
|
NYMEX/ICE open long futures/swap positions
|
|
|
|
|
|||||||||
|
Fiscal 2014
|
7.26
|
|
$
|
3.99
|
|
1.71
|
|
$
|
3.94
|
|
|||
|
Fiscal 2015
|
0.94
|
|
3.84
|
|
0.19
|
|
4.06
|
|
|||||
|
Fiscal 2016
|
—
|
|
—
|
|
0.02
|
|
4.15
|
|
|||||
|
OTCBB open long futures
|
|||||||||||||
|
Fiscal 2014
|
16.81
|
|
$
|
3.97
|
|
—
|
|
$
|
—
|
|
|||
|
Fiscal 2015
|
7.58
|
|
4.22
|
|
—
|
|
—
|
|
|||||
At
September 30, 2013
, the Utility and LER also had
23.6 million
MMBtu and
0.0 million
MMBtu, respectively, of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.
In February 2013, Laclede Group entered into certain interest rate swap agreements, with a notional amount of
$355 million
, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Missouri Gas Energy (MGE). These derivative instruments had been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2013, the interest rate swap agreements were terminated and the settlement resulted in a
$20.8 million
gain by Laclede Group. The Company assigned the gain as a regulatory liability since the interest rate swaps were entered into to hedge the interest payments on the
$450 million
of long-term debt issued on August 13, 2013 by Laclede Gas.
81
|
|
||||||||||||
|
|
Location of Gain (Loss)
|
|
|
|
||||||||
|
(Thousands)
|
Recorded in Income
|
2013
|
2012
|
2011
|
||||||||
|
Derivatives in Cash Flow Hedging Relationships
|
|
|
|
|||||||||
|
Effective portion of gain (loss) recognized in OCI on derivatives:
|
|
|
|
|||||||||
|
NYMEX/ICE natural gas contracts
|
|
$
|
4,923
|
|
$
|
4,505
|
|
$
|
5,226
|
|
||
|
NYMEX gasoline and heating oil contracts
|
|
123
|
|
297
|
|
355
|
|
|||||
|
Total
|
|
$
|
5,046
|
|
$
|
4,802
|
|
$
|
5,581
|
|
||
|
Effective portion of gain (loss) reclassified from AOCI to income:
|
|
|
|
|||||||||
|
NYMEX/ICE natural gas contracts
|
Gas Marketing Operating Revenues
|
$
|
(4
|
)
|
$
|
18,929
|
|
$
|
7,443
|
|
||
|
|
Gas Marketing Operating Expenses
|
(509
|
)
|
(10,532
|
)
|
(9,770
|
)
|
|||||
|
Sub-total
|
|
$
|
(513
|
)
|
$
|
8,397
|
|
$
|
(2,327
|
)
|
||
|
NYMEX gasoline and heating oil contracts
|
Gas Utility Other Operation Expenses
|
211
|
|
—
|
|
466
|
|
|||||
|
Total
|
|
$
|
(302
|
)
|
$
|
8,397
|
|
$
|
(1,861
|
)
|
||
|
Ineffective portion of gain (loss) on derivatives
recognized in income:
|
|
|
|
|
||||||||
|
NYMEX/ICE natural gas contracts
|
Gas Marketing Operating Revenues
|
$
|
(420
|
)
|
$
|
(36
|
)
|
$
|
966
|
|
||
|
|
Gas Marketing Operating Expenses
|
(239
|
)
|
(263
|
)
|
(1,322
|
)
|
|||||
|
Sub-total
|
|
$
|
(659
|
)
|
$
|
(299
|
)
|
$
|
(356
|
)
|
||
|
NYMEX gasoline and heating oil contracts
|
Gas Utility Other Operation Expenses
|
(127
|
)
|
175
|
|
12
|
|
|||||
|
Total
|
|
$
|
(786
|
)
|
$
|
(124
|
)
|
$
|
(344
|
)
|
||
|
Derivatives Not Designated as Hedging Instruments*
|
|
|
|
|||||||||
|
Gain (loss) recognized in income on derivatives:
|
|
|
|
|
||||||||
|
Natural gas commodity contracts
|
Gas Marketing Operating Revenues
|
$
|
(78
|
)
|
$
|
3,782
|
|
$
|
(660
|
)
|
||
|
|
Gas Marketing Operating Expenses
|
—
|
|
687
|
|
4,229
|
|
|||||
|
NYMEX/ICE natural gas contracts
|
Gas Marketing Operating Revenues
|
(778
|
)
|
(615
|
)
|
(115
|
)
|
|||||
|
|
Gas Marketing Operating Expenses
|
—
|
|
(625
|
)
|
(3
|
)
|
|||||
|
NYMEX gasoline and heating oil contracts
|
Other Income and (Income Deductions) - Net
|
41
|
|
19
|
|
37
|
|
|||||
|
Total
|
|
$
|
(815
|
)
|
$
|
3,248
|
|
$
|
3,488
|
|
||
|
*
|
Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.
|
82
|
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
|
|||||||||
|
|
Asset Derivatives*
|
|
Liability Derivatives*
|
||||||
|
(Thousands)
|
|
Fair Value
|
Balance Sheet Location
|
Fair Value
|
|||||
|
Derivatives designated as hedging instruments
|
|
|
|
|
|||||
|
NYMEX/ICE natural gas contracts
|
Derivative Instrument Assets
|
$
|
2,222
|
|
|
Derivative Instrument Assets
|
$
|
440
|
|
|
Other Deferred Charges
|
22
|
|
Other Deferred Charges
|
11
|
|
||||
|
NYMEX gasoline and heating oil contracts
|
Accounts Receivable - Other
|
105
|
|
|
Accounts Receivable - Other
|
—
|
|
||
|
Sub-total
|
|
2,349
|
|
|
|
451
|
|
||
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|||||
|
NYMEX/ICE natural gas contracts
|
Derivative Instrument Assets
|
950
|
|
|
Derivative Instrument Assets
|
100
|
|
||
|
Accounts Receivable - Other
|
1,434
|
|
Accounts Receivable - Other
|
3,455
|
|
||||
|
Other Deferred Charges
|
32
|
|
Other Deferred Charges
|
—
|
|
||||
|
OTCBB natural gas contracts
|
Other Current Liabilities
|
228
|
|
Other Current Liabilities
|
4,045
|
|
|||
|
Other Deferred Credits
|
4
|
|
Other Deferred Credits
|
1,398
|
|
||||
|
Natural gas commodity contracts
|
Derivative Instrument Assets
|
991
|
|
|
Derivative Instrument Assets
|
90
|
|
||
|
Other Deferred Charges
|
20
|
|
Other Deferred Charges
|
137
|
|
||||
|
Other Current Liabilities
|
247
|
|
Other Current Liabilities
|
830
|
|
||||
|
|
Other Deferred Credits
|
21
|
|
|
Other Deferred Credits
|
123
|
|
||
|
Sub-total
|
|
3,927
|
|
|
|
10,178
|
|
||
|
Total derivatives
|
|
$
|
6,276
|
|
|
|
$
|
10,629
|
|
|
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
|
|||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||
|
(Thousands)
|
Balance Sheet Location
|
Fair Value
|
*
|
Balance Sheet Location
|
Fair Value
|
||||
|
Derivatives designated as hedging instruments
|
|
|
|
|
|||||
|
NYMEX/ICE natural gas contracts
|
Accounts Receivable - Other
|
$
|
405
|
|
|
Accounts Receivable - Other
|
$
|
3,413
|
|
|
|
|||||||||
|
NYMEX gasoline and heating oil contracts
|
Accounts Receivable - Other
|
334
|
|
|
Accounts Receivable - Other
|
—
|
|
||
|
Sub-total
|
|
739
|
|
|
|
3,413
|
|
||
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|||||
|
NYMEX/ICE natural gas contracts
|
Accounts Receivable - Other
|
8,000
|
|
|
Accounts Receivable - Other
|
10,731
|
|
||
|
|
Other Deferred Charges
|
—
|
|
|
Other Deferred Charges
|
—
|
|
||
|
Natural gas commodity contracts
|
Derivative Instrument Assets
|
3,150
|
|
|
Derivative Instrument Assets
|
295
|
|
||
|
|
Other Current Liabilities
|
4
|
|
|
Other Current Liabilities
|
137
|
|
||
|
|
Other Deferred Charges
|
19
|
|
|
Other Deferred Charges
|
—
|
|
||
|
NYMEX gasoline and heating oil contracts
|
Accounts Receivable - Other
|
10
|
|
|
Accounts Receivable - Other
|
—
|
|
||
|
Sub-total
|
|
11,183
|
|
|
|
11,163
|
|
||
|
Total derivatives
|
|
$
|
11,922
|
|
|
|
$
|
14,576
|
|
|
*
|
The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to
Note 10
, Fair Value Measurements, for information on the valuation of derivative instruments.
|
83
Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Fair value of asset derivatives presented above
|
6,276
|
|
11,922
|
|
|||
|
Fair value of cash margin receivables offset with derivatives
|
1,765
|
|
5,478
|
|
|||
|
Netting of assets and liabilities with the same counterparty
|
(4,739
|
)
|
(14,526
|
)
|
|||
|
Total
|
3,302
|
|
2,874
|
|
|||
|
Derivative Instrument Assets, per Consolidated Balance Sheets:
|
|||||||
|
Derivative instrument assets
|
3,291
|
|
2,855
|
|
|||
|
Other deferred charges
|
11
|
|
19
|
|
|||
|
Total
|
3,302
|
|
2,874
|
|
|||
|
Fair value of liability derivatives presented above
|
10,629
|
|
14,576
|
|
|||
|
Fair value of cash margin payables offset with derivatives
|
6
|
|
83
|
|
|||
|
Netting of assets and liabilities with the same counterparty
|
(4,739
|
)
|
(14,526
|
)
|
|||
|
Derivative instrument liabilities, per Consolidated Balance Sheets
|
5,896
|
|
133
|
|
|||
|
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
|
|||||||
|
Other current liabilities
|
$
|
4,400
|
|
$
|
133
|
|
|
|
Other deferred credits
|
1,496
|
|
—
|
|
|||
|
Total
|
$
|
5,896
|
|
$
|
133
|
|
|
Additionally, at
September 30, 2013
and
2012
, the Company had
$3.2 million
and
$10.0 million
, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable – Other.
|
12.
|
CONCENTRATION OF CREDIT RISK
|
A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to
$22.8 million
at September 30, 2013. However, due to netting arrangements, there were no net receivable amounts from these customers on that same date. Accounts receivable attributable to utility companies and their marketing affiliates comprised
$23.5 million
of total accounts receivable at September 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were
$16.6 million
. LER also has concentrations of credit risk with certain individually significant counterparties. At September 30, 2013, the amounts included in accounts receivable from LER’s
five
largest counterparties (in terms of net accounts receivable exposure), were
$16.6 million
. These
five
counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were
$14.5 million
. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.
84
|
13.
|
INCOME TAXES
|
The net provisions for income taxes charged during the fiscal years ended September 30,
2013
,
2012
, and
2011
are as follows:
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Included in Statements of Consolidated Income:
|
|
|
|
||||||||
|
Federal
|
|
|
|
||||||||
|
Current
|
$
|
(4,173
|
)
|
$
|
(3,835
|
)
|
$
|
4,724
|
|
||
|
Deferred
|
19,925
|
|
26,365
|
|
20,602
|
|
|||||
|
Investment tax credits
|
(213
|
)
|
(213
|
)
|
(213
|
)
|
|||||
|
State and local
|
|
|
|||||||||
|
Current
|
(301
|
)
|
(430
|
)
|
573
|
|
|||||
|
Deferred
|
2,340
|
|
4,402
|
|
3,496
|
|
|||||
|
Total Income Tax Expense
|
$
|
17,578
|
|
$
|
26,289
|
|
$
|
29,182
|
|
||
The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
|
|
2013
|
2012
|
2011
|
|||||
|
Federal income tax statutory rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||
|
State and local income taxes, net of federal income tax benefits
|
3.5
|
|
2.9
|
|
2.8
|
|
||
|
Certain expenses capitalized on books and deducted on tax return
|
(9.7
|
)
|
(6.9
|
)
|
(5.0
|
)
|
||
|
Taxes related to prior years
|
(1.6
|
)
|
(0.8
|
)
|
(0.7
|
)
|
||
|
Other items – net
|
(2.2
|
)
|
(0.6
|
)
|
(0.7
|
)
|
||
|
Effective income tax rate
|
25.0
|
%
|
29.6
|
%
|
31.4
|
%
|
||
The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Deferred tax assets:
|
|
|
|||||
|
Reserves not currently deductible
|
$
|
13,933
|
|
$
|
16,400
|
|
|
|
Pension and other postretirement benefits
|
71,367
|
|
73,480
|
|
|||
|
Unamortized investment tax credits
|
1,799
|
|
1,955
|
|
|||
|
Other*
|
12,522
|
|
18,224
|
|
|||
|
Total deferred tax assets
|
99,621
|
|
110,059
|
|
|||
|
Deferred tax liabilities:
|
|
|
|||||
|
Relating to property
|
341,975
|
|
303,474
|
|
|||
|
Regulatory pension and other postretirement benefits
|
124,871
|
|
121,554
|
|
|||
|
Deferred gas costs
|
7,112
|
|
20,652
|
|
|||
|
Other
|
5,789
|
|
26,563
|
|
|||
|
Total deferred tax liabilities
|
479,747
|
|
472,243
|
|
|||
|
Net deferred tax liability
|
380,126
|
|
362,184
|
|
|||
|
Net deferred tax liability – current*
|
(1,012
|
)
|
(6,675
|
)
|
|||
|
Net deferred tax liability – non-current*
|
$
|
379,114
|
|
$
|
355,509
|
|
|
* The Company periodically invests in tax credits. As of September 30,
2013
,
$7.1 million
of state tax credits are included in Other and Net deferred tax liability.
$4.7 million
of state tax credits were classified as current.
$2.4 million
of state tax credits were classified as non-current.
Pursuant to GAAP, the Company may recognize the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are included in the Other line of the Deferred Credits and Other Liabilities section of the Consolidated Balance Sheets.
85
The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:
|
(Thousands)
|
2013
|
2012
|
|||||
|
Unrecognized tax benefits, beginning of year
|
$
|
5,810
|
|
$
|
5,596
|
|
|
|
Increases related to prior year tax positions
|
145
|
|
78
|
|
|||
|
Increases related to tax positions taken in current year
|
1,450
|
|
547
|
|
|||
|
Reductions due to lapse of applicable statute of limitations
|
(5,018
|
)
|
(411
|
)
|
|||
|
Unrecognized tax benefits, end of year
|
$
|
2,387
|
|
$
|
5,810
|
|
|
The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were
$1.9 million
and
$1.4 million
as of September 30,
2013
and
2012
, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.
Interest accrued associated with the Company’s uncertain tax positions as of September 30,
2013
and
2012
were
$0.1 million
and
$0.6 million
, respectively, and an immaterial amount of penalties were accrued as of September 30, 2013. Interest expense accrued during fiscal year
2013
was
$0.1 million
,
$0.2 million
for fiscal year
2012
, and
$0.2 million
for fiscal year
2011
. During fiscal year
2013
, the Company reversed
$0.6 million
of accrued interest expense in the Consolidated Statements of Income.
The Company is subject to U.S. federal income tax as well as income tax of state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2010.
In September 2013, the Internal Revenue Service and U.S. Treasury Department released final regulations on the deduction and capitalization of expenditures related to tangible property. The regulations do not address the tax treatment for network assets such as natural gas pipelines. These regulations apply to tax years beginning on or after January 1, 2014. Laclede is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its consolidated financial statements.
|
14.
|
OTHER INCOME AND (INCOME DEDUCTIONS) – NET
|
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Interest income
|
$
|
1,088
|
|
$
|
1,309
|
|
$
|
1,136
|
|
||
|
Net investment gain
|
2,857
|
|
3,124
|
|
185
|
|
|||||
|
Other income
|
377
|
|
811
|
|
118
|
|
|||||
|
Other income deductions
|
(1,878
|
)
|
(1,972
|
)
|
(1,262
|
)
|
|||||
|
Other Income and (Income Deductions) – Net
|
$
|
2,444
|
|
$
|
3,272
|
|
$
|
177
|
|
||
15. INFORMATION BY OPERATING SEGMENT
All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of the Utility and is the core business segment of Laclede Group. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through
seven
subsidiaries. Other also includes the Utility’s non-regulated business activities, which are comprised of its propane storage and related services. Beginning July 1, 2013, propane-related services were included within Gas Utility operations pursuant to Laclede Gas' most recent rate case. Accounting policies are described in
Note 1
, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from the Utility to LER, propane storage services provided by the Utility to Laclede Pipeline Company, sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility.
86
Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also excludes the after-tax impacts related to acquisition, divestiture, and restructuring activities.
|
Gas Utility
|
Gas Marketing
|
Other
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(Thousands)
|
|
|
|||||||||||||||||
|
Fiscal 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
Revenues from external customers
|
$
|
847,224
|
|
$
|
165,146
|
|
|
$
|
4,649
|
|
|
$
|
—
|
|
$
|
1,017,019
|
|
||
|
Intersegment revenues
|
10,538
|
|
24,185
|
|
|
1,625
|
|
|
(36,348
|
)
|
—
|
|
|||||||
|
Total Operating Revenues
|
857,762
|
|
189,331
|
|
|
6,274
|
|
|
(36,348
|
)
|
1,017,019
|
|
|||||||
|
Operating Expenses
|
|||||||||||||||||||
|
Gas Utility
|
|||||||||||||||||||
|
Natural and Propane Gas
|
469,098
|
|
—
|
|
—
|
|
(35,656
|
)
|
433,442
|
|
|||||||||
|
Other Operation and Maintenance
|
180,702
|
|
—
|
|
—
|
|
(360
|
)
|
180,342
|
|
|||||||||
|
Depreciation and Amortization
|
48,283
|
|
—
|
|
—
|
|
—
|
|
48,283
|
|
|||||||||
|
Taxes, Other than Income Taxes
|
60,079
|
|
—
|
|
—
|
|
—
|
|
60,079
|
|
|||||||||
|
Total Gas Utility Operating Expenses
|
758,162
|
|
—
|
|
—
|
|
(36,016
|
)
|
722,146
|
|
|||||||||
|
Gas Marketing
|
—
|
|
176,554
|
|
(a)
|
—
|
|
—
|
|
176,554
|
|
||||||||
|
Other
|
—
|
|
—
|
|
22,157
|
|
(b)
|
(332
|
)
|
21,825
|
|
||||||||
|
Total Operating Expenses
|
758,162
|
|
176,554
|
|
22,157
|
|
(36,348
|
)
|
920,525
|
|
|||||||||
|
Operating Income
|
99,599
|
|
12,777
|
|
(15,882
|
)
|
—
|
|
96,494
|
|
|||||||||
|
Interest income
|
947
|
|
103
|
|
|
343
|
|
|
(305
|
)
|
1,088
|
|
|||||||
|
Interest charges
|
26,137
|
|
135
|
|
|
2,635
|
|
|
(305
|
)
|
28,602
|
|
|||||||
|
Income tax expense
|
19,243
|
|
5,162
|
|
|
(6,827
|
)
|
|
—
|
|
17,578
|
|
|||||||
|
Net economic earnings
|
56,635
|
|
8,936
|
|
|
(559
|
)
|
|
—
|
|
65,012
|
|
|||||||
|
Total assets
|
2,981,016
|
|
163,944
|
|
|
115,560
|
|
|
(135,134
|
)
|
3,125,386
|
|
|||||||
|
Capital expenditures
|
128,496
|
|
44
|
|
|
2,248
|
|
|
—
|
|
130,788
|
|
|||||||
|
Fiscal 2012
|
|
|
|
|
|
|
|
|
|||||||||||
|
Revenues from external customers
|
$
|
763,447
|
|
$
|
358,145
|
|
|
$
|
3,883
|
|
|
$
|
—
|
|
$
|
1,125,475
|
|
||
|
Intersegment revenues
|
1,204
|
|
15,330
|
|
|
1,042
|
|
|
(17,576
|
)
|
—
|
|
|||||||
|
Total Operating Revenues
|
764,651
|
|
373,475
|
|
|
4,925
|
|
|
(17,576
|
)
|
1,125,475
|
|
|||||||
|
Operating Expenses
|
|||||||||||||||||||
|
Gas Utility
|
|||||||||||||||||||
|
Natural and Propane Gas
|
414,846
|
|
—
|
|
—
|
|
(17,542
|
)
|
397,304
|
|
|||||||||
|
Other Operation and Maintenance
|
167,351
|
|
—
|
|
—
|
|
—
|
|
167,351
|
|
|||||||||
|
Depreciation and Amortization
|
40,739
|
|
—
|
|
—
|
|
—
|
|
40,739
|
|
|||||||||
|
Taxes, Other than Income Taxes
|
53,672
|
|
—
|
|
—
|
|
—
|
|
$
|
53,672
|
|
||||||||
|
Total Gas Utility Operating Expenses
|
676,608
|
|
—
|
|
—
|
|
(17,542
|
)
|
659,066
|
|
|||||||||
|
Gas Marketing
|
—
|
|
353,286
|
|
(a)
|
—
|
|
(3
|
)
|
353,283
|
|
||||||||
|
Other
|
—
|
|
—
|
|
2,555
|
|
(b)
|
(31
|
)
|
2,524
|
|
||||||||
|
Total Operating Expenses
|
676,608
|
|
353,286
|
|
2,555
|
|
(17,576
|
)
|
1,014,873
|
|
|||||||||
|
Operating Income
|
88,043
|
|
20,189
|
|
2,370
|
|
—
|
|
110,602
|
|
|||||||||
|
Interest income
|
1,230
|
|
175
|
|
|
371
|
|
|
(467
|
)
|
1,309
|
|
|||||||
|
Interest charges
|
25,156
|
|
81
|
|
|
175
|
|
|
(467
|
)
|
24,945
|
|
|||||||
|
Income tax expense
|
17,393
|
|
7,966
|
|
|
930
|
|
|
—
|
|
26,289
|
|
|||||||
|
Net economic earnings
|
48,089
|
|
12,273
|
|
|
2,250
|
|
|
—
|
|
62,612
|
|
|||||||
|
Total assets
|
1,758,952
|
|
190,709
|
|
|
102,241
|
|
|
(171,640
|
)
|
1,880,262
|
|
|||||||
|
Capital expenditures
|
106,734
|
|
140
|
|
|
1,969
|
|
|
—
|
|
108,843
|
|
|||||||
87
|
Fiscal 2011
|
|
|
|
|
|
|
|
|
|||||||||||
|
Revenues from external customers
|
$
|
911,614
|
|
$
|
645,042
|
|
|
$
|
19,704
|
|
|
$
|
—
|
|
1,576,360
|
|
|||
|
Intersegment revenues
|
1,576
|
|
24,333
|
|
|
1,038
|
|
|
—
|
|
26,947
|
|
|||||||
|
Total Operating Revenues
|
913,190
|
|
669,375
|
|
|
20,742
|
|
|
—
|
|
1,603,307
|
|
|||||||
|
Operating Expenses
|
|||||||||||||||||||
|
Gas Utility
|
|||||||||||||||||||
|
Natural and Propane Gas
|
549,947
|
|
—
|
|
—
|
|
—
|
|
549,947
|
|
|||||||||
|
Other Operation and Maintenance
|
172,938
|
|
—
|
|
—
|
|
—
|
|
172,938
|
|
|||||||||
|
Depreciation and Amortization
|
39,214
|
|
—
|
|
—
|
|
—
|
|
$
|
39,214
|
|
||||||||
|
Taxes, Other than Income Taxes
|
60,752
|
|
—
|
|
—
|
|
—
|
|
60,752
|
|
|||||||||
|
Total Gas Utility Operating Expenses
|
822,851
|
|
—
|
|
—
|
|
—
|
|
$
|
822,851
|
|
||||||||
|
Gas Marketing
|
—
|
|
652,567
|
|
(a)
|
—
|
|
—
|
|
652,567
|
|
||||||||
|
Other
|
—
|
|
—
|
|
9,642
|
|
(b)
|
—
|
|
9,642
|
|
||||||||
|
Total Operating Expenses
|
822,851
|
|
652,567
|
|
9,642
|
|
—
|
|
1,485,060
|
|
|||||||||
|
Operating Income
|
90,339
|
|
16,808
|
|
11,100
|
|
—
|
|
118,247
|
|
|||||||||
|
Interest income
|
1,057
|
|
165
|
|
|
217
|
|
|
(303
|
)
|
1,136
|
|
|||||||
|
Interest charges
|
25,544
|
|
14
|
|
|
162
|
|
|
(303
|
)
|
25,417
|
|
|||||||
|
Income tax expense
|
18,694
|
|
6,570
|
|
|
3,918
|
|
|
—
|
|
29,182
|
|
|||||||
|
Net economic earnings
|
46,952
|
|
8,962
|
|
|
6,496
|
|
(c)
|
—
|
|
62,410
|
|
|||||||
|
Total assets
|
1,641,386
|
|
175,352
|
|
|
129,176
|
|
|
(162,832
|
)
|
1,783,082
|
|
|||||||
|
Capital expenditures
|
67,304
|
|
215
|
|
|
119
|
|
|
—
|
|
67,638
|
|
|||||||
|
(a)
|
Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income (
$0.3 million
for fiscal year
2013
,
$0.3 million
for fiscal year
2012
, and
$0.1 million
for fiscal year
2011
).
|
|
(b)
|
Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income (
$0.6 million
for fiscal year
2013
,
$0.3 million
for fiscal year
2012
and
$0.2 million
for fiscal year
2011
).
|
|
(c)
|
Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling
$6.1 million
.
|
|
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
|
|||||||||||
|
(Thousands)
|
2013
|
2012
|
2011
|
||||||||
|
Net Income (GAAP)
|
$
|
52,758
|
|
$
|
62,640
|
|
$
|
63,825
|
|
||
|
Unrealized loss (gain) on energy-related
derivatives
|
614
|
|
(314
|
)
|
(1,415
|
)
|
|||||
|
Lower of cost or market inventory adjustments
|
868
|
|
—
|
|
—
|
|
|||||
|
Realized (gain) loss on economic hedges prior
to the sale of the physical commodity
|
(25
|
)
|
163
|
|
—
|
|
|||||
|
Acquisition, divestiture and restructuring activities
|
10,797
|
|
123
|
|
—
|
|
|||||
|
Net Economic Earnings (Non-GAAP)
|
$
|
65,012
|
|
$
|
62,612
|
|
$
|
62,410
|
|
||
16. COMMITMENTS AND CONTINGENCIES
Commitments
The Utility estimates total Utility capital expenditures for fiscal 2014 at approximately
$175 million
. In fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At September 30, 2013, the Company was contractually committed to costs of approximately
$1.5 million
related to this project.
88
Fiscal year 2014 capital expenditures for non-regulated subsidiaries will depend on the nature and magnitude of investments with the current estimate at
$10 million
. There are no material contractual commitments at September 30, 2013 related to these estimated capital expenditures.
The Utility and LER have entered into various contracts, expiring on dates through 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at September 30, 2013 are estimated at approximately
$981 million
. The Utility recovers its costs from customers in accordance with the PGA Clause.
Leases and Guarantees
The lease agreement covering the main office space of the Utility extends through February 2015 with the option to renew for
five
additional years. The aggregate rental expense for fiscal years 2013, 2012, and 2011 was approximately
$1.0 million
,
$0.9 million
, and
$0.9 million
, respectively. The annual minimum rental payment for fiscal year 2014 is anticipated to be approximately
$1.0 million
through fiscal year 2015. The annual rental amount for the lease agreement covering MGE's main office space is approximately
$0.6 million
, and the lease term extends through November 30, 2015.
The Utility has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The rental costs will be approximately
$2.7 million
in fiscal year 2014,
$1.8 million
in fiscal year 2015,
$1.0 million
in fiscal year 2016, and
$0.4 million
in fiscal year 2017, and
$0.1 million
in fiscal year 2018. The Utility and LER have other relatively minor rental arrangements that provide for minimum rental payments.
A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately
$1.6 million
incurred in connection with various real estate ventures. Laclede Group has no reason to believe that the other principal liable parties will not be able to meet their proportionate share of these obligations. Laclede Group further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.
Contingencies
The Utility owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs.
Similar to other natural gas utility companies, Laclede Gas Company faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and MGE or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified
three
former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted:
one
in Shrewsbury, Missouri and
two
in the City of St. Louis, Missouri. Laclede Gas has enrolled the
two
sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). MGE has enrolled all of its owned former manufactured gas plant sites in the BVCP.
With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, EPA Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.
One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources.
89
The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability.
The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.
Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion.
To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from
$5.8 million
to
$36.3 million
based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.
MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.
Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. The Utility anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of the Utility or the Company.
The MoPSC Staff proposed disallowances related to Laclede Gas' recovery of its gas costs totaling
$6.0 million
pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism.
90
For a three-year period ending September 30, 2016, Laclede Gas' share of the first
$2 million
in net margin is reduced from
15%
to
0%
. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first
$2 million
in net margins returns to
15%
. The Stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.
On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February
4,
2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC
’
s May 2011 penalty case was dismissed.
On June 29, 2010, the Office of Federal Contract Compliance Programs (OFCCP) issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a
two
-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.
As discussed in Note 11, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of November 26, 2013, Laclede Gas and LER had
$0.2 million
and
$0.1 million
, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. As the Company has recovered
98%
of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.
On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.
Laclede Group is involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.
91
17. INTERIM FINANCIAL INFORMATION (UNAUDITED)
In the opinion of Laclede Group, the quarterly information presented below for fiscal years
2013
and
2012
includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utility.
|
(Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|||||||
|
Three Months Ended
|
Dec. 31
|
March 31
|
June 30
|
Sept. 30
|
|||||||||||
|
Fiscal Year 2013
|
|
|
|
||||||||||||
|
Total Operating Revenues
|
$
|
307,003
|
|
$
|
397,613
|
|
$
|
165,289
|
|
$
|
147,114
|
|
|||
|
Operating Income (Loss)
|
42,085
|
|
51,849
|
|
12,282
|
|
(9,722
|
)
|
|||||||
|
Net Income (Loss)
|
25,568
|
|
30,242
|
|
6,584
|
|
(9,636
|
)
|
|||||||
|
Basic Earnings (Loss) Per Share of Common Stock
|
1.14
|
|
1.34
|
|
0.25
|
|
(0.30
|
)
|
|||||||
|
Diluted Earnings (Loss) Per Share of Common Stock
|
1.14
|
|
1.34
|
|
0.25
|
|
(0.30
|
)
|
|||||||
|
Three Months Ended
|
Dec. 31
|
March 31
|
June 30
|
Sept. 30
|
|||||||||||
|
Fiscal Year 2012
|
|
|
|
|
|||||||||||
|
Total Operating Revenues
|
$
|
410,913
|
|
$
|
358,175
|
|
$
|
186,849
|
|
$
|
169,538
|
|
|||
|
Operating Income
|
43,105
|
|
50,583
|
|
15,045
|
|
1,869
|
|
|||||||
|
Net Income (Loss)
|
25,174
|
|
29,684
|
|
8,433
|
|
(651
|
)
|
|||||||
|
Basic Earnings (Loss) Per Share of Common Stock
|
1.13
|
|
1.33
|
|
0.38
|
|
(0.03
|
)
|
|||||||
|
Diluted Earnings (Loss) Per Share of Common Stock
|
1.12
|
|
1.32
|
|
0.38
|
|
(0.03
|
)
|
|||||||
All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.
92
There have been no changes in and disagreements on accounting and financial disclosure with Laclede’s outside auditors that are required to be disclosed.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.
(b) Change in Internal Controls
During our fourth fiscal quarter we implemented a new customer care and billing application. The new system and related changes to processes have changed and enhanced our internal control over customer billing and financial reporting. We have taken the necessary steps to test the operating effectiveness of all key controls in the new system and maintain appropriate internal control over financial reporting during fiscal year 2013. Other than the system implementation discussed above, there have been no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The Management Report on Internal Control Over Financial Reporting and the Reports of Independent Registered Public Accounting Firm are included under
Item 8
, pages
46
through
48
.
None.
93
Information about:
|
•
|
our directors is incorporated by reference from the discussion under Proposal 1 of our proxy statement dated December 18, 2013 (2013 proxy statement);
|
|
•
|
our executive officers is reported in Part I of this Form 10-K;
|
|
•
|
compliance with Section 16(a) of the Exchange Act is incorporated by reference from the discussion in our
2013
proxy statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”;
|
|
•
|
Financial Code of Ethics is posted on our website,
www.TheLacledeGroup.com
, in the Investor Services section under Governance Documents; and,
|
|
•
|
our audit committee, our audit committee financial experts, and submitting nominations to the Corporate Governance Committee is incorporated by reference from the discussion in our
2013
proxy statement under the heading “Corporate Governance.”
|
In addition, our Code of Business Conduct, Corporate Governance Guidelines, and charters for our audit, compensation and corporate governance committees are available on our website, and a copy will be sent to any shareholder upon written request.
Information about director and executive compensation is incorporated by reference from the discussion in our
2013
proxy statement under the headings: “Directors’ Compensation,” “Compensation Discussion and Analysis,” and “Executive Compensation.” The
2013
proxy statement also includes the “Compensation Committee Report,” which is deemed furnished and not filed.
Information about security ownership of certain beneficial owners and management is incorporated by reference from the discussion in our
2013
proxy statement under “Beneficial Ownership of Laclede Group Common Stock.”
The following table sets forth aggregate information regarding the Company’s equity compensation plans as of
September 30, 2013
:
|
Plan Category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
Weighted average exercise price of outstanding options, warrants and rights
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
|
||||||
|
|
(a)
|
(b)
|
(c)
|
||||||
|
Equity compensation plans approved by security holders (1)
|
338,924
|
|
$
|
31.87
|
|
550,331
|
|
||
|
Equity compensation plans not approved by security holders
|
—
|
|
—
|
|
—
|
|
|||
|
Total
|
338,924
|
|
31.87
|
|
550,331
|
|
|||
|
(1)
|
Reflects the Company’s Equity Incentive Plan. Included in column (a) are 205,424 nonvested restricted stock units issued under the Equity Incentive Plan for which the weighted average exercise price in column (b) does not take into account.
|
Information regarding the above referenced plans is set forth in
Note 4
of the Notes to Consolidated Financial Statements in this report.
Information about:
|
•
|
our policy and procedures for related party transactions and
|
|
•
|
the independence of our directors
|
is included in our
2013
proxy statement under “Corporate Governance” and is incorporated by reference. There were no related party transactions in fiscal year
2013
.
94
Information about fees paid to our independent registered public accountant and our policy for pre-approval of services provided by our independent registered public accountant is incorporated by reference from our
2013
proxy statement under “Fees of Independent Registered Public Accountant” and “Corporate Governance,” respectively.
95
|
Item 15. Exhibits, Financial Statement Schedule
|
|
|||||
|
|
|
|
2013 10-K Page
|
|||
|
(a)
|
1.
|
Financial Statements:
|
|
|||
|
|
|
See
Item 8
. Financial Statements and Supplementary Data, filed herewith, for a list of financial statements.
|
||||
|
|
2.
|
Supplemental Schedule
|
|
|||
|
|
|
|||||
|
|
|
Schedules not included have been omitted because they are not applicable or the required data has been included in the financial statements or notes to financial statements.
|
|
|||
|
|
|
|
||||
|
|
3.
|
Exhibits
|
||||
|
|
|
Incorporated herein by reference to
Index to Exhibits
, page 99.
|
||||
|
Item 15(a)(3) See the marked exhibits in the
Index to Exhibits
, page 99.
|
|
|||||
|
(b)
|
Incorporated herein by reference to
Index to Exhibits
, page 99.
|
|||||
96
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
THE LACLEDE GROUP, INC.
|
|
|
|
|
|
|
November 26, 2013
|
|
By /s/
|
Steven P. Rasche
|
|
|
|
|
Steven P. Rasche
|
|
|
|
|
Senior Vice President
|
|
|
|
|
and Chief Financial Officer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
Date
|
Signature
|
Title
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Suzanne Sitherwood
|
Director, President,
|
|
|
|
Suzanne Sitherwood
|
and Chief Executive Officer
|
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Steven P. Rasche
|
Senior Vice President
|
|
|
|
Steven P. Rasche
|
and Chief Financial Officer
|
|
|
|
|
(Principal Finance and Accounting Officer)
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
William E. Nasser
|
Chairman of the Board
|
|
|
|
William E. Nasser
|
|
|
|
|
|
|
|
November 26, 2013
|
Director
|
||
|
|
|
Arnold W. Donald
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Edward L. Glotzbach
|
Director
|
|
|
|
Edward L. Glotzbach
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Anthony V. Leness
|
Director
|
|
|
|
Anthony V. Leness
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
W. Stephen Maritz
|
Director
|
|
|
|
W. Stephen Maritz
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Brenda D. Newberry
|
Director
|
|
|
|
Brenda D. Newberry
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
John P. Stupp, Jr.
|
Director
|
|
|
|
John P. Stupp, Jr.
|
|
|
|
|
|
|
|
November 26, 2013
|
/s/
|
Mary Ann Van Lokeren
|
Director
|
|
|
|
Mary Ann Van Lokeren
|
|
97
SCHEDULE II
THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES
RESERVES
FOR THE YEARS ENDED SEPTEMBER 30, 2013, 2012, AND 2011
|
COLUMN A
|
COLUMN B
|
COLUMN C
|
|
COLUMN D
|
|
COLUMN E
|
|||||||||||||
|
|
BALANCE AT
|
ADDITIONS
|
CHARGED
|
|
DEDUCTIONS
|
|
BALANCE
|
||||||||||||
|
|
BEGINNING
|
TO
|
TO OTHER
|
|
FROM
|
|
AT CLOSE
|
||||||||||||
|
DESCRIPTION
|
OF PERIOD
|
INCOME
|
ACCOUNTS
|
RESERVES
|
OF PERIOD
|
||||||||||||||
|
(Thousands of Dollars)
|
|
|
|
|
|
|
|
||||||||||||
|
YEAR ENDED SEPTEMBER 30, 2013:
|
|
|
|
|
|
|
|
||||||||||||
|
DOUBTFUL ACCOUNTS
|
$
|
7,705
|
|
$
|
5,584
|
|
$
|
8,234
|
|
(b)
|
$
|
13,477
|
|
(c)
|
$
|
8,046
|
|
||
|
MISCELLANEOUS:
|
|
|
|
|
|
|
|
||||||||||||
|
Injuries and property damage
|
$
|
4,540
|
|
$
|
1,934
|
|
$
|
—
|
|
|
$
|
2,135
|
|
(d)
|
$
|
4,339
|
|
||
|
Deferred compensation
|
14,205
|
|
1,781
|
|
—
|
|
|
1,306
|
|
|
14,680
|
|
|||||||
|
Group medical claims incurred but not reported
|
1,560
|
|
17,205
|
|
—
|
|
|
16,116
|
|
(d)
|
2,649
|
|
|||||||
|
TOTAL
|
$
|
20,305
|
|
$
|
20,920
|
|
(a)
|
$
|
—
|
|
(a)
|
$
|
19,557
|
|
(a)
|
$
|
21,668
|
|
|
|
YEAR ENDED SEPTEMBER 30, 2012:
|
|
|
|
|
|
|
|
||||||||||||
|
DOUBTFUL ACCOUNTS
|
$
|
10,073
|
|
$
|
6,011
|
|
$
|
10,145
|
|
(b)
|
$
|
18,524
|
|
(c)
|
$
|
7,705
|
|
||
|
MISCELLANEOUS:
|
|
|
|
|
|
|
|
||||||||||||
|
Injuries and property damage
|
$
|
3,603
|
|
$
|
3,150
|
|
$
|
—
|
|
|
$
|
2,213
|
|
(d)
|
$
|
4,540
|
|
||
|
Deferred compensation
|
13,474
|
|
1,756
|
|
—
|
|
|
1,025
|
|
|
14,205
|
|
|||||||
|
Group medical claims incurred but not reported
|
1,300
|
|
15,381
|
|
—
|
|
|
15,121
|
|
(d)
|
1,560
|
|
|||||||
|
TOTAL
|
$
|
18,377
|
|
$
|
20,287
|
|
$
|
—
|
|
|
$
|
18,359
|
|
|
$
|
20,305
|
|
||
|
YEAR ENDED SEPTEMBER 30, 2011:
|
|
|
|
|
|
|
|
||||||||||||
|
DOUBTFUL ACCOUNTS
|
$
|
10,295
|
|
$
|
7,242
|
|
$
|
11,340
|
|
(b)
|
$
|
18,804
|
|
(c)
|
$
|
10,073
|
|
||
|
MISCELLANEOUS:
|
|
|
|
|
|
|
|
||||||||||||
|
Injuries and property damage
|
$
|
3,228
|
|
$
|
2,416
|
|
$
|
—
|
|
|
$
|
2,041
|
|
(d)
|
$
|
3,603
|
|
||
|
Deferred compensation
|
12,571
|
|
1,893
|
|
—
|
|
|
990
|
|
|
13,474
|
|
|||||||
|
Group medical claims incurred but not reported
|
1,450
|
|
14,171
|
|
—
|
|
|
14,321
|
|
(d)
|
1,300
|
|
|||||||
|
TOTAL
|
$
|
17,249
|
|
$
|
18,480
|
|
$
|
—
|
|
|
$
|
17,352
|
|
|
$
|
18,377
|
|
||
|
(a)
|
Totals for the year ended September 30, 2013 includes one month of MGE activity.
|
|
(b)
|
Accounts reinstated, cash recoveries, etc.
|
|
(c)
|
Accounts written off.
|
|
(d)
|
Claims settled, less reimbursements from insurance companies.
|
98
INDEX TO EXHIBITS
|
Exhibit
|
|
|
|
No.
|
|
|
|
2.01*
|
-
|
Agreement and Plan of Merger and Reorganization; filed as Appendix A to proxy statement/prospectus contained in the Company’s registration statement on Form S-4, No. 333-48794.
|
|
3.01(i)*
|
-
|
The Company’s Articles of Incorporation, as amended; filed as Exhibit 3.1 to the Company’s Form 8-K filed January 26, 2006.
|
|
3.01(ii)*
|
-
|
The Company’s Bylaws, as amended; filed as Exhibit 3.2 to the Company’s 10-Q for the fiscal quarter ended March 31, 2012.
|
|
4.01*
|
-
|
Mortgage and Deed of Trust, dated as of February 1, 1945; filed as Exhibit 7-A to registration statement No. 2-5586.
|
|
4.02*
|
-
|
Fourteenth Supplemental Indenture, dated as of October 26, 1976; filed on June 26, 1979 as Exhibit b-4 to registration statement No. 2-64857.
|
|
4.04*
|
-
|
Twenty-Fourth Supplemental Indenture dated as of June 1, 1999; filed on June 4, 1999 as Exhibit 4.01 to Laclede’s Form 8-K.
|
|
4.05*
|
-
|
Twenty-Fifth Supplemental Indenture dated as of September 15, 2000; filed on September 27, 2000 as Exhibit 4.01 to Laclede’s Form 8-K.
|
|
4.06*
|
-
|
Twenty-Seventh Supplemental Indenture dated as of April 15, 2004; filed on April 28, 2004 as Exhibit 4.01 to Laclede’s Form 8-K.
|
|
4.07*
|
-
|
Twenty-Eighth Supplemental Indenture dated as of April 15, 2004; filed on April 28, 2004 as Exhibit 4.02 to Laclede’s Form 8-K.
|
|
4.08*
|
-
|
Twenty-Ninth Supplemental Indenture dated as of June 1, 2006; filed on June 9, 2006, as Exhibit 4.1 to Laclede’s Form 8-K
|
|
4.09*
|
-
|
Thirtieth Supplemental Indenture dated as of September 15, 2008; filed on September 23, 2008 as Exhibit 4.1 to Laclede’s Form 8-K.
|
|
4.10*
|
-
|
Thirty-First Supplemental Indenture dated as of March 15, 2013; filed as Exhibit 4.1 to the Company's Form 10-Q for the quarter ended March 31, 2013.
|
|
4.11*
|
-
|
Thirty-Second Supplemental indenture dated as of August 13, 2013; filed August 13, 2013 as Exhibit 4.1 to the Company's Form 8-K filed August 13, 2013.
|
|
4.12*
|
-
|
Laclede Gas Company Board of Directors’ Resolution dated August 28, 1986 which generally provides that the Board may delegate its authority in the adoption of certain employee benefit plan amendments to certain designated Executive Officers; filed as Exhibit 4.12 to the Company’s 1991 10-K.
|
|
4.13*
|
-
|
Company Board of Directors’ Resolutions dated March 27, 2003, updating authority delegated pursuant to August 28, 1986 Laclede Gas Company resolutions; filed as Exhibit 4.19(a) to the Company’s Form 10-K for the year ended September 30, 2003.
|
|
10.04*
|
-
|
Restated Laclede Gas Company Supplemental Retirement Benefit Plan, as amended and restated effective as of November 1, 2005; filed as Exhibit 10.06 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.05*
|
-
|
Amended and Restated Storage Service Agreement For Rate Schedule FSS, Contract #3147 between Centerpoint Energy-Mississippi River Transmission Corporation (MRT) and Laclede dated July 30, 2013; filed as 10.1 to the Company's Form 8-K filed August 2, 2013.
|
|
10.05a*
|
-
|
Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3310 between Laclede and MRT dated July 30, 2013; filed as Exhibit 10.2 to the Company's Form 8-K filed August 2, 2013.
|
|
10.05b*
|
-
|
Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3311, between Laclede and MRT dated July 30, 2013; filed as Exhibit 10.3 to the Company's Form 8-K filed August 2, 2013.
|
|
10.06*
|
-
|
Laclede Supplemental Retirement Benefit Plan II, effective as of January 1, 2005; filed as Exhibit 10.7 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.07*
|
-
|
Amendment and Restatement of Retirement Plan for Non-Employee Directors as of November 1, 2002; filed as Exhibit 10.08c to the Company’s 10-K for the fiscal year ended September 30, 2002.
|
|
10.07a*
|
-
|
Amendment to Terms of Retirement Plan for Non-Employee Directors as of October 1, 2004; filed as Exhibit 10.w to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2004.
|
|
10.08*
|
-
|
Salient Features of the Laclede Gas Company Deferred Income Plan for Directors and Selected Executives, including amendments adopted by the Board of Directors on July 26, 1990; filed as Exhibit 10.12 to the Company’s 1991 10-K.
|
|
10.08a*
|
-
|
Amendment to Laclede’s Deferred Income Plan for Directors and Selected Executives, adopted by the Board of Directors on August 27, 1992; filed as Exhibit 10.12a to the Company’s 1992 10-K.
|
99
|
Exhibit
|
|
|
|
No.
|
|
|
|
10.09*
|
-
|
Form of Indemnification Agreement between Laclede and its Directors and Officers; filed as Exhibit 10.13 to the Company’s 1990 10-K.
|
|
10.10*
|
-
|
The Laclede Group Management Continuity Protection Plan, effective as of January 1, 2005; filed as Exhibit 10.5 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.10a*
|
-
|
Form of Management Continuity Protection Agreement; Filed as Exhibit 10.05a to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.11*
|
-
|
Restricted Stock Plan for Non-Employee Directors as amended and effective January 29, 2009; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended March 31, 2009.
|
|
10.11a*
|
-
|
Amendment to Restricted Stock Plan for Non-Employee Directors; filed as Exhibit 10.6 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
|
|
10.12*
|
-
|
Salient Features of the Laclede Gas Company Deferred Income Plan II for Directors and Selected Executives (as amended and restated effective as of January 1, 2005); filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.13*
|
-
|
Salient Features of the Company’s Deferred Income Plan for Directors and Selected Executives (effective as of January 1, 2005); filed as Exhibit 10.2 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.14*
|
-
|
The Laclede Group, Inc. 2002 Equity Incentive Plan; filed as Exhibit 10.22 to the Company’s Form 10-K for the year ended September 30, 2002.
|
|
10.14a*
|
-
|
Form of Non-Qualified Stock Option Award Agreement with Mandatory Retirement Provisions; filed as Exhibit 10.1 to the Company’s Form 8-K filed November 5, 2004.
|
|
10.14b*
|
-
|
Form of Non-Qualified Stock Option Award Agreement without Mandatory Retirement Provisions; filed as Exhibit 10.2 to the Company’s Form 8-K filed November 5, 2004.
|
|
10.15*
|
-
|
Lease between Laclede Gas Company, as Lessee and First National Bank in St. Louis, Trustee, as Lessor; filed as Exhibit 10.23 to the Company’s Form 10-K for the fiscal year ended September 30, 2002.
|
|
10.16*
|
-
|
Automated Meter Reading Services Agreement executed March 11, 2005; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended March 31, 2005. Confidential portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.
|
|
10.17*
|
-
|
The Laclede Group, Inc. Annual Incentive Plan; filed as Appendix 1 to the Company’s proxy statement filed December 17, 2010.
|
|
10.18*
|
-
|
The Laclede Group, Inc. 2006 Equity Incentive Plan; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended March 31, 2012.
|
|
10.18a*
|
-
|
Form of Restricted Stock Award Agreement filed as Exhibit 10.8 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
|
|
10.18b*
|
-
|
Form of Performance Contingent Restricted Stock Award Agreement; filed as Exhibit 10.2 to the Company’s 10-Q for the fiscal quarter ended December 31, 2009.
|
|
10.18c*
|
-
|
Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended December 31, 2011.
|
|
10.18d*
|
-
|
Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company's Form 10-Q for the fiscal quarter ended December 31, 2012.
|
|
10.19*
|
-
|
Amended and Restated Firm (Rate Schedule FT) Transportation Service Agreement between Laclede Energy Resources, Inc. and Centerpoint Energy Gas Transmission Company TSA #1006667; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended June 30, 2012.
|
|
10.20
|
-
|
Loan agreement with The Laclede Group, Inc. dated September 3, 2013 with several banks, including Wells Fargo Bank, National Association, as Administrative Agent, U. S. Bank National Association and JPMorgan Chase Bank, N. A. as Co-Syndication Agents; Bank of America, N.A., Fifth Third Bank and Morgan Stanley Bank, N.A., as Co-Documentation Agents; and Wells Fargo Securities LLC, U.S. Bank National Assocation and J.P. Morgan Securities LLC as Joint Lead Arrangers and Joint Bookrunners; and Commerce Bank, UMB Bank, N.A., and Stifel Bank & Trust as the other participating banks.
|
|
10.21*
|
-
|
The Laclede Group 2011 Management Continuity Protection Plan; filed as Exhibit 10.25 to the Company’s Form 10-K for the fiscal year ended September 30, 2010.
|
|
10.21a*
|
-
|
Form of Agreement Under The Laclede Group 2011 Management Continuity Protection Plan; filed as Exhibit 10.25a to the Company’s Form 10-K for the fiscal year ended September 30, 2010.
|
100
|
Exhibit
|
|
|
|
No.
|
|
|
|
10.22*
|
-
|
Severance Benefits Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
|
|
10.23*
|
-
|
Performance Contingent Restricted Stock Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.2 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
|
|
10.24*
|
-
|
Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.3 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
|
|
10.25*
|
-
|
Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Ex 10.25 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
|
|
10.26*
|
-
|
Performance Contingent Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Exhibit 10.26 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
|
|
10.27*
|
-
|
Severance Benefits Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Exhibit 10.27 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
|
|
10.28*
|
-
|
Note Purchase Agreement between The Laclede Group, Inc. and certain institutional purchasers effective August 3, 2012; filed as Exhibit 10.28 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
|
|
10.30*
|
|
Laclede Gas Company Cash Balance Supplemental Retirement Benefit Plan, effective as of January 1, 2009; filed as Exhibit 10.30 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
|
|
10.31*
|
Purchase and Sale Agreement between Southern Union Company, Plaza Missouri Acquisition, Inc. and The Laclede Group, Inc. (Solely for purposes of Section 13.19 of the Agreement) dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.1 to Form 8-K.
|
|
|
10.31a*
|
Employee Agreement between Southern Union Company, Plaza Missouri Acquisition, Inc. and, for purposes of Section 13.19 of the Purchase and Sale Agreement, dated of even date herewith, to the extent incorporated herein, The Laclede Group, Inc. dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.3 to Form 8-K.
|
|
|
10.31b*
|
Assignment and Assumption Agreement by and between Plaza Missouri Acquisition, Inc. and Laclede Gas Company dated as of January 11, 2013; filed January 11, 2013 as Exhibit 99.1 to the Company's Form 8-K.
|
|
|
10.31c*
|
Consent to Assignment executed by Southern Union Company dated as of January 11, 2013; filed January 11, 2013 as Exhibit 99.2 to the Company's Form 8-K.
|
|
|
10.32*
|
Purchase and Sale Agreement between Southern Union Company, Plaza Massachusetts Acquisition, Inc. and The Laclede Group, Inc. (Solely for purposes of Section 13.19 of the Agreement) dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.2 to Form 8-K.
|
|
|
10.32a*
|
Employee Agreement between Southern Union Company, Plaza Massachusetts Acquisition, Inc. and, for purposes of Section 13.19 of the Purchase and Sale Agreement, dated of even date herewith, to the extent incorporated herein, The Laclede Group, Inc. dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.4 to Form 8-K.
|
|
|
10.32b*
|
Stock Purchase Agreement by and among The Laclede Group, Inc., Plaza Massachusetts Acquisition, Inc., and Algonquin Power & Utilities Corp. dated as February 11, 2013; filed February 11, 2013 as Exhibit 2.1 to the Company Form 8-K.
|
|
|
10.32c*
|
Consent Agreement by and among The Laclede Group, Inc., Plaza Massachusetts Acquisition, Inc. Southern Union Company and Algonquin Power & Utilities Corp. dated as of February 11, 2013; filed February 11, 2013 as Exhibit 2.2 to the Company Form 8-K.
|
|
|
12
|
-
|
Ratio of Earnings to Fixed Charges.
|
|
21
|
-
|
Subsidiaries of the Registrant.
|
|
23
|
-
|
Consent of Independent Registered Public Accounting Firm.
|
|
31
|
-
|
Certificates under Rule 13a-14(a) of the CEO and CFO of The Laclede Group, Inc.
|
|
32
|
-
|
Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of The Laclede Group, Inc.
|
|
101.INS
|
-
|
XBRL Instance Document. (1)
|
|
101.SCH
|
-
|
XBRL Taxonomy Extension Schema. (1)
|
|
101.CAL
|
-
|
XBRL Taxonomy Extension Calculation Linkbase. (1)
|
101
|
Exhibit
|
|
|
|
No.
|
|
|
|
101.DEF
|
-
|
XBRL Taxonomy Definition Linkbase. (1)
|
|
101.LAB
|
-
|
XBRL Taxonomy Extension Labels Linkbase. (1)
|
|
101.PRE
|
-
|
XBRL Taxonomy Extension Presentation Linkbase. (1)
|
|
(1)
|
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Statements of Consolidated Income for the years ended September 30, 2013, 2012, and 2011; (iii) Statements of Consolidated Comprehensive Income for the years ended September 30, 2013, 2012, and 2011; (iv) Consolidated Statements of Common Shareholders’ Equity for the years ended September 30, 2013, 2012, and 2011; (v) Statements of Consolidated Cash Flows for the years ended September 30, 2013, 2012, and 2011; (vi) Consolidated Balance Sheets at September 30, 2013 and 2012; (vii) Statements of Consolidated Capitalization at September 30, 2013 and 2012;
|
(viii) Notes to the Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
*Incorporated herein by reference and made a part hereof. the Company’s File No. 1-16681.
Bold items reflect management, contract or compensatory plan or arrangement.
102
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters, and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IV