UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.
FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended September 30, 2015
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
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(X)[ X ] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2013 |
| For the fiscal year ended September 30, 2015 |
( ) | OR |
| [ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___ For the Transition Period from to |
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| Commission File Number | | Registrant, Address and Telephone Number | | State of Incorporation | | I.R.S. Employer Identification Number |
| 1-16681 | | CommissionThe Laclede Group, Inc.
File700 Market Street
St. Louis, MO 63101 Telephone Number | Registrant | State of
Incorporation
| IRS Employer
Identification Number 314-342-0878
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| Missouri | | 1-781074-2976504 |
| 1-1822 | Energen | Laclede Gas Company 700 Market Street St. Louis, MO 63101 Telephone Number 314-342-0878 | | Missouri | | 43-0368139 |
| 2-38960 | | Alabama Gas Corporation 2101 6th Avenue North Birmingham, Alabama 35203 Telephone Number 205-326-8100 | | Alabama | 63-0757759 | |
| 2-38960 | Alabama Gas Corporation | Alabama | 63-0022000 | |
605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707
Telephone Number (205) 326-2700
http://www.energen.com
Securities Registered Pursuantregistered pursuant to Section 12(b) of the Act:Act
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| Title of Each Class | | Name of Each Exchange onOn Which Registered |
Energen Corporation The Laclede Group, Inc. | Common Stock $0.01$1.00 par value | | New York Stock Exchange |
| Laclede Gas Company | None | Not applicable |
| Alabama Gas Corporation | None | Not Applicable |
Securities Registered Pursuantregistered pursuant to Section 12(g) of the Act: NONE
The Laclede Group, Inc.Yes [ ]No [ X ]
Laclede Gas CompanyYes [ ]No [ X ]
Alabama Gas CorporationYes [ ]No [ X ]
Indicate by check mark if the registrants arewhether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES (X) NO ( )
The Laclede Group, Inc.Yes [ X ]No [ ]
Laclede Gas CompanyYes [ ]No [ X ]
Alabama Gas CorporationYes [ ]No [ X ]
Indicate by check mark if the registrants areregistrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.act.
YES ( ) NO (X)The Laclede Group, Inc.Yes [ ]No [ X ]
Laclede Gas CompanyYes [ ]No [ X ]
Alabama Gas CorporationYes [ ]No [ X ]
Indicate by a check mark whether registrantseach registrant (1) havehas filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants wereregistrant was required to file such reports)report), and (2) havehas been subject to such filing requirements for the past 90 days. YES (X) NO ( )
The Laclede Group, Inc.Yes [ X ] No [ ]
Laclede Gas CompanyYes [ X ] No [ ]
Alabama Gas CorporationYes [ X ]No [ ]
Indicate by check mark whether theeach registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Energen Corporation YES (X) NO ( )The Laclede Group, Inc. Yes [ X ] No [ ]
Laclede Gas CompanyYes [ X ] No [ ]
Alabama Gas Corporation YES (X) NO ( )
Yes [ X ] No [ ]
Indicate by a 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. ( )
The Laclede Group, Inc.[ X ]
Laclede Gas Company[ X ]
Alabama Gas Corporation[ 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”filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Energen Corporation Large accelerated filer (X) Accelerated filer ( ) Non-accelerated filer ( ) Smaller reporting company ( )Alabama Gas Corporation Large accelerated filer ( ) Accelerated filer ( ) Non-accelerated filer (X) Smaller reporting company ( ) |
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| Large accelerated filer | | Accelerated filer | | Non- accelerated filer | | Smaller reporting company |
| The Laclede Group, Inc. | X | | | | | | |
| Laclede Gas Company | | | | | X | | |
| Alabama Gas Corporation | | | | | X | | |
Indicate by check mark whether the registrants areeach registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ( ) NO (X)
The Laclede Group, Inc.Yes [ ]No [ X ]
Laclede Gas CompanyYes [ ]No [ X ]
Alabama Gas CorporationYes [ ]No [ X ]
AggregateThe aggregate market value of the voting stock held by non-affiliates of the registrantsThe Laclede Group, Inc. amounted to $2,145,801,563 as of June 30, 2013:March 31, 2015. All of Laclede Gas Company's and Alabama Gas Corporation's equity securities are owned by The Laclede Group, Inc., their parent company and a 1934 Act Reporting Company. Laclede Gas Company and Alabama Gas Corporation meet the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2) to Form 10-K.
The number of shares outstanding of each registrant’s common stock as of November 20, 2015 was as follows:
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EnergenThe Laclede Group, Inc. | | Common Stock, par value $1.00 per share | | 43,350,411 |
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| Laclede Gas Company | | Common Stock, par value $1.00 per share (all owned by The Laclede Group, Inc.) | | 24,577 |
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| Alabama Gas Corporation | | $3,809,442,960Common Stock, par value $0.01 per share (all owned by The Laclede Group, Inc.) | | 1,972,052 |
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Indicate number
Document Incorporated by Reference:
Portions of shares outstanding of each ofProxy Statement for Laclede Group, Inc. to be filed on or about December 18, 2015 — Part III. Exhibit Index is found on page 145.
This combined Form 10-K represents separate filings by The Laclede Group, Inc. Laclede Gas Company, and Alabama Gas Corporation. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes no representation as to information relating to the registrant’s classes of common stock as of February 14, 2014:
other registrant, except that information relating to Laclede Gas Company and Alabama Gas Corporation is also attributed to The Laclede Group, Inc. |
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Energen Corporation | | 72,713,965 shares |
Alabama Gas Corporation | | 1,972,052 shares |
Alabama Gas Corporation meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2).
DOCUMENTS INCORPORATED BY REFERENCE
Energen Corporation Proxy Statement to be filed on or about March 21, 2014 (Part III, Item 10-14)
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INDUSTRY GLOSSARY
For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.
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Basis | The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing. |
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Basin-Specific | A type of derivative contract whereby the contract’s settlement price is based on specific geographic basin indices. |
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Behind Pipe Reserves | Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs. |
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Cash Flow Hedge | The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale. |
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Collar | A financial arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price. |
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Development Costs | Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves. |
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Development Well | A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. |
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Downspacing | An increase in the number of available drilling locations as a result of a regulatory commission order. |
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Dry Well | An exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. |
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Exploration Expenses | Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds. |
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Exploratory Well | A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. |
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Futures Contract | An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts. |
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Hedging | The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility. |
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Gross Revenues | Revenues reported after deduction of royalty interest payments. |
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Gross Well or Acre | A well or acre in which a working interest is owned. |
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Liquified Natural Gas (LNG) | Natural gas that is liquified by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand. |
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Long-Lived Reserves | Reserves generally considered to have a productive life of approximately 10 years or more, as measured by the reserves-to-production ratio. |
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Natural Gas Liquids (NGL) | Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons. |
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Net Well or Acre | A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. |
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Odorization | The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell. |
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Operational Enhancement | Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs. |
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Operator | The company responsible for exploration, development and production activities for a specific project. |
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Pay-Add | An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s). |
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Pay Zone | The formation from which oil and gas is produced. |
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Production (Lifting) Costs | Costs incurred to operate and maintain wells.
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Productive Well | An exploratory or a development well that is not a dry well. |
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Proved Developed Reserves | The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. |
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Proved Reserves | Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. |
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Proved Undeveloped Reserves (PUD) | The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. |
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Recompletion | An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone. |
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Reserves-to-Production Ratio | Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable reserves. |
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Secondary Recovery | The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts. |
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Service Well | A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste. |
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Sidetrack Well | A new section of wellbore drilled from an existing well. |
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Swap | A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or “swap” variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk. |
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Transportation | Moving gas through pipelines on a contract basis for others. |
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Throughput | Total volumes of natural gas sold or transported by the gas utility. |
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Working Interest | Ownership interest in the oil and gas properties that is burdened with the cost of development and operation of the property. |
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Workover | A major remedial operation on a completed well to restore, maintain, or improve the well’s production such as deepening the well or plugging back to produce from a shallow formation. |
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-e | Following a unit of measure denotes that the gas components have been converted to barrels of oil equivalents at a rate of 1 barrel per 6 thousand cubic feet. |
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| ENERGEN CORPORATION
2013 FORM 10-K ANNUAL REPORT
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| TABLE OF CONTENTS | Page No. |
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| PART I | Page |
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Item 1. | Business | |
Item 1A. | Risk Factors | |
Item 1B. | Unresolved Staff Comments | |
Item 2. | Properties | |
Item 3. | Legal Proceedings | |
Item 4. | Mine Safety Disclosures | |
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| Purchases of Equity Securities | |
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| Results of Operations | |
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| Financial Disclosure | |
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| Executive Compensation11 | | |
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| Related Stockholder Matters | |
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GLOSSARY OF KEY TERMS AND ABBREVIATIONS
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| Alagasco | Alabama Gas Corporation or Alabama Utility | LNG | Liquefied natural gas |
| Alabama Utility | Alabama Gas Corporation or Alagasco; the utility serving the Alabama region | MGE | Missouri Gas Energy |
| AOCI | Accumulated other comprehensive income | Missouri Utilities | Laclede Gas Company (including MGE), the utilities serving the Missouri region |
| APSC | Alabama Public Service Commission | MMBtu | Million British thermal units |
| ASC | Accounting Standards Codification | MoPSC | Missouri Public Service Commission |
| APUC | Algonquin Power and Utilities Corp. | MRT | Enable Mississippi River Transmission LLC |
| Bcf | Billion cubic feet | NEG | New England Gas Company |
| CAM | Cost Allocation Manual | NYSE | New York Stock Exchange |
| CCM | Cost Control Mechanism | NYMEX | New York Mercantile Exchange, Inc. |
| CNG | Compressed Natural Gas | OCI | Other comprehensive income |
| DOE | Department of Energy | OTCBB | Over-the-counter bulletin board |
| EPA | US Environmental Protection Agency | PEPL | Panhandle Eastern Pipe Line Company, LP |
| ESR | Enhanced Stability Reserve | PGA | Purchased Gas Adjustment |
| ETE | Energy Transfers Equity, LP | PP&E | Property, plant, and equipment |
| FASB | Financial Accounting Standards Board | REX | Rockies Express Pipeline, LLC |
| FERC | Federal Energy Regulatory Commission | RSE | Rate Stabilization and Equalization |
| FIFO | First-in, first-out | SEC | US Securities and Exchange Commission |
| GAAP | Accounting principles generally accepted in the United States of America | SPA | Stock Purchase Agreement with Energen to purchase 100% of the common shares of Alabama Gas Corporation (Alagasco) |
| Gas Utility | Operating segment including the regulated operations of Laclede Gas Company and Alabama Gas Corporation | Spire | Laclede Group's compressed natural gas fueling solutions business |
| Gas Marketing | Operating segment including LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities | Southern Natural Gas | Southern Natural Gas Company, LLC |
| GSA | Gas supply adjustment | Southern Star | Southern Star Central Gas Pipeline, Inc. |
| ICE | Intercontinental Exchange | SUG | Southern Union Company |
| ISRS | Infrastructure System Replacement Surcharge | TGIT | Tallgrass Interstate Gas Transmission, LLC |
| LER | Laclede Energy Resources, Inc. | TSR | Total shareholder return |
| LG | The Laclede Group, Inc. | Transco | Transcontinental Gas Pipe Line Company, LLC |
| LGC | Laclede Gas Company | US | United States |
| LIBOR | London Inter-Bank Offered Rate | | |
| LIFO | Last-in, first-out | | |
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This Form 10-K is filed on behalf of Energen Corporation (Energen or the Company)PART I
FORWARD-LOOKING STATEMENTS
and Alabama Gas Corporation (Alagasco).
Forward-Looking Statements: The disclosure and analysisCertain matters discussed in this 2013 Annual Report on Form 10-K containsreport, 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 express management’sinvolve uncertainties and risks. Future developments may not be in accordance with our current expectations or beliefs and the effect of future plans, objectivesdevelopments 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 performancecatastrophic events, particularly severe weather in the natural gas producing areas of the Companycountry;
Volatility in gas prices, particularly sudden and its subsidiaries. Such statements constitutesustained 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 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;
The recent acquisitions may not achieve their intended results, including anticipated cost savings;
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;
The availability and access, in general, of funds to meet our debt obligations prior to or when they become due and to fund our operations and necessary capital expenditures, either through (i) cash on hand, (ii) operating cash flow, or (iii) access to the capital or credit markets;
Retention of, ability to attract, ability to collect from, and conservation efforts of, customers;
Our ability to comply with all covenants in our indentures and credit facilities any violations of which, if not cured in a timely manner, could trigger a default of our obligations under cross-default;
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, including but not limited to labor disputes and future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets.
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 withinmade in this report rely upon the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted bysafe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.
All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental and regulatory obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, acts of nature, sabotage, terrorism (including cyber-attacks) and other similar acts that disrupt operations or cause damage greater than covered by insurance, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this 10-K and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.
See Item 1A, Risk Factors, for a discussion of risk factors that may affect the Company and cause material variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference into this forward-looking statement disclosure.
Except as otherwise disclosed, the forward-looking statementsWe do not, reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakesby including this statement, assume any obligation to correctreview or updaterevise any particular forward-looking statements whether as a resultstatement in light of new information, future events or otherwise.events.
ITEM 1.BUSINESS
OVERVIEW
General
Energen Corporation is an oilThe Laclede Group, Inc. (Laclede Group or the Company) formed in 2000 and, gas explorationeffective October 1, 2001, became the public utility holding company for Laclede Gas Company (Laclede Gas or the Missouri Utilities). Laclede Gas was founded in 1857 as The Laclede Gas Light Company and production company complemented by its legacy natural gas distribution business. Headquarteredit was listed on the New York Stock Exchange (NYSE) in Birmingham, Alabama,1889, making the Company successor to the eighth longest listed stock on the NYSE. The Laclede Gas Light Company was renamed Laclede Gas Company in 1950.
Laclede Group is committed to transforming its business and pursuing growth by: 1) growing its Gas Utility business through prudent investment in infrastructure upgrades and organic growth initiatives; 2) acquiring and integrating gas utilities; 3) modernizing its gas assets; and 4) investing in innovation and emerging markets.
The Company has two key business segments: Gas Utility and Gas Marketing. The Gas Utility segment includes the regulated operations of Laclede Gas and Alabama Gas Corporation (Alagasco or the Alabama Utility) (collectively, the Utilities). Laclede Gas, a public utility engaged in the development and exploration of oil, natural gas and natural gas liquids in the continental United States and in the purchase, retail distribution and sale of natural gas, is the largest natural gas distribution utility system in Missouri, serving more than 1.1 million residential, commercial and industrial customers, and is headquartered in St. Louis, Missouri. Laclede Gas serves St. Louis and eastern Missouri and, through Missouri Gas Energy (MGE), Kansas City and western Missouri. MGE was acquired by Laclede Gas on September 1, 2013. Alagasco is a public utility engaged in the purchase, retail distribution and sale of natural gas principally in central and northnorthern Alabama, serving more than 0.4 million residential, commercial and industrial customers with primary offices located in Birmingham, Alabama. Its two principalThe Company purchased 100% of the common shares of Alagasco from Energen Corporation (Energen) effective on August 31, 2014.
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, 2015, Laclede Group had 3,078 employees, Laclede Gas had 2,169 employees (including 22 employees dedicated to LER and other subsidiaries are Energen Resources Corporationof the Company), and Alabama Gas Corporation (Alagasco).Alagasco had 909 employees.
Alagasco was formedThe business of the Utilities is subject to seasonal fluctuations with the peak period occurring in 1948the winter heating season, typically November through April of each fiscal year. Consolidated operating revenues contributed by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became publicly traded in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco. Energen was incorporated in 1978 in preparationeach segment for the 1979 corporate reorganizationlast three fiscal years are presented below. For more detailed financial information regarding the segments, see Note 14, Information by Operating Segment, of the Notes to Financial Statements in whichItem 8. |
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| (Dollars in millions) | 2015 | | 2014 | | 2013 |
| Gas Utility | $ | 1,891.8 |
| | $ | 1,462.6 |
| | $ | 847.2 |
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| Gas Marketing | 84.6 |
| | 164.6 |
| | 169.8 |
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| Total Operating Revenues | $ | 1,976.4 |
| | $ | 1,627.2 |
| | $ | 1,017.0 |
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2015 Gas Utility operating results include twelve months each of MGE and Alagasco revenues. 2014 Gas Utility operating results include twelve months of MGE revenues and Energen Resources became subsidiariesone month of Energen.Alagasco revenues. 2013 Gas Utility operating results include one month of MGE revenues.
Laclede Group’s common stock is listed on the New York Stock Exchange (NYSE) and trades under the ticker symbol “LG.” The following table reflects Laclede Group shares issued during the two most recent fiscal years:
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| | 2015 | | 2014 |
| Common Stock Issuance | — |
| | 10,350,000 |
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| Dividend Reinvestment and Stock Purchase Plan (DRIP) | 31,166 |
| | 33,667 |
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| Equity Incentive Plan | 125,441 |
| | 97,902 |
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| Total Shares Issued | 156,607 |
| | 10,481,569 |
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During fiscal 2015 and 2014, shares were issued at historically consistent levels for Laclede Group's DRIP and Equity Incentive Plan. Shares were issued during 2014 to effect the Alagasco acquisition.
The Company maintains a Web site with the addressDuring fiscal 2015, neither Laclede Gas nor Alagasco issued shares to Laclede Group, but during fiscal 2014 Laclede Gas issued 28 shares. For more detailed common stock information of Laclede Group, Laclede Gas and Alagasco, see www.energen.comItem 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.The Company does not includeinformation Laclede Group, Laclede Gas and Alagasco file or furnish to the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site theSecurities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and anytheir amendments, to these reports. Also, these reportsand proxy statements are available free of charge under "SEC Filings and Annual Reports" in print upon shareholder request. These reports are availablethe Investor Relations section of
Laclede Group's website, www.TheLacledeGroup.com, as soon as reasonably practicablepractical after being electronicallythe information is filed with or furnished to the Securities and Exchange Commission. SEC. Information contained on Laclede Group's website is not incorporated by reference in this report.
GAS UTILITY
Natural Gas Supply
The Company’s Web site also includes its Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Officers’ Review Committee Charter and Governance and Nominations Committee Charter, eachUtilities' fundamental gas supply strategy is to meet the two-fold objective of which1) ensuring a dependable gas supply is available in print upon shareholder request.for delivery when needed and 2) insofar as is compatible with that dependability, purchasing gas that is economically priced. In structuring their natural gas supply portfolio, the Utilities focus on natural gas assets that are strategically positioned to meet the Utilities' primary objectives.
Laclede Gas
Laclede Gas 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. In eastern Missouri, 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. In western Missouri, both Mid-Continent and Rocky Mountain gas sources are utilized by MGE to provide a level of supply diversity that accesses low cost supplies while providing a natural gas price arbitrage.
Financial Information About Industry Segments
In fiscal year 2015, Laclede Gas purchased natural gas from 41 different suppliers to meet its total service area current gas sales and storage injection requirements. Laclede Gas 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 Laclede Gas for delivery to its service area through the Enable Mississippi River Transmission LLC (MRT) system totaled 60.5 billion cubic feet (Bcf). Laclede Gas also holds firm transportation on several other interstate pipeline systems that provide access to gas supplies upstream of MRT. In addition to natural gas deliveries from MRT, 57.2 Bcf was purchased on the Southern Star Central Gas Pipeline, Inc. (Southern Star), 10.0 Bcf was purchased on the MoGas Pipeline LLC (MoGas), 2.9 Bcf was purchased on the Tallgrass Interstate Gas Transmission, LLC (TGIT) system, 1.1 Bcf was purchased on the Panhandle Eastern Pipe Line Company, LP (PEPL) system, and 0.6 Bcf was purchased on the Rockies Express Pipeline, LLC (REX) system. Some of Laclede Gas’ commercial and industrial customers purchased their own gas with Laclede Gas transporting 42.9 Bcf to them through its distribution system.
The information required by this item is provided in Note 20, Industry Segment Information, in the Notes to Financial Statements.
Narrative Descriptionfiscal year 2015 peak day send out of Business
Oil and Gas Operations
General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the development of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All oil, gas and natural gas liquids production is sold to third parties. Energen Resources also provides operating servicesLaclede Gas customers in both eastern and western Missouri, including transportation customers, occurred on January 7, 2015. The average temperature was 7.0 degrees Fahrenheit in St. Louis and 8.0 degrees Fahrenheit in Kansas City. On that day, the Permian and San Juan basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.
At the end of 2013, Energen Resources’ proved oil and gas reserves totaled 347.8 million barrels of oil equivalent (MMBOE). Substantially all of these reserves are located in the Permian Basin in west Texas and the San Juan Basin in New Mexico and Colorado. Approximately 75 percent of Energen Resources’ year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 15 years. Oil, natural gas and natural gas liquids represent approximately 47 percent, 35 percent and 18 percent, respectively, of Energen Resources’ proved reserves.
In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which is reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97Missouri Utilities' customers consumed 1.67 Bcf of natural gas.
In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas For eastern Missouri, about 76% of this peak day demand was met with natural gas transported to St. Louis through the MRT, MoGas, and oil properties for $31.5 million (subject to closing adjustments). The Company expects to completeSouthern Star transportation systems, and the sale in the first quarter of 2014other 24% was met from Laclede Gas' on-system storage and will use the proceeds to repay short-term obligations. During the third quarter of 2013, Energen Resources classified thesepeak shaving resources. For western Missouri, this peak day demand was met with natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively,transported to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.
Growth Strategy: Energen operates under a strategy to grow the oil and gas operations of Energen Resources largelyKansas City through the development of provedSouthern Star, PEPL, TGIT, and unproved reserves and through the exploration in and around the basins in which it operates. Energen Resources focuses on increasing production and reserves through development well drilling, exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery, and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of drilling and development activities. Energen Resources operated approximately 95 percent of its proved reserves at December 31, 2013.REX transportation systems.
Alagasco
Since the end of fiscal year 1995, Energen Resources has invested approximately $1.9 billion to acquire proved and unproved reserves, $4.3 billion in related development and $1.7 billion in exploration. Energen Resources’ capital spending plans for 2014 target a total investment of approximately $1.05 billion, the bulk of which will focus on drilling and related development activities on its existing properties, with approximately 99 percent targeting the liquids-rich Permian Basin. The Company may choose to allocate additional capital during the year for property acquisitions and/or increased drilling and development activities.
Energen Resources’ development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.
During the three years ended December 31, 2013, the Company’s development and exploratory efforts have added 139 MMBOE of proved reserves from the drilling of 1,308 gross development, exploratory and service wells (including 11 sidetrack wells) and 289 well recompletions and pay-adds. In 2013, Energen Resources’ successful development and exploratory wells and other activities added approximately 37 MMBOE of proved reserves; the Company drilled 347 gross development, exploratory and service wells (including no sidetrack wells), performed some 87 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production from continuing operations totaled 23.3 MMBOE in 2013 and in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE, including approximately 22.1 MMBOE of estimated production from proved reserves owned at December 31, 2013.
Drilling Activity: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
|
| | | | | |
| Years ended December 31, | 2013 | 2012 | 2011 |
| Development: | | | |
| Productive | 169.5 |
| 239.9 |
| 370.3 |
| Dry | — |
| — |
| 3.3 |
| Total | 169.5 |
| 239.9 |
| 373.6 |
| Exploratory: | | | |
| Productive | 89.1 |
| 74.1 |
| 23.3 |
| Dry | 0.9 |
| 1.1 |
| 1.0 |
| Total | 90.0 |
| 75.2 |
| 24.3 |
As of December 31, 2013, the Company was participating in the drilling of 5 gross development and 11 gross exploratory wells, with the Company’s interest equivalent to 2.2 wells and 9.4 wells, respectively. In addition to the development wells drilled, the Company drilled 9.8, 47.8 and 29.1 net service wells during 2013, 2012 and 2011, respectively.
Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2013, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
|
| | | | |
| | Gross |
| Net |
|
| Oil wells | 4,876 |
| 3,262 |
|
| Gas wells | 3,305 |
| 1,616 |
|
| Developed acreage | 654,848 |
| 480,983 |
|
| Undeveloped acreage | 164,416 |
| 112,732 |
|
There were 10 wells with multiple completions in 2013. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas and Colorado.
Concentration of Credit Risk:Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest oil and gas purchasers accounted for approximately 35 percent and 12 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2013. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2013. During the year ended December 31, 2013, Plains Marketing, LP, accounted for approximately 25 percent of consolidated total operating revenues. All other oil and gas purchasers each accounted for less than 10 percent of consolidated total operating revenues for the year ended December 31, 2013.
Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of swaps and basis hedges. Energen Resources does not hedge more than 80 percent of its estimated annual production. Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions.
Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
See the Forward-Looking Statements preceding Item 1, Business, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.
Natural Gas Distribution
General: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers’ facilities.
Alagasco’s service territory is located in central and parts of north Alabama and includes 187 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.5 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2013, Alagasco served an average of 391,093 residential customers and 31,174 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 11,229 miles of main and more than 12,015 miles of service lines, odorization and regulation facilities, and customer meters.
APSC Regulation: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Alagasco’s current RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range.
Alagasco’s allowed range of return on average equity was 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. Through December 31, 2013, RSE limited the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless Alagasco exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain
items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.
Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.
The APSC approved an Enhanced Stability Reserve (ESR) in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.
Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which prescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year period with an annual limitation of $660,000.
Gas Supply:Alagasco’s distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company, (Southern)L.L.C. (Southern Natural Gas) and Transcontinental Gas Pipe Line Company, LLC (Transco). It is also connected to two intrastate natural gas pipeline systems and to Alagasco’s two liquified natural gas (LNG) facilities.
systems.
Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco’s system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system’s varying levels of demand. Alagasco’s
In fiscal year 2015, Alagasco purchased natural gas from 15 different suppliers to meet current gas sales, storage injection, and LNG liquefaction requirements, of which six are under long-term supply agreements. Approximately 62.7 Bcf was transported by Southern Natural Gas, 7.1 Bcf by Transco, and 5.3 Bcf through intrastate pipelines to the Alagasco delivery points for its residential, commercial, and industrial customers.
The fiscal year 2015 peak day send out for Alagasco was 0.6 Bcf on January 7, 2015, when the average temperature was 22.0 degrees Fahrenheit in Birmingham, of which 84% was met with supplies transported through Southern Natural Gas, Transco and intrastate facilities and 16% was met with supplies from Alagasco's four liquefied natural gas (LNG) peak shaving facilities.
Natural Gas Storage
Laclede Gas
For its eastern service area, Laclede Gas has a contractual right to store 21.6 Bcf of gas in MRT’s storage facility located in Unionville, Louisiana, and for its western service area 16.3 Bcf of gas storage in Southern Star system storage facilities located in Kansas and Oklahoma, as well as 1.4 Bcf of firm storage on PEPL’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 2.1 Bcf from November 16 through May 15. Southern Star 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, in eastern Missouri, Laclede Gas supplements 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 approximately 0.3 Bcf of natural gas withdrawals on a peak day and maximum annual net withdrawals of approximately 4.0 Bcf of natural gas based on the inventory level that Laclede Gas plans to maintain.
Alagasco
Alagasco has a contractual right to store 12.5 Bcf of gas with Southern Natural Gas, 0.2 Bcf of gas with Transco and 0.2 Bcf of gas with Tennessee Gas Pipeline. In addition, the Alagasco has 1.8 Bcf of LNG storage that can provide the system with up to an additional 200,000 thousand cubic feet per day (Mcfd)0.2 Bcf of natural gas daily to meet peak day demand.
As of December 31, 2013, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:
|
| | |
| December 31, 2013 |
| (Mcfd) |
Southern firm transportation | 112,933 |
|
Southern storage and no notice transportation | 231,679 |
|
Transco firm transportation | 70,000 |
|
Various intrastate transportation | 20,240 |
|
Regulatory Matters
Competition:For details on regulatory matters, see Note 15The price, Regulatory Matters, of the Notes to Financial Statements in Item 8.Other Pertinent Matters
Laclede Gas is the only distributor of natural gas within its franchised service areas, while Alagasco is the main distributor of natural gas in its service areas. The principal competition for the Utilities comes from the local electric companies. Other competitors in the service areas include suppliers of fuel oil, coal, propane, natural gas pipelines that can directly connect to large volume customers, for the Missouri Utilities, district steam systems in the downtown areas of both St. Louis and Kansas City, and for Alagasco, from municipally or publicly owned gas distributors located adjacent to its service territory. Coal is price competitive as a significantfuel 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 factor in Alagasco’s service territory, particularly among largewith gas for downtown St. Louis and Kansas City area heating users.
Laclede Gas' residential, commercial, and small industrial transportation customers. Propane, coalmarkets represented approximately 91% of its operating revenue for fiscal 2015. Alagasco's residential, commercial, and fuel oil are readily available,small industrial markets represented approximately 79% of its operating revenue for the twelve months ended September 30, 2015. Given the current level of natural gas supply and many industrial customers havemarket conditions, the capabilityUtilities believe 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 switch to alternate fuels and alternate sources ofbe supplied by natural gas. In new multi-family and commercial rental markets, the residentialUtilities' competitive exposures are presently limited to space and smallwater heating applications. Certain alternative heating systems can be cost competitive in traditional markets.
Laclede Gas offers gas transportation service to its large-user industrial and commercial and industrial markets, electricity iscustomers. The tariff approved for that type of service produces a margin similar to that which the principal competitor. With the support of the APSC, Alagasco has implemented a variety of programs to help it compete for gas load in all market segments. The Company has been effective at utilizing these programs to avoid load loss to competitive fuels.
Missouri Utilities would have received under their regular sales rates. Alagasco’s Transportation Tarifftransportation tariff allows the CompanyAlabama Utility to transport gas for large commercial and industrial customers rather than buying and reselling it to them and is based on Alagasco’sthe Alabama Utility’s sales profit margin so that operating margins are unaffected. During 2013,2015, substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas.
The Utilities are subject to various environmental laws and regulations that, to date, have not materially affected the Utilities' or the Company’s financial position and results of operations. For a detailed discussion of environmental matters, see Note 16, Commitment and Contingencies, of the Notes to Financial Statements in Item 8.
Union Agreements
As of September 30, 2015, the Company had approximately 1,897 employees represented by organized labor unions. The Company believes labor relations with its employees are good. Should that condition change, the Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s results of operations and cash flows.
The following table presents the Company's various labor agreements as of September 30, 2015:
|
| | | | |
| Union | Local | Employees Covered | Contract Start Date | Contract End Date |
| Laclede Gas Company (eastern Missouri) | | | | |
| United Steel, Paper and Forestry, Rubber Manufacturing, Allied-Industrial and Service Workers International Union (USW) | 884 | 60 | August 1, 2015 | July 31, 2018 |
| USW | 11-6 | 858 | August 1, 2015 | July 31, 2018 |
| USW | 11-194 | 142 | August 1, 2015 | July 31, 2018 |
| | | | | |
| Missouri Gas Energy (western Missouri) | | | | |
| USW | 12561 | 126 | June 1, 2014 | July 31, 2016 |
| USW | 14228 | 38 | June 1, 2014 | July 31, 2016 |
| USW | 11-267 | 32 | June 1, 2014 | July 31, 2016 |
| Gas Workers Metal Trades locals of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada | 781-Kansas City | 193 | June 1, 2014 | July 31, 2016 |
| Gas Workers Metal Trades locals of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada | 781-Monett | 49 | June 1, 2014 | July 31, 2016 |
| International Brotherhood of Electrical Workers (IBEW) | 53 | 4 | April 30, 2014 | July 31, 2016 |
| | | | | |
| Total Laclede Gas Company | | 1,502 | | |
| | | | | |
| Alabama Gas Corporation | | | | |
| USW | 12030 | 212 | December 19, 2014 | April 30, 2017 |
| USW | 12030-A | 67 | May 1, 2014 | April 30, 2017 |
| United Association of Gas Fitters | 548 | 116 | July 1, 2013 | June 30, 2016 |
| | | | | |
| Total Alabama Gas Corporation | | 395 | | |
NaturalOperating Revenues and Customer Information
Revenues and therms sold and transported for the Gas Utility segment for the last three fiscal years are as follows (before intersegment eliminations):
|
| | | | | | | | | | | | |
| Gas Utility Operating Revenues | | | | | |
| (Dollars in millions) | 2015 | | 2014* | | 2013** |
| Residential | $ | 1,263.1 |
| | $ | 974.3 |
| | $ | 556.8 |
|
| Commercial & Industrial | 462.3 |
| | 357.1 |
| | 184.1 |
|
| Interruptible | 2.3 |
| | 2.1 |
| | 3.5 |
|
| Transportation | 92.2 |
| | 32.4 |
| | 15.3 |
|
| Off-System and Other Incentive | 76.2 |
| | 79.5 |
| | 90.2 |
|
| Provisions for Refunds and Other | (0.3 | ) | | 22.4 |
| | 7.9 |
|
| Total Utility Operating Revenues | $ | 1,895.8 |
| | $ | 1,467.8 |
| | $ | 857.8 |
|
| | | | | | |
| Gas Utility Therms Sold and Transported | | |
| | |
| (In millions) | 2015 | | 2014* | | 2013** |
| Residential | 1,065.1 |
| | 952.9 |
| | 496.6 |
|
| Commercial & Industrial | 491.6 |
| | 435.6 |
| | 229.6 |
|
| Interruptible | 3.6 |
| | 3.5 |
| | 3.1 |
|
| Transportation | 989.0 |
| | 484.6 |
| | 160.4 |
|
| System Therms Sold and Transported | 2,549.3 |
| | 1,876.6 |
| | 889.7 |
|
| Off-System | 193.5 |
| | 125.8 |
| | 229.4 |
|
| Total Utility Therms Sold and Transported | 2,742.8 |
| | 2,002.4 |
| | 1,119.1 |
|
| | | | | | | |
| * | Includes Alagasco for the one month ended September 30, 2014. |
| ** | Includes MGE for the one month ended September 30, 2013. |
The following table presents our Gas Utility customers for the last three fiscal years, based on an annual average number of customers:
|
| | | | | | | | | |
| Gas Utility Customers | 2015* | | 2014** | | 2013*** |
| Residential | 1,434,584 |
| | 1,418,422 |
| | 1,022,026 |
|
| Commercial & Industrial | 132,388 |
| | 133,799 |
| | 99,671 |
|
| Interruptible | 18 |
| | 18 |
| | 17 |
|
| Transportation | 796 |
| | 795 |
| | 513 |
|
| Total Utility Customers | 1,567,786 |
| | 1,553,034 |
| | 1,122,227 |
|
| | | | | | | |
| * | Includes MGE and Alagasco for the twelve months ended September 30, 2015. |
| ** | Includes Alagasco for the month of September 2014. The number of customers for 2014 is based on average customers over the twelve months ended September 30, 2014, while only including Alagasco customers for the month of ownership. Restated to align methodology. |
| *** | Includes MGE for the one month ended September 30, 2013. Restated to align methodology. |
Total annual average number of customer for Laclede Gas and Alagasco for fiscal 2015 was 1,148,339 and 419,447, respectively.
Laclede Gas has franchises in nearly all the communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows Laclede Gas, among other things, to install pipes and construct other facilities in the community. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of Laclede Gas' current public utility businesses in the state of Missouri. In recent years, although certain franchise agreements have expired, including Clayton, North Kansas City, Cameron, and Riverside, Laclede Gas has continued to provide service in those communities without formal franchises.
Alagasco has franchises in nearly all the communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows Alagasco, among other things, to install pipes and construct other facilities in the community. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of Alagasco's current public utility business in the state of Alabama.
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 Utilities' traditional service areas. During fiscal year 2015, LER utilized 17 interstate and intrastate pipelines and 107 suppliers to market natural gas to its customers primarily in the Midwest. LER served more than 225 retail customers and 120 wholesale customers. Through its retail operations, LER offers natural gas marketing services to large commercial and 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 majority of LER’s total business.
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 various pipelines from both pipeline companies and through the secondary capacity market from third parties. Throughout fiscal year 2015, LER held approximately 0.4 Bcf per day of firm transportation capacity. In addition, to ensure reliability of service and to provide operational flexibility, LER enters into firm storage contracts and interruptible park and loan transactions with various companies, where it is able to buy and retain gas to be delivered at a future date, at which time LER sells the natural gas to third parties. As of September 30, 2015, LER has contracted for approximately 4.5 Bcf of such storage and park and loan capacity for the 2015-2016 winter period.
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. Overall, fiscal 2015 had significantly fewer opportunities for LER due primarily to volatility and extreme price spikes as compared to fiscal 2014. However, LER was able to expand its producer services business and sales to power generation markets.
OTHER
The principal drivers of the Other results for fiscal 2015 and fiscal 2014 has been interest expense related to the 2014 debt issue to finance the Alagasco acquisition and expenses attributable to the Alagasco transaction and MGE integration.
This category also includes Laclede Pipeline Company, a 100% owned subsidiary of Laclede Group, which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction. This pipeline allows Laclede Gas to receive propane that may be used to supplement its natural gas supply and meet peak demands on its distribution system. Laclede Pipeline Company also provides transportation services to third parties.
Additionally, this category includes Laclede Group’s subsidiaries that are engaged in compression of natural gas, oil production, real estate development, risk management, and financial investments in other enterprises, among other activities. These operations are conducted through seven subsidiaries.
ITEM 1A. RISK FACTORS
Laclede Group’s and the Utilities' 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 and the Utilities consider to be material. When considering any investment in Laclede Group or the Utilities' 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 Group and Laclede Gas file with the SEC. This list is not exhaustive, and Laclede Group's and the Utilities' respective management places no priority or likelihood based on the risk descriptions, order of presentation or grouping by subsidiary. All references to dollar amounts are in millions.
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 Laclede Gas prior to Laclede Group’s formation, have paid dividends continuously since 1946. 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. In addition, because it is a holding company and the substantial portion of its assets are represented by its holdings in the Utilities, the risks faced by the Utilities as described under RISKS THAT RELATE TO THE GAS UTILITY SEGMENT below may also adversely affect Laclede Group’s cash flows, liquidity, financial condition and results of operations.
A downgrade in Laclede Group’s and/or its subsidiaries' credit ratings may negatively affect its ability to access capital.
Currently, Laclede Group and its utility subsidiaries have investment grade credit ratings, which are subject to review and change by the rating agencies. Laclede Group, Laclede Gas and Alagasco each have a working capital line of credit to meet its short-term liquidity needs. Laclede Group’s line of credit may also be used to meet the liquidity needs of any of its subsidiaries. If the rating agencies lowered the credit rating at any of these entities, particularly below investment grade, it might significantly limit such entity’s ability to secure new or additional credit facilities and would increase its costs of borrowing. Laclede Group’s or the Utilities’ ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on their ability to execute their operating strategies. In the fourth quarter of 2014, Laclede Group issued its first public debt and received its first senior unsecured debt ratings. Standard & Poor’s rated Laclede Group debt BBB+, one notch lower than its issuer rating of A-, while Fitch also rated the Laclede Group debt at BBB+, equal to its issuer rating, and Moody’s (which does not use issuer ratings) rated the Laclede Group debt at Baa2. These rating levels have no specific implications for Laclede Group's corporate funding ability or our ability to access the capital markets, nor do they trigger any collateralization requirements under Laclede Group's corporate guarantees. There is no assurance that such credit ratings for any of the Laclede Group companies will 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.
Unexpected losses may adversely affect Laclede Group’s or its subsidiaries 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 or any of its subsidiaries 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 and/or its subsidiaries' financial condition and results of operations.
Increased inter-dependence on technology may hinder Laclede Group’s and its subsidiaries' business operations and adversely affect their 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 Laclede Group and its subsidiaries' 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 or its subsidiaries' inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder their business operations and adversely impact their financial condition and results of operations.
Although the Company and its subsidiaries have, when possible, developed alternative sources of technology and built redundancy into their 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 the Utilities’ use of such technologies.
Laclede Gas completed the acquisition of the assets and liabilities of MGE near the end of fiscal 2013. Through fiscal 2015, Laclede Gas integrated MGE’s data into its systems, with the final migration to Laclede Gas' technology platforms occurring in September 2015.
The Company completed the acquisition of the common stock of Alagasco near the end of fiscal 2014. Alagasco utilizes a different ERP system which will remain in place pending review of the Company's long-term ERP needs during the integration process.
Furthermore, the Company and its subsidiaries are subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the Company and its subsidiaries 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 and its subsidiaries' reputation, diminish customer confidence, disrupt operations, and subject the Company and its subsidiaries to possible financial liability, any of which could have a material effect on the Company’s and its subsidiaries' financial condition and results of operations. The Company and its subsidiaries closely monitor both preventive and detective measures to manage these risks and maintain 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 and its subsidiaries' financial condition and results of operations.
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 recent MGE and Alagasco acquisitions, the opening of public compressed natural gas (CNG) stations or other future opportunities. 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 efficiencies 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 the Company's financial condition and 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.
In addition, to the extent Laclede Group engages in any of the above activities together with or through one or more of its subsidiaries, including the Utilities, such subsidiaries may face the same risks.
Workforce risks may affect the Company's financial results.
The Company and its subsidiaries are 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.
Changes in accounting standards may adversely impact the Utilities’ financial condition and results of operations.
Laclede Group and its subsidiaries are subject to changes in US Generally Accepted Accounting Principles (GAAP), SEC regulations and other interpretations of financial reporting requirements for public utilities. Neither the Company nor any of its subsidiaries have any control over the impact these changes may have on their 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 to GAAP that the US Financial Accounting Standards Board (FASB) continues to consider may be significant.
RISKS RELATED TO THE COMPANY'S AND ITS SUBSIDIARIES' ACQUISITION AND INTEGRATION ACTIVITIES
As a result of recent acquisitions, the Company and its subsidiaries are subject to risks related to its level of indebtedness.
In connection with the Alagasco and MGE acquisitions, Laclede Group and Laclede Gas incurred additional debt to pay a portion of the acquisition cost and transaction expenses. On August 19, 2014 Laclede Group issued unsecured debt in the aggregate principal amount of $625.0 to finance the acquisition of Alagasco. On August 13, 2013, Laclede Gas issued debt in the aggregate principal amount of $450.0 to finance the acquisition of MGE. Laclede Group's total consolidated indebtedness as of September 30, 2015 was $2,189.5 ($338.0 of short-term borrowings and $1,851.5 of long-term debt, including current portion) and Laclede Gas' total indebtedness as of September 30, 2015 was $1,041.1 ($233.0 of short-term borrowings, including borrowings from affiliates, and $808.1 of long-term debt).
Laclede Group’s and Laclede Gas' debt service obligations with respect to this increased indebtedness could have an adverse impact on their earnings and cash flows (which after the acquisitions include the earnings and cash flows of MGE and, in the case of Laclede Group, Alagasco) for as long as the indebtedness is outstanding. Among other risks, the increase in indebtedness may:
make it more difficult for Laclede Group or Laclede Gas to pay or refinance their debts as they become due during adverse economic and industry conditions;
limit the Company’s or Laclede Gas' flexibility to pursue other strategic opportunities or react to changes in its business and the industry in which they operate and, consequently, place them at a competitive disadvantage to competitors with less debt;
require an increased portion of the Company’s or Laclede Gas' cash flows from operations of their respective subsidiaries to be used for debt service payments, thereby reducing the availability of their cash flows to fund working capital, capital expenditures, dividend payments and other general corporate activities;
result in a downgrade in the credit rating of Laclede Group’s or the Utilities’ indebtedness, which could limit the Utilities’ ability to borrow additional funds or increase the interest rates applicable to Utilities’ 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 Alagasco customers fallssupport hedging activities; and
require that additional terms, conditions or covenants be placed on the Company or Laclede Gas.
Based upon current levels of operations, Laclede Group or Laclede Gas expect 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 their existing credit agreements, indentures and other instruments governing outstanding indebtedness; but there can be no assurance that Laclede Group or Laclede Gas 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 and Laclede Gas may consider it appropriate to reduce the amount of indebtedness outstanding following the acquisitions. This may be accomplished in several ways, including, in the case of Laclede Group, issuing additional shares of common stock or securities convertible into two broad categories: interruptibleshares of common stock, or in the case of Laclede Group or Laclede Gas, reducing discretionary uses of cash or a combination of these and firm. Interruptible service contractuallyother 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 Company, increasing the Company’s dividend payment obligations and perhaps reducing the reported earnings per share.
Recent acquisitions may not achieve their intended results, including anticipated efficiencies and cost savings.
Although the Company and its subsidiaries expect that the recent acquisitions will result in various benefits, including a significant cost savings and other financial and operational benefits, there can be no assurance regarding when or the extent to which the Company and its subsidiaries will be able to realize or retain these benefits. Achieving and retaining the anticipated benefits, including cost savings, is subject to interruption ata number of uncertainties, including whether the assets acquired can be operated in the manner the Company and its subsidiaries intended. Events outside of the control of the Company and its
subsidiaries, including but not limited to regulatory changes or developments, could also adversely affect their ability to realize the anticipated benefits from the acquisitions.
Thus, the integration of Alagasco may be unpredictable, subject to delays or changed circumstances, and the Company and its subsidiaries can give no assurance that the acquisitions will perform in accordance with their expectations or that their expectations with respect to integration or cost savings as a result of the Alagasco acquisition will materialize. In addition, the anticipated costs to the Company and its subsidiaries to achieve the integration of Alagasco may differ significantly from their current estimates. The integration may place an additional burden on management and internal resources, and the diversion of management’s attention during the integration process could have an adverse effect on the Company's and its subsidiaries' business, financial condition and expected operating results.
In connection with the MGE and the Alagasco acquisitions, Laclede Gas and Laclede Group, respectively, recorded goodwill and long-lived assets that could become impaired and adversely affect its financial condition and results of operations.
Laclede Group and Laclede Gas 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 and Laclede Gas will assess their 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 and Laclede Gas may be required to incur impairment charges that could have a material impact on their results of operations. No impairment of long-lived assets was recorded during 2015 or 2014.
Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of the Company's 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 and Laclede Gas 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 SEGMENT
Regulation of the Utilities’ businesses may impact rates they are able to charge, costs, and profitability.
The Utilities are subject to regulation by federal, state and local regulatory authorities. At the state level, the Utilities are regulated by regulatory authorities in Missouri by the Missouri Public Service Commission (MoPSC) and in Alabama by the Alabama Public Service Commission (APSC). The state regulatory authorities regulate many aspects of the Utilities’ distribution operations, including construction and maintenance of facilities, operations, safety, the rates that the Utilities may charge customers, the terms of service to their customers, transactions with their affiliates, and the rate of return that they are allowed to realize; as well as the accounting treatment for certain aspects of their operations. For further discussion of these accounting matters, see Item 7, Critical Accounting Policies pertaining to the Utilities’ operations. The Utilities’ ability to obtain and timely implement rate increases and rate supplements to maintain the current rate of return is subject to regulatory review and approval. There can be no assurance that they will be able to obtain rate increases or rate supplements or continue earning the current authorized rates of return. The first Missouri Utilities general rate case filed after October 1, 2015 must be for both the legacy Laclede Gas and the MGE operations. Alagasco’s discretion.rate setting process, Rate Stabilization and Equalization (RSE), is subject to regulation by the APSC and is implemented pursuant to an APSC order that will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with the law. Under the current RSE order, Alagasco is allowed to earn a return on average common equity between 10.5% and 10.95%. Quarterly reviews are conducted by the APSC and if it is determined that Alagasco will exceed the allowed range of return, rates are reduced to bring the projected return within the allowed range. Rates can only be increased once a year effective December 1. Alagasco’s year-end equity under RSE is limited to 56.5% of total capitalization, subject to certain adjustments. The most common reasonRSE order includes a Cost Control Mechanism (CCM) which requires Alagasco’s operation and maintenance expenses to be within an allowed index range based on inflation-adjusted from 2007 actual operation and maintenance (O&M) expenses. If O&M expenses exceed the index range, 75% of the amount over the range is returned to customers through future rate adjustments.
The Utilities 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 such interruptionthe natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If the Utilities fail to comply with applicable laws and regulations, whether existing or new, they could be subject to fines, penalties or other enforcement action by the authorities that regulate the Utilities’ operations.
The Utilities are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect their results of operations, cash flows and financial condition.
The Utilities are 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 Utilities to make payments in excess of amounts provided for in their financial statements, or to the extent they are not covered by insurance, could adversely affect the Utilities’ results of operations, cash flows and financial condition.
The Utilities’ liquidity may be adversely affected by delays in recovery of their costs, due to regulation.
In the normal course of business, there may be a lag between when the Utilities incur increases in certain of their 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 and APSC. Accordingly, the Utilities’ liquidity may be adversely impacted to the extent higher costs are not timely recovered from their customers. The first Missouri Utilities general rate case filed after October 1, 2015 is curtailmentrequired to be for both the legacy Laclede Gas and the MGE operations.
The Utilities’ ability to meet their 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 their customers’ annual and seasonal natural gas demands, the Utilities must obtain sufficient supplies, interstate pipeline capacity, and storage capacity. If they are unable to obtain these, either from their suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, the Utilities’ 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 peak core market heating demand. Customers who contract for interruptible service can generally adjust production schedules or switch to alternate fuelsheavy demand, the Utilities’ financial results could be adversely impacted.
The Utilities’ liquidity and, in certain circumstances, the Utilities’ results of operations may be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
The Missouri Utilities' tariff rate schedules contain Purchased Gas Adjustment (PGA) clauses and the Alabama Utility’s tariff rate schedule contains a Gas Supply Adjustment (GSA) rider that permit the Utilities to file for rate adjustments to recover the cost of service interruption or curtailment. More expensive firm service,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, the Missouri Utilities are allowed to adjust the gas cost component of rates up to four times each year while the Alabama Utility may adjust its gas cost component of its rates on a monthly basis. The Missouri Utilities must make a mandatory gas cost adjustment at the other hand, generallybeginning of the winter, in November, and during the next twelve months may make up to three additional discretionary gas cost adjustments, so long as each of these adjustments is notseparated by at least two months.
The MoPSC typically approves the Missouri Utilities' PGA changes on an interim basis, subject to interruptionrefund and the outcome of a subsequent audit and prudence review. Due to such review process, there is provideda risk of a disallowance of full recovery of these costs. Any material disallowance of purchased gas costs would adversely affect revenues. Alagasco's GSA changes are submitted for APSC review on a monthly basis, regardless of whether there is a request for a change, so prudence review occurs on an ongoing basis.
Increases in the prices the Utilities charge for gas may also adversely affect revenues because they could lead customers to residentialreduce usage and small commercialcause some customers to have trouble paying the resulting higher bills. These higher prices may increase bad debt expenses and industrial customers. These core market customers depend onultimately reduce earnings. 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, Laclede Gas enters into contracts to hedge the forward commodity price of its natural gas primarily for space heating.
Customers: Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco’s average customer count for 2013 declined approximately 0.6 percent from 2012supplies. As part of this strategy, Laclede Gas may use fixed-price, forward, physical purchase contracts, swaps, futures, and reflected a moderation in decline overoption contracts. However, Laclede Gas does not hedge the five-year trend. Other factors impacting Alagasco’s average customer count include recent weather trends, enhanced credit and collection effortsentire 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 Missouri Utilities' 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 Missouri Utilities' use of natural gas derivative instruments may cause short-term cash requirements to vary. These procedures remain subject to prudence review by the MoPSC.
The Alabama Utility currently does not utilize risk mitigation strategies that incorporate commodity hedge instruments, but has the ability to do so through its GSA.
The Utilities' business activities are concentrated in two states.
The Utilities provide natural gas distribution services to customers in Missouri and Alabama. Changes in the regional economies, politics, regulations and weather patterns of these states could negatively impact the Utilities' growth opportunities and the usage patterns and financial condition of customers and could adversely affect the Utilities' earnings, cash flow, and financial position.
The Utilities 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, a loss of existing customers, duefewer new customers especially in newly constructed buildings. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Utilities’ revenues and cash flows or restrict their future growth. Economic conditions in the Utilities’ service territories may also adversely impact the Utilities’ ability to a 2011 weather event.
Seasonality:Alagasco’s gas distribution business is highly seasonal since a material portion of the utility’s total sales and delivery volumes relate to space heating customers. Alagasco’s tariff includes a Temperature Adjustment Rider primarily for residential, small commercial and small industrial customers that moderates the impact of departures from normal temperatures on Alagasco’s earnings. The adjustments are made through the GSA.
collect accounts receivable, resulting in an increase in bad debt expenses.
Environmental Matterslaws and Climate Changeregulations may require significant expenditures or increase operating costs.
VariousThe Utilities are subject to federal, state and local environmental laws and regulations applyaffecting many aspects of their present and future operations. These laws and regulations require the Utilities 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 operationsUtilities in the form of Energen Resourcesfines, penalties or business interruptions, which may be material. In addition, existing environmental laws and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operationsregulations could be revised or cash flows. New regulations, enforcement policies, claims for damages reinterpreted and/or other events could result in significant unanticipated costs.
Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend and interpret existing laws and regulations. Such law and regulation changes may occur with little prior notification, subject the Company to cost increases, and impose restrictions and limitations on the Company’s operations. Currently, there are various proposed law and regulatory changes with the potential to materially impact the Company. Such proposals include, but are not limited to, measures dealing with hydraulic fracturing, emission limits and reporting and the repeal of certain oil and gas tax incentives and deductions. Duecould be adopted or become applicable to the natureUtilities or their facilities, thereby impacting the Utilities’ cost of the political and regulatory processes and based on its considerationcompliance. The discovery of existing proposals, the Company is unable to determine whether such proposed laws and regulations are reasonably likely to be enacted or to determine, if enacted, the magnitude of the potential impact of such laws.
Energen regularly utilizes hydraulic fracturing in its drilling and completion activities. The Company’s first widespread use of hydraulic fracturing occurred during the 1980s when we successfully pioneered the exploration and development of coalbed methane in Alabama’s Black Warrior Basin.
Hydraulic fracturing is a well-established reservoir stimulation technique used throughout the oil and gas industry for more than 60 years. After a well has been drilled, hydraulic fracturing is used during the completion process to form small fractures in the target formation through which the natural gas or oil can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the natural gas- or crude oil-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the natural gas or crude oil to flow from tight (low permeability) reservoirs into the well bore.
Various states in which we operate have adopted a variety of well construction, set back, and disclosure regulations limiting how drilling can be performed and requiring various degrees of chemical and water usage disclosure for operators that employ hydraulic fracturing. We are complying with these additional regulations as part of our routine operations and within the normal execution of our business plan. The adoption of additional federal or state regulations, however, could impose significant new costs and challenges. For example, adoption of new hydraulic fracturing permitting requirements could significantly delay or prevent new drilling. Adoption of new regulatory restrictions on the use of hydraulic fracturing could reduce the amount of oil and gas that we are able to recover from our reserves. The degree to which additional oil and gas industry regulation may impact our future operations and results will depend on the extent to which we utilize the regulated activity and whether the geographic locations in which we operate are subject to the new regulation.
Existing federal, state and localpresently unknown environmental laws and regulations also have the potential to increase costs, reduce liquidity, delay operations and otherwise alter business operations. These existing laws and regulations include, but are not limited to, the Clean Air Act; the Clean Water Act; Oil Pollution Prevention: Spill Prevention, Control, and Countermeasure regulations;
Toxic Substances Control Act; Resource Conservation and Recovery Act; and the Federal Endangered Species Act. Compliance with these and other environmental laws and regulations is undertaken as part of the Company’s routine operations. The Company does not separately track costs associated with these routine compliance activities.
Climate change, whether arising through natural occurrences or through the impact of human activities, may have a significant impact upon the operations of Energen Resources and Alagasco. Volatile weather patterns and the resulting environmental impact may adversely impact the results of operations, financial position and cash flows of the Company. The Company is unable to predict the timing or manifestation of climate change or reliably estimate the impact to the Company. However, climate change could affect the operations of the Company as follows:
sustained increases or decreases to the supply and demand of oil, natural gas and natural gas liquids;
positive or negative changes to usage and customer count at Alagasco from prolonged increases or decreases in average temperature for Alagasco’s central and north Alabama service territory;
potential disruption to third party facilities to which Energen Resources delivers and from which Alagasco is served. Such facilities include third party oil and gas gathering, transportation, processing and storage facilities and are typically limited in number and geographically concentrated.
Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.
During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.
Alagasco is in the chain of title of nineconditions, including former manufactured gas plant sites, four ofand claims against the Utilities under environmental laws and regulations may result in expenditures and liabilities, which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sitescould be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States EPA, Alagasco and the current site owner.
In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has not been provided information at this time that would allow it to determinematerial. To the extent if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco hasenvironmental compliance costs are not agreed to undertake the proposed removal activities and no amount has been accrued as of December 31, 2013.
Employees
The Company has approximately 1,434 employees, of which Alagasco employs 993 and Energen Resources employs 441. The Company believes that its relations with employees are good.
ITEM 1A.RISK FACTORS
The future success and continued viability of Energen and its businesses, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materiallyfully covered by insurance or recovered in rates from customers, those contained in forward-looking statements made in this report and presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors, and should not be viewed as complete or comprehensive. The Company undertakes no obligation to correct or update such risk factors whether as a result of new information, future events or otherwise. These risk factors should be read in conjunction with the Company’s disclosure specific to Forward-Looking Statements made elsewhere in this report.
Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect the Company’s results and the carrying value of its oil and natural gas properties: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for oil, natural gas and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trendscosts may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.
Market conditions or a downgrade in the credit ratings of the Company or its subsidiaries could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders, the Company and its subsidiaries. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition (including by sale, spin-off or distribution) transactions involving the Company, Energen Resources or Alagasco may negatively impact market and rating agency considerations regarding the credit of the Company or its subsidiaries, and the management of the Company periodically considers these types of transactions. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs, limit availability of funds to the Company and adversely affect the price of outstanding debt securities.
Energen Resources’ hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk:Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.
The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.
The Company’s operations depend upon the use of third party facilities and an interruption of its ability to utilize these facilities may adversely affect itsUtilities’ financial condition and results of operations: Energen Resources deliversoperations.
The Utilities are subject to pipeline safety and Alagasco is servedsystem integrity laws and regulations that may require significant expenditures or significant increases in operating costs.
Such laws and regulations affect various aspects of the Utilities’ present and future operations. These laws and regulations require the Utilities to maintain pipeline safety and system integrity by third party facilities. These facilities include third party oilidentifying and gas gathering, transportation, processingreducing pipeline risks. Compliance with these laws and storage facilities. Energen Resources relies upon such facilities for accessregulations, 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.
Failure to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limitedcomply may result in numberfines, penalties, or injunctive measures that would not be recoverable from customers in rates and geographically concentrated. An extended
interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in a material adverseeffect on the Utilities’ financial consequences to Energen Resources, Alagascocondition and the Company.results of operations.
The Company’s oilTransporting, distributing, and storing natural gas reserves are estimates, and actual future productiontransporting and storing propane involves numerous risks that may vary significantlyresult in accidents and may also be negatively impacted by its inability to invest in production on planned timelines:other operating risks and costs.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.
The Company’s operations involve operational risk including risk of personal injury, property damage and environmental damage and its insurance policies do not cover all such risks: Inherent in the oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco are a variety of hazards and operationoperations risks, such as:
Pipeline and storageas leaks, ruptures and spills;
Equipment malfunctionsaccidental explosions, including third party damages, and mechanical failures;
Fires and explosions;
Well blowouts, explosions and cratering; and
Soil, surface water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.
Such eventsproblems, 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 financial losses.losses to the Utilities. The location of certain of our pipelinepipelines 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 Laclede Gas' propane storage and transmission operations. These activities may subject the Utilities to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties against the Utilities or be resolved on unfavorable terms. The Utilities are subject to federal and state laws and regulations requiring the Utilities to maintain certain safety and system integrity measures by identifying and managing storage and 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. In accordance with customary industry practices, the Company maintainsUtilities maintain insurance against some,a significant portion, but not all, of these risks and losses andlosses. To the insurance coverages are subject to retention levels and coverage limits. Theextent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect Energen Resources’, Alagasco’s and the Company’s financial positions, results of operations and cash flows.
Alagasco operates in a limited service territory and is therefore subject to concentrated regional risks which may negatively affect Alagasco’sUtilities’ financial condition and results of operations: Alagasco’s utilityoperations.
Because of the highly competitive nature of its business, the Utilities may not be able to retain existing customers are geographically concentratedor acquire new customers, which would have an adverse impact on its businesses, operating results and financial conditions.
The Utilities face the risk that customers may bypass gas distribution services by gaining distribution directly from interstate pipelines or, in central and north Alabama. Significant economic, weather, natural disaster, criminal actthe case of Alagasco, also from municipally or publicly owned gas distributors located adjacent to its service territory. The Utilities cannot provide any assurance that increased competition or other eventschanges in legislation, regulation or policies will not have a material adverse effect on their business, financial condition or results of operation.
The Utilities compete with distributors offering a broad range of services and prices, from full-service distributors to those offering delivery only. The Utilities also compete for retail customers with suppliers of alternative energy products, principally propane and electricity. If they are unable to compete effectively, the Utilities may lose existing customers and/or fail to acquire new customers, which could have a material adverse effect on their business, operating results and financial condition.
Changes in the wholesale costs of purchased natural gas supplies may adversely impact the Utilities’ competitive position compared with alternative energy sources.
Changes in wholesale natural gas prices compared with prices for electricity, fuel oil, coal, propane, or other energy sources may affect the Utilities’ retention of natural gas customers and may adversely impact their financial condition and results of operations.
Significantly warmer-than-normal weather conditions, the effects of climate change, and other factors that influence customer usage may affect the Utilities’ sale of heating energy and adversely affect this region could adversely affect Alagascoimpact their financial position and results of operations.
The Utilities’ earnings are primarily generated by the sale of heating energy. The Missouri Utilities have weather mitigation rate designs and the Company.
The CompanyAlabama Utility has a Temperature Adjustment Rider (TAR), each of which is subjectapproved by the respective state regulatory body, which provide better assurance of the recovery of fixed costs and margins during winter months despite variations in sales volumes due to numerous federal, statethe impacts of weather and local lawsother factors that affect customer usage. However, significantly warmer-than-normal weather conditions in the Utilities’ service areas and regulations thatother factors, such as climate change and alternative energy sources, may require significant expendituresresult in reduced profitability and decreased cash flows attributable to lower gas sales. Furthermore, continuation of the weather mitigation rate design at Laclede Gas, the rate design where distribution costs are recovered predominantly through fixed monthly charges at MGE, or impose significant restrictions on its operations:Energenthe Rate Stabilization and Equalization (RSE) at Alagasco are subject to extensive federal, stateregulatory discretion. In addition, the promulgation of regulations by the Environmental Protection Agency (EPA), Department of Energy (DOE) or the potential enactment of congressional legislation addressing global warming and local regulationclimate change may result in future additional compliance costs that could impact the Utilities’ financial conditions and results of operations.
Regional supply/demand fluctuations and changes in national infrastructure, as well as regulatory discretion, may adversely affect the Missouri Utilities' ability to profit from off-system sales and capacity release.
The Missouri Utilities' income from off-system sales and capacity release is subject to fluctuations in market conditions and changing supply and demand conditions in areas the Missouri Utilities hold pipeline capacity rights. Specific factors impacting the Missouri Utilities' 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 Missouri Utilities are allowed to retain 15% to 25% of the first $6.0 in annual income earned (depending on the level of income earned) and 30% of income exceeding $6.0 annually. In accordance with an agreement approved by the MoPSC, Laclede Gas deferred, until fiscal year 2017, its ability to retain 15% of the first $2.0. MGE is allowed to retain 15% to 25% of the first $3.6 in annual income earned (depending on the level of income earned) and 30% of income exceeding $3.6 annually. The Missouri Utilities' ability to retain such income in the future is subject to regulatory discretion in a base rate proceeding.
Catastrophic events may adversely affect the Utilities’ facilities and operations.
Catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, tropical storms, terrorist acts, pandemic illnesses or other similar occurrences could adversely affect the Utilities’ facilities and operations. The Utilities have 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 Utilities’ 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 supply and transportation arrangements, and 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 significantly influences operations.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 Company believesFederal Energy Regulatory Commission (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 generallyfrom 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.
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 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 delivery obligations to LER under firm contracts. If these counterparties fail to perform, they have a contractual obligation to reimburse LER for 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, failurewhether existing or new ones, it could be subject to comply could result infines, penalties or other enforcement action by the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’sauthorities that regulate its operations.
The Company’s business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions:The Company relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company’s information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company’s operations, financial position and results of operations.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
None
ITEM 2. PROPERTIES
Laclede Gas
The corporate headquartersprincipal properties of Energen, Energen ResourcesLaclede Gas consist of more than 30,000 miles of gas main and Alagascorelated service pipes, meters, and regulators. In eastern Missouri, Laclede Gas has an underground storage facility, several operating centers, and other related properties, some of which are locatedleased. Laclede Gas' western Missouri region, served by MGE, also has several operating centers and other related properties, some of which are leased. Substantially all of Laclede Gas' utility plant is subject to the liens of its mortgage.
All of the properties of Laclede Gas are held in leasedfee, or by easement, or under lease agreements. The principal lease agreements include underground storage rights that are of indefinite duration and the downtown St. Louis office buildings. The current leases for office space in Birmingham, Alabama. Seedowntown St. Louis commenced in early 2015, with terms ranging from 10 to 20 years, with multiple renewal options. Laclede Gas entered into an agreement to sell the discussion under Item 1, Business, for further information related to Energen Resources’ and Alagasco’s business operations. Information concerning Energen Resources’ production and reserves is summarized inForest Park property, which closed on May 14, 2014. As part of the table below and included in Note 19, Oil andagreement Laclede Gas Operations (Unaudited), inleased back the Notes to Financial Statements. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operationsproperty for a discussion of the future outlook and expectations for Energen Resources and Alagasco and additional information regarding Energen Resources’ production, revenue and production costs.term that expired April 1, 2015.
Oil and Gas Operations
Energen Resources focuses on increasing its production and proved reserves through the development and exploration of onshore North American oil and gas properties. Energen Resources maintains district offices in Midland, Texas; Farmington, New Mexico; and Arcadia, Louisiana.
The major areas of operations include (1) the Permian Basin, (2) the San Juan Basin and (3) North Louisiana/East Texas as highlighted on the above map. As of December 31, 2013, North Louisiana/East Texas natural gas and oil properties were classified as held-for-sale and the associated operating results were reflected in discontinued operations.
The following table sets forth the production volumes, proved reserves and reserves-to-production ratio by area:
|
| | | | | | |
| | Year ended | | |
| | December 31, 2013 | December 31, 2013 | December 31, 2013 |
| | Production Volumes (MBOE) | Proved Reserves (MBOE) | Reserves-to-Production Ratio |
| Permian Basin | 14,187 |
| 246,586 |
| 17.38 years |
|
| San Juan Basin | 9,011 |
| 96,448 |
| 10.70 years |
|
| North Louisiana/East Texas* | 617 |
| 3,877 |
| 6.28 years |
|
| Other | 83 |
| 924 |
| 11.13 years |
|
| Total excluding Black Warrior Basin | 23,898 |
| 347,835 |
| 14.55 years |
|
| Black Warrior Basin (sold during 2013) | 1,464 |
| — |
| — |
|
| Total | 25,362 |
| — |
| — |
|
* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.
The following table sets forth proved reserves by area as of December 31, 2013:
|
| | | | | | |
| | Gas MMcf | Oil MBbl | NGL MBbl |
| Permian Basin | 232,345 |
| 163,716 |
| 44,147 |
|
| San Juan Basin | 460,097 |
| 900 |
| 18,864 |
|
| North Louisiana/East Texas* | 22,716 |
| 91 |
| — |
|
| Other | 4,567 |
| 163 |
| — |
|
| Total | 719,725 |
| 164,870 |
| 63,011 |
|
* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.
See Note 19, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2013, 2012 and 2011 of natural gas, oil, and natural gas liquids.
The following table sets forth proved developed reserves by area as of December 31, 2013:
|
| | | | | | |
| | Gas MMcf | Oil MBbl | NGL MBbl |
| Permian Basin | 135,925 |
| 112,641 |
| 23,223 |
|
| San Juan Basin | 460,097 |
| 900 |
| 18,864 |
|
| North Louisiana/East Texas* | 22,716 |
| 91 |
| — |
|
| Other | 4,567 |
| 163 |
| — |
|
| Total | 623,305 |
| 113,795 |
| 42,087 |
|
* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.
The following table sets forth proved undeveloped reserves by area as of December 31, 2013:
|
| | | | | | |
| | Gas MMcf | Oil MBbl | NGL MBbl |
| Permian Basin | 96,420 |
| 51,075 |
| 20,924 |
|
| Total | 96,420 |
| 51,075 |
| 20,924 |
|
The following table sets forth the reconciliation of proved undeveloped reserves:
|
| |
Year ended December 31, 2013 | Total MMBOE |
Balance at beginning of period | 85.9 |
Undeveloped reserves transferred to developed reserves | (20.3) |
Revisions | 5.7 |
Extensions and discoveries | 16.7 |
Balance at end of period | 88.0 |
Undeveloped reserves transferred to developed reserves reflect capital expenditures of approximately $414 million during the year ended December 31, 2013 in development of previously proved undeveloped reserves. Proved undeveloped reserves additions were one offset location away from producing wells where our geologic interpretation and experience indicate the reservoirs were continuous across those locations. The technologies associated with these additions to reserve estimates are analysis of well production data, geophysical data, wireline and core data. Revisions largely relate to well performance in the Permian Basin of approximately 13.4 MMBOE partially offset by a reduction in reserves of 5.3 MMBOE associated with the five-year proved undeveloped reserve development rules.
Estimated proved reserves as of December 31, 2013 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers. Calculations were prepared using geological and engineering methods widely used and referred to by professionals in the industry and in accordance with Securities and Exchange Commission (SEC) guidelines.
A Senior Vice President at Ryder Scott is the technical person primarily responsible for overseeing the audit of the reserves. The Senior Vice President has a Bachelor of Science degree in Mechanical Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been an employee of Ryder Scott since 1982 and also serves as chief technical advisor of unconventional reserves evaluation. A Petroleum Consultant at T. Scott Hickman is the technical person primarily responsible for overseeing the audit of the reserves. He has a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by T. Scott Hickman since 1983. The Vice President of Acquisitions and Reservoir Engineering is the technical person primarily responsible for overseeing reserves on behalf of Energen Resources. His background includes a Bachelor of Science degree in Mechanical Engineering and membership in the Society of Petroleum Engineers. He is a registered Professional Engineer in the State of Alabama with more than 30-years experience evaluating oil and natural gas properties and estimating reserves.
The Company relies upon certain internal controls when preparing its reserve estimations. These internal controls include review by the reservoir engineering managers to ensure the correct reserve methodology has been applied for each specific property and that the reserves are properly categorized in accordance with SEC guidelines. The reservoir engineering managers also affirm the accuracy of the data used in the reserve and associated rate forecast, provide a review of the procedures used to input pricing data and provide a review of the working and net interest factors to ensure that factors are adequately reflected in the engineering analysis.
Net production forecasts are compared to historical sales volumes to check for reasonableness, and operating costs and severance taxes calculated in the reserve report are compared to historical accounting data to help ensure proper cost estimates are used. A reserve table is generated comparing the previous year’s reserves to current year reserve estimates to determine variances. This table is reviewed by the Vice President of Acquisitions and Reservoir Engineering and the Chief Operating Officer of Energen Resources. Revisions and additions are investigated and explained.
Reserve estimates of proved reserves are sent to independent reservoir engineers for audit and verification. For 2013, approximately 98 percent of all proved reserves were audited by the independent reservoir engineers which audit engineering procedures, check the reserve estimates for reasonableness and check that the reserves are properly classified.
The following table sets forth the standard pressure base in pounds-force per square inch absolute (psia) for each state in which Energen Resources has wells:
|
| | |
Texas | 14.65 psia |
Colorado | 14.73 psia |
Louisiana, New Mexico | 15.025 psia |
The following table sets forth the total net productive oil and gas wells by area as of December 31, 2013, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
|
| | | | | | |
| |
Net Wells | Net Developed Acreage | Net Undeveloped Acreage |
| Permian Basin | 3,241 |
| 172,496 |
| 81,043 |
|
| San Juan Basin | 1,454 |
| 281,676 |
| 31,689 |
|
| North Louisiana/East Texas* | 175 |
| 20,720 |
| — |
|
| Other | 8 |
| 6,091 |
| — |
|
| Total | 4,878 |
| 480,983 |
| 112,732 |
|
* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.
The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2013:
|
| | | | | | | | | | | | | | | | |
| | Years ending December 31, |
| | 2014 | 2015 | 2016 | Thereafter |
| | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
| Permian | 11,400 |
| 7,537 |
| 43,938 |
| 31,513 |
| 13,724 |
| 13,110 |
| 35,667 |
| 28,883 |
|
| San Juan | 498 |
| 245 |
| 1,619 |
| 919 |
| 20,731 |
| 5,982 |
| 36,839 |
| 24,543 |
|
| Total* | 11,898 |
| 7,782 |
| 45,557 |
| 32,432 |
| 34,455 |
| 19,092 |
| 72,506 |
| 53,426 |
|
* Our capital plan contemplates avoiding a significant portion of these lease expirations.
Energen Resources has 5.6 MMBOE of proved undeveloped reserves on leased acreage which is not held by production and is expected to be developed after the primary term of the leases. Drilling associated with these reserves is expected to occur under the continuous development provisions of the leases. The amount represents approximately 6 percent of the 88 MMBOE total proved undeveloped reserves and approximately 2 percent of the 347.8 MMBOE total proved reserves at December 31, 2013. We believe both of these amounts to be immaterial to our operations.
Energen Resources sells oil, natural gas, and natural gas liquids under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity (firm volumes). Energen Resources is contractually committed to deliver approximately 37.8 billion cubic feet (net) of natural gas through March 2015. The Company expects to fulfill delivery commitments through production of existing proved reserves.
|
| | |
| Gas MMcf |
San Juan Basin | 37,823 |
|
Natural Gas DistributionAlagasco
The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 11,22923,000 miles of main and more than 12,015 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has twofour LNG facilities, thirteenseveral operation centers, two business centers, and other related property and equipment, some of which are leased by Alagasco.
For both Laclede Gas and Alagasco, the transmission pipelines and distribution mains are located in municipal streets or alleys, public streets or highways, or on lands of others for which we have obtained the necessary legal rights to place and operate our facilities on such property.
For further information on the Utilities' leases see Note 16, Commitments and Contingencies, of the Notes to Financial Statements in Item 8. 15Other properties of Laclede Group, including LER, do not constitute a significant portion of its properties.
ITEM 3. LEGAL PROCEEDINGS
Energen and its affiliates are, from time to time, parties to variousFor a description of pending or threatened legal proceedings. Certainregulatory matters of these lawsuits include claims for punitive damages in addition to other specified relief. Various pending or threatened legal proceedings are in progress currently. See Laclede Group, see Note 7, Commitments and Contingencies, in15, Regulatory Matters, of the Notes to Financial Statements for furtherin Item 8. For a description of environmental matters, see Note 16, Commitments and Contingencies, of the Notes to Financial Statements in Item 8.Laclede Group and its subsidiaries are involved in litigation, claims, and investigations arising in the normal course of business. Management, after discussion with respect to legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
None
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.
EXECUTIVE OFFICERS OF THE REGISTRANTSREGISTRANT – Listed below are executive officers as defined by the SEC for Laclede Group, Laclede Gas and Alagasco. Their ages, at September 30, 2015, 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 55 (2) | |
| | | |
| Laclede Group | | |
| President and Chief Executive Officer | February 2012 |
| President | | September 2011 |
| | | |
| Laclede Gas | | |
| Chairman of the Board | January 2015 |
| Chairman of the Board and Chief Executive Officer | October 2012 |
| Chairman of the Board, Chief Executive Officer and President | February 2012 |
| | | |
| Alagasco | | |
| Chairman of the Board | September 2014 |
| | | |
| S. L. Lindsey, Age 49 (3) | |
| | | |
| Laclede Group | | |
| Executive Vice President, Chief Operating Officer, Distribution Operations | October 2012 |
| | | |
| Laclede Gas | | |
| Chief Executive Officer and President | January 2015 |
| President | October 2012 |
| | | |
| Alagasco | | |
| Chief Executive Officer | September 2014 |
| | | |
| S. P. Rasche, Age 55 | |
| | | |
| Laclede Group | | |
| Executive Vice President, Chief Financial Officer | November 2013 |
| 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 | November 2009 |
| | | |
| Alagasco | | |
| Chief Financial Officer | September 2014 |
| | | |
| M. C. Darrell, Age 57 (4) | |
| | | |
| Laclede Group | | |
| Senior Vice President, General Counsel and Chief Compliance Officer | May 2012 |
| General Counsel | May 2004 |
| | | |
|
| | |
Name | Age | Position (1) |
James T. McManus, IIL. C. Dowdy, Age 59 (5) | 55 |
| Chairman, Chief Executive Officer | | |
| Laclede Group | | |
| Senior Vice President, External Affairs, Corporate Communications and Marketing | January 2014 |
| | | |
| M. C. Geiselhart, Age 56 | | |
| | | |
| Laclede Group | | |
| Senior Vice President, Strategic Planning and Corporate Development | January 2015 |
| Vice President, Strategic Planning and Corporate Development | February 2014 |
| Vice President, Strategic Development and Planning | August 2006 |
| | | |
| K. A. Smith, Age 57 | | |
| | | |
| Alagasco | | |
| President | April 2015 |
| Vice President, System Integrity | August 2011 |
| Vice President, Operations | January 2008 |
|
| |
| * | 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 Group are normally reappointed by the Board of Directors in November of each year. Officers of Laclede Gas and Alagasco are normally reappointed by 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. |
| |
| (3) | Mr. Lindsey served as Senior Vice President, Southern Operations of AGL Resources, Inc. and President of Energenits Atlanta Gas Light, Chattanooga Gas and Chairman and Chief Executive Officer of Alagasco (2) |
Charles W. Porter, Jr. | 49 | Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (3) |
John S. Richardson | 56 | President and Chief Operating Officer of Energen Resources (4) |
Dudley C. Reynolds | 60 | President and Chief Operating Officer of Alagasco (5) |
J. David Woodruff, Jr. | 57 | Vice President, General Counsel and Secretary of Energen and Alagasco (6) |
Russell E. Lynch, Jr. | 40 | Florida City Gas subsidiaries from December 2011 to October 2012. He also served as Vice President and ControllerGeneral Manager of Energen (7)Atlanta Gas Light and Chattanooga Gas from 2005 to 2011. |
| |
| (4) | Mr. Darrell served as Senior Vice President and General Counsel of Laclede Gas from October 2007 to July 2012. |
| |
| (5) | Mr. Dowdy served as Partner at the law firm McKenna Long & Aldridge LLP until December 2013. He also served as Senior Vice President of Laclede Gas from January 2014 to January 2015. |
Notes:
(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.
(2) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.
(3) Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.
(4) Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.
(5) Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.
(6) Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003. He also served as Vice President-Corporate Development of Energen from 1995 to 2010.
(7) Mr. Lynch has been employed by the Company in various capacities since 2001. He was elected Vice President and Controller of Energen effective January 1, 2009.
PART II
| |
ITEM 5. | MARKET FOR REGISTRANT’SITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES |
|
| | | | |
| Quarterly Market Prices and Dividends Paid Per Share |
| | | | | |
Quarter ended (in dollars) | High | Low | Close | Dividends Paid |
| March 31, 2012 | 58.24 | 47.33 | 49.15 | 0.14 |
| June 30, 2012 | 53.28 | 40.13 | 45.13 | 0.14 |
| September 30, 2012 | 55.59 | 43.81 | 52.41 | 0.14 |
| December 31, 2012 | 54.77 | 41.38 | 45.09 | 0.14 |
| March 31, 2013 | 52.13 | 44.46 | 52.01 | 0.145 |
| June 30, 2013 | 56.65 | 45.11 | 52.26 | 0.145 |
| September 30, 2013 | 77.50 | 52.42 | 76.39 | 0.145 |
| December 31, 2013 | 89.92 | 65.74 | 70.75 | 0.145 |
Energen’sLaclede Group’s common stock is listedtrades on theThe New York Stock Exchange (NYSE) under the symbol EGN. On February 14, 2014, there were 5,076“LG.” The high and the low sales price for the common stock for each quarter in the two most recent fiscal years are:
|
| | | | | | | | | | | | |
| | 2015 | 2014 |
| | High | Low | High | Low |
| 1st Quarter | $ | 55.22 |
| $ | 46.00 |
| $ | 47.82 |
| $ | 43.96 |
|
| 2nd Quarter | 55.75 |
| 49.07 |
| 47.48 |
| 43.95 |
|
| 3rd Quarter | 54.32 |
| 50.04 |
| 48.75 |
| 44.75 |
|
| 4th Quarter | 56.31 |
| 49.66 |
| 49.95 |
| 45.36 |
|
The number of holders of record as of Energen’sSeptember 30, 2015 was 3,611.
Dividends declared on common stock for the two most recent fiscal years were:
|
| | | | | | |
| | 2015 | 2014 |
| 1st Quarter | $ | 0.46 |
| $ | 0.44 |
|
| 2nd Quarter | 0.46 |
| 0.44 |
|
| 3rd Quarter | 0.46 |
| 0.44 |
|
| 4th Quarter | 0.46 |
| 0.44 |
|
For disclosures related to securities authorized for issuance under equity compensation plans, see Item 12, page 139. The only repurchases of Laclede Group's common stock during the three months ended September 30, 2015 would be pursuant to elections by employees to have shares of stock withheld to cover employee tax withholding obligations upon the vesting of performance-based and time-vested restricted stock and stock units. During the three months ended September 30, 2015, there were no such repurchases of Laclede Group's common stock. At
Laclede Gas
Laclede Gas common stock is owned by its parent, The Laclede Group, Inc., and is not traded on any stock exchange.
Dividends declared on common stock for the datetwo most recent fiscal years were:
|
| | | | | | |
| | 2015 | 2014 |
| 1st Quarter | $ | 808.84 |
| $ | 586.08 |
|
| 2nd Quarter | 810.93 |
| 587.16 |
|
| 3rd Quarter | 810.71 |
| 587.14 |
|
| 4th Quarter | 811.21 |
| 773.05 |
|
Laclede Gas' mortgage contains restrictions on its ability to pay cash dividends on its common stock, as described in further detail in Note 5, Stockholder’s Equity, of this filing, Energen Corporation owned all the issued and outstandingNotes to Financial Statements in Item 8.
Laclede Group periodically purchases common stock of AlabamaLaclede Gas Corporation. Energen expects to pay annual cash dividendswith the price set at the book value of $0.60 per share on the Company’sLaclede Gas common stock in 2014. The amount and timing of all dividend payments is subject to the discretionas of the Boardmost recently completed fiscal quarter. The details on sales of Directors and is based upon business conditions, resultscommon stock of operations, financial conditions and other factors.
The following table summarizes information concerning purchases of equity securities byLaclede Gas to Laclede Group during the issuer:
past three fiscal years are set forth below:
|
| | | | | | | | | |
Period |
Total Number of Shares Purchased |
Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans | Maximum Number of Shares that May Yet Be Purchased Under the Plans** |
| October 1, 2013 through October 31, 2013 | — |
| $ | — |
| — |
| 8,992,700 |
| November 1, 2013 through November 30, 2013 | — |
| — |
| — |
| 8,992,700 |
| December 1, 2013 through December 31, 2013 |
507* |
| 70.08 |
| — |
| 8,992,700 |
| Total | 507 |
| $ | 70.08 |
| — |
| 8,992,700 |
|
| | | | | | |
| Date of Sale | Aggregate Purchase Price (In millions) | | Number of Shares |
| | | | |
| 2013 | | | |
| December 13, 2012 | $ | 0.8 |
| | 21 |
|
| March 13, 2013 | 0.9 |
| | 22 |
|
| May 10, 2013 | 0.2 |
| | 5 |
|
| August 8, 2013 | 0.4 |
| | 9 |
|
| August 30, 2013 | 430.0 |
| | 10,581 |
|
| September 30, 2013 | 45.0 |
| | 1,107 |
|
| | | | |
| 2014 | | | |
| December 10, 2013 | $ | 0.3 |
| | 9 |
|
| February 6, 2014 | 0.4 |
| | 9 |
|
| May 12, 2014 | 0.4 |
| | 10 |
|
| | | | |
2015 (1) | | | |
| $ | — |
| | — |
|
* Acquired in connection with tax withholdings and payment(1) There were no purchases of exercise price onLaclede Gas common stock compensation plans.during fiscal 2015.
** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006,Exemption from registration for the Boardsale of Directors authorized the Company to repurchase up to 12,564,400 sharesstock was claimed under section 4(a)(2) of the Company’sSecurities Act of 1933.
Alagasco
Alagasco common stock.stock is owned by its parent, The resolutions doLaclede Group, Inc., and is not have an expiration date.traded on any stock exchange.
Dividends declared on common stock for the two most recent fiscal years were:
|
| | | | | | |
| | 2015 | 2014 |
| 1st Quarter | $ | — |
| $ | — |
|
| 2nd Quarter | — |
| 10.8 |
|
| 3rd Quarter | — |
| 10.8 |
|
| 4th Quarter | — |
| 15.8 |
|
In the fourth quarter of fiscal 2014, dividends declared after the August 31, 2014 effective date of Alagasco's acquisition by Laclede Group totaled $5.0.
PERFORMANCE GRAPH
This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500), the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP), and the Standard & Poor’s Supercomposite Gas Utilities Index (S15GASUX). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2008, in the Company and each of the indices. Total shareholder return includes reinvested dividends.
|
| | | | | | | | | | | | | | | | | | |
| As of December 31, | 2008 | 2009 | 2010 | 2011 | 2012 | 2013 |
| S&P 500 | $ | 100 |
| $ | 126 |
| $ | 146 |
| $ | 149 |
| $ | 172 |
| $ | 228 |
|
| Energen | $ | 100 |
| $ | 162 |
| $ | 169 |
| $ | 177 |
| $ | 161 |
| $ | 255 |
|
| S15OILP | $ | 100 |
| $ | 145 |
| $ | 164 |
| $ | 152 |
| $ | 155 |
| $ | 200 |
|
| S15GASUX | $ | 100 |
| $ | 126 |
| $ | 147 |
| $ | 177 |
| $ | 177 |
| $ | 230 |
|
Contents
ITEM 6. SELECTED FINANCIAL DATA
Laclede Group
|
| | | | | | | | | | | | | | | | | | | |
| | Fiscal Years Ended September 30 |
| (Dollars in Millions, Except Per Share Amounts) | 2015 | | 2014 (1) | | 2013 (2) | | 2012 | | 2011 |
| Statements of Income data | | | | | | | | | |
| Total Operating Revenues | $ | 1,976.4 |
| | $ | 1,627.2 |
| | $ | 1,017.0 |
| | $ | 1,125.5 |
| | $ | 1,603.3 |
|
| Net Income | 136.9 |
| | 84.6 |
| | 52.8 |
| | 62.6 |
| | 63.8 |
|
| Common Stock data | | | | | | | | | |
| Diluted Earnings Per Share of Common Stock | $ | 3.16 |
| | $ | 2.35 |
| | $ | 2.02 |
| | $ | 2.79 |
| | $ | 2.86 |
|
| Dividends Declared Per Share of Common Stock | 1.84 |
| | 1.76 |
| | 1.70 |
| | 1.66 |
| | 1.62 |
|
| Statements of Financial Position data | | | | | | | | | |
| Total Assets | $ | 5,290.2 |
| | $ | 5,074.0 |
| | $ | 3,125.4 |
| | $ | 1,880.3 |
| | $ | 1,783.1 |
|
| Long-Term Debt (less current portion) | 1,771.5 |
| | 1,851.0 |
| | 912.7 |
| | 339.4 |
| | 364.4 |
|
Consolidated Net Economic Earnings data (3) | | | | | | | | | |
| Net Income (GAAP) | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
| | $ | 62.6 |
| | $ | 63.8 |
|
| Unrealized (gain) loss on energy-related derivatives | (1.8 | ) | | (0.9 | ) | | 0.5 |
| | (0.3 | ) | | (1.4 | ) |
| Lower of cost or market inventory adjustments | 0.3 |
| | (0.7 | ) | | 0.9 |
| | — |
| | — |
|
| Realized loss (gain) on economic hedges prior to the sale of the physical commodity | 1.5 |
| | (0.2 | ) | | — |
| | 0.2 |
| | — |
|
| Acquisition, divestiture and restructuring activities | 6.1 |
| | 17.3 |
| | 10.8 |
| | 0.1 |
| | — |
|
| Gain on sale of property | (4.7 | ) | | — |
| | — |
| | — |
| | — |
|
| Net Economic Earnings (Non-GAAP) | $ | 138.3 |
| | $ | 100.1 |
| | $ | 65.0 |
| | $ | 62.6 |
| | $ | 62.4 |
|
| Diluted Earnings per Share of Common Stock: | | | | | | | | | |
| Net Income (GAAP) | $ | 3.16 |
| | $ | 2.35 |
| | $ | 2.02 |
| | $ | 2.79 |
| | $ | 2.86 |
|
| Unrealized (gain) loss on energy-related derivatives | (0.04 | ) | | (0.02 | ) | | 0.02 |
| | (0.02 | ) | | (0.07 | ) |
| Lower of cost or market inventory adjustments | 0.01 |
| | (0.02 | ) | | 0.03 |
| | — |
| | — |
|
| Realized loss (gain) on economic hedges prior to the sale of the physical commodity | 0.03 |
| | (0.01 | ) | | — |
| | 0.01 |
| | — |
|
| Acquisition, divestiture and restructuring activities | 0.14 |
| | 0.48 |
| | 0.42 |
| | 0.01 |
| | — |
|
| Gain on sale of property | (0.11 | ) | | — |
| | — |
| | — |
| | — |
|
| Weighted average shares adjustment | — |
| | 0.27 |
| | 0.38 |
| | — |
| | — |
|
| Net Economic Earnings (Non-GAAP) | $ | 3.19 |
| | $ | 3.05 |
| | $ | 2.87 |
| | $ | 2.79 |
| | $ | 2.79 |
|
(1) Effective August 31, 2014, the Company completed the purchase from Energen of 100% of the outstanding common stock of Alagasco for $1,590.3 (including assumed debt of $264.8). Laclede Group funded the purchase price with a combination of the issuance of approximately 10.4 million shares of common stock and approximately 2.8 million equity units completed on June 11, 2014, the issuance by Laclede Group of $625.0 aggregate principal amount of senior notes on August 19, 2014, and cash from operations.
(2) Effective September 1, 2013, Laclede Gas completed the purchase from Southern Union Company, an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., of substantially all of the assets and liabilities of MGE, a utility engaged in the distribution of natural gas on a regulated basis in western Missouri for $940.2. The selectedacquisition was supported by a combination of the issuance of approximately 10 million shares of common stock completed on May 29, 2013 and the issuance by Laclede Gas of $450.0 of first mortgage bonds on August 13, 2013.
(3) This section contains the non-GAAP financial measures of net economic earnings and net economic earnings per share. Net economic earnings per share are calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation. Each item is shown net of tax.
| |
| 2014 net economic earnings per share excludes the impact of the June 2014 equity offerings to fund the acquisition of Alagasco, but includes the May 2013 equity offering to fund the MGE acquisition. The weighted-average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2014 was 32.7 compared to 35.9 in the GAAP EPS calculation. |
2013 net economic earnings per share excludes the impact of the May 2013 equity offering to fund the 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 compared to 26.0 in the GAAP EPS calculation.
For more information on economics earnings data, refer to the Earnings section of Management's Discussion and Analysis of Financial Condition and Results of Operations on page 24.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions, except per share amounts)
INTRODUCTION
This section analyzes the financial condition and results of operations of The Laclede Group, Inc. (Laclede Group or the Company), Laclede Gas Company (Laclede Gas or the Missouri Utilities), and Alabama Gas Corporation (Alagasco or the Alabama Utility). Laclede Gas and Alagasco are wholly owned subsidiaries of the Company. Collectively, Laclede Gas and Alagasco are referred to as set forth belowthe Utilities. This section includes management’s view of factors that affect the respective businesses of the Company, Laclede Gas, and Alagasco, explanations of financial results including changes in earnings and costs from the prior periods, and the effects of such factors on the Company's, Laclede Gas' and Alagasco's overall financial condition and liquidity.
Reference is made to “Part I. Item 1A. Risk Factors” and “Forward-Looking Statements,” which describe important factors that could cause actual results to differ from expectations and non-historical information contained herein. In addition, the following discussion should be read in conjunction with the consolidatedaudited financial statements and the Notes toaccompanying notes thereto of Laclede Group, Laclede Gas, and Alagasco included in “Item 8. Financial Statements included in this Form 10-K.and Supplementary Data.”
SELECTED FINANCIAL AND COMMON STOCK DATA
Energen Corporation
|
| | | | | | | | | | | | | | | | | | | |
Years ended December 31, (dollars in thousands, except per share amounts) |
2013 | |
2012 | |
2011 | |
2010 | |
2009 |
| INCOME STATEMENT | | | | | | | | | |
| Operating revenues | $ | 1,738,650 |
| | $ | 1,540,819 |
| | $ | 1,373,113 |
| | $ | 1,425,107 |
| | $ | 1,273,574 |
|
| Income from continuing operations | $ | 193,147 |
| | $ | 255,220 |
| | $ | 224,305 |
| | $ | 233,133 |
| | $ | 191,643 |
|
| Net income | $ | 204,554 |
| | $ | 253,562 |
| | $ | 259,624 |
| | $ | 290,807 |
| | $ | 256,325 |
|
| Diluted earnings per average common share from continuing operations | $ | 2.67 |
| | $ | 3.53 |
| | $ | 3.10 |
| | $ | 3.24 |
| | $ | 2.67 |
|
| Diluted earnings per average common share | $ | 2.82 |
| | $ | 3.51 |
| | $ | 3.59 |
| | $ | 4.04 |
| | $ | 3.57 |
|
| BALANCE SHEET | | | | | | | | | |
| Total property, plant and equipment, net | $ | 6,003,638 |
| | $ | 5,541,636 |
| | $ | 4,620,776 |
| | $ | 3,719,227 |
| | $ | 3,144,469 |
|
| Total assets | $ | 6,622,212 |
| | $ | 6,175,890 |
| | $ | 5,237,416 |
| | $ | 4,363,560 |
| | $ | 3,803,118 |
|
| Long-term debt | $ | 1,343,464 |
| | $ | 1,103,528 |
| | $ | 1,153,700 |
| | $ | 405,254 |
| | $ | 410,786 |
|
| Total shareholders’ equity | $ | 2,858,019 |
| | $ | 2,676,690 |
| | $ | 2,432,163 |
| | $ | 2,154,043 |
| | $ | 1,988,243 |
|
| COMMON STOCK DATA | | | | | | | | | |
| Cash dividends paid per common share | $ | 0.58 |
| | $ | 0.56 |
| | $ | 0.54 |
| | $ | 0.52 |
| | $ | 0.50 |
|
| Diluted average common shares outstanding (000) | 72,471 |
| | 72,316 |
| | 72,332 |
| | 72,051 |
| | 71,885 |
|
| Price range: | | | | | | | | | |
| High | $ | 89.92 |
| | $ | 58.24 |
| | $ | 65.44 |
| | $ | 49.94 |
| | $ | 48.89 |
|
| Low | $ | 44.46 |
| | $ | 40.13 |
| | $ | 37.22 |
| | $ | 40.25 |
| | $ | 23.18 |
|
| Close | $ | 70.75 |
| | $ | 45.09 |
| | $ | 50.00 |
| | $ | 48.26 |
| | $ | 46.80 |
|
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
|
| | | | | | | | | | | | | | | | | | | |
Years ended December 31, (dollars in thousands) |
2013 | |
2012 | |
2011 | |
2010 | |
2009 |
| OIL AND GAS OPERATIONS | | | | | | | | | |
| Operating revenues from continuing operations | | | | | | | | | |
| Natural gas | $ | 239,643 |
| | $ | 216,073 |
| | $ | 281,501 |
| | $ | 336,493 |
| | $ | 298,865 |
|
| Oil | 865,100 |
| | 788,937 |
| | 465,735 |
| | 403,039 |
| | 283,247 |
|
| Natural gas liquids | 101,550 |
| | 85,938 |
| | 87,464 |
| | 65,161 |
| | 67,254 |
|
| Other | (981 | ) | | (1,718 | ) | | 3,460 |
| | 642 |
| | 6,334 |
|
| Total | $ | 1,205,312 |
| | $ | 1,089,230 |
| | $ | 838,160 |
| | $ | 805,335 |
| | $ | 655,700 |
|
| Non-cash mark-to-market gains (losses) (included in operating revenues from continuing operations above) | |
| Natural gas | $ | (3,919 | ) | | $ | (515 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Oil | (43,261 | ) | | 58,786 |
| | (37,473 | ) | | (3 | ) | | (107 | ) |
| Natural gas liquids | (652 | ) | | 479 |
| | (114 | ) | | — |
| | — |
|
| Total | $ | (47,832 | ) | | $ | 58,750 |
| | $ | (37,587 | ) | | $ | (3 | ) | | $ | (107 | ) |
| Production volumes from continuing operations | | | | | | | | | |
| Natural gas (MMcf) | 58,104 |
| | 59,166 |
| | 54,132 |
| | 51,778 |
| | 50,365 |
|
| Oil (MBbl) | 10,364 |
| | 8,749 |
| | 6,300 |
| | 5,109 |
| | 4,664 |
|
| Natural gas liquids (MMgal) | 135.8 |
| | 108.1 |
| | 91.4 |
| | 79.0 |
| | 75.2 |
|
| Production volumes from continuing operations (MBOE) | 23,281 |
| | 21,183 |
| | 17,499 |
| | 15,619 |
| | 14,849 |
|
| Total production volumes (MBOE) | 25,362 |
| | 24,066 |
| | 20,448 |
| | 18,832 |
| | 18,537 |
|
| Proved reserves | | | | | | | | | |
| Natural gas (MMcf) | 719,725 |
| | 809,128 |
| | 957,368 |
| | 954,387 |
| | 897,546 |
|
| Oil (MBbl) | 164,870 |
| | 155,348 |
| | 129,578 |
| | 103,262 |
| | 77,963 |
|
| Natural gas liquids (MBbl) | 63,011 |
| | 56,155 |
| | 53,957 |
| | 40,601 |
| | 30,257 |
|
| Total (MMcfe) | 2,087,010 |
| | 2,078,154 |
| | 2,058,594 |
| | 1,817,565 |
| | 1,546,866 |
|
| Total (MBOE) | 347,835 |
| | 346,359 |
| | 343,099 |
| | 302,928 |
| | 257,811 |
|
| Other data from continuing operations | | | | | | | | | |
| Lease operating expense | | | | | | | | | |
| Lease operating expense and other | $ | 284,053 |
| | $ | 224,503 |
| | $ | 174,778 |
| | $ | 155,359 |
| | $ | 151,651 |
|
| Production taxes | 67,488 |
| | 53,690 |
| | 51,583 |
| | 38,686 |
| | 31,852 |
|
| Total | $ | 351,541 |
| | $ | 278,193 |
| | $ | 226,361 |
| | $ | 194,045 |
| | $ | 183,503 |
|
| Depreciation, depletion and amortization | $ | 453,474 |
| | $ | 343,183 |
| | $ | 213,841 |
| | $ | 168,016 |
| | $ | 146,946 |
|
| Capital expenditures | $ | 1,104,745 |
| | $ | 1,291,211 |
| | $ | 1,115,452 |
| | $ | 717,782 |
| | $ | 427,399 |
|
| Exploration expense | $ | 27,942 |
| | $ | 19,356 |
| | $ | 12,967 |
| | $ | 64,562 |
| | $ | 10,225 |
|
| Operating income | $ | 257,963 |
| | $ | 369,765 |
| | $ | 308,561 |
| | $ | 315,990 |
| | $ | 252,927 |
|
| NATURAL GAS DISTRIBUTION | | | | | | | | | |
| Operating revenues | | | | | | | | | |
| Residential | $ | 340,563 |
| | $ | 277,698 |
| | $ | 343,740 |
| | $ | 414,870 |
| | $ | 398,289 |
|
| Commercial and industrial | 136,990 |
| | 115,711 |
| | 136,469 |
| | 159,658 |
| | 161,543 |
|
| Transportation | 61,254 |
| | 58,857 |
| | 55,234 |
| | 57,049 |
| | 53,856 |
|
| Other | (5,469 | ) | | (677 | ) | | (490 | ) | | (11,805 | ) | | 4,186 |
|
| Total | $ | 533,338 |
| | $ | 451,589 |
| | $ | 534,953 |
| | $ | 619,772 |
| | $ | 617,874 |
|
| Gas delivery volumes (MMcf) | | | | | | | | | |
| Residential | 20,279 |
| | 16,014 |
| | 21,132 |
| | 24,463 |
| | 20,921 |
|
| Commercial and industrial | 9,968 |
| | 8,372 |
| | 9,994 |
| | 10,985 |
| | 9,934 |
|
| Transportation | 47,534 |
| | 48,106 |
| | 44,614 |
| | 46,479 |
| | 40,903 |
|
| Total | 77,781 |
| | 72,492 |
| | 75,740 |
| | 81,927 |
| | 71,758 |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| Average number of customers | | | | | | | | | |
| Residential | 391,093 |
| | 393,467 |
| | 395,766 |
| | 404,697 |
| | 409,214 |
|
| Commercial, industrial and transportation | 31,174 |
| | 31,450 |
| | 31,840 |
| | 32,632 |
| | 33,264 |
|
| Total | 422,267 |
| | 424,917 |
| | 427,606 |
| | 437,329 |
| | 442,478 |
|
| Other data | | | | | | | | | |
| Depreciation and amortization | $ | 43,907 |
| | $ | 42,270 |
| | $ | 39,916 |
| | $ | 44,042 |
| | $ | 50,995 |
|
| Capital expenditures | $ | 88,769 |
| | $ | 71,869 |
| | $ | 73,984 |
| | $ | 93,566 |
| | $ | 77,809 |
|
| Operating income | $ | 93,768 |
| | $ | 93,216 |
| | $ | 86,216 |
| | $ | 88,383 |
| | $ | 83,984 |
|
| |
ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
RESULTS OF OPERATIONS
Consolidated Net IncomeOverview
Energen Corporation’s net income forThe Company has two key business segments: Gas Utility and Gas Marketing. Laclede Group’s earnings are primarily derived from its Gas Utility segment, which reflects the year ended December 31, 2013 totaled $204.6 million, or $2.82 per diluted share comparedregulated activities of the Utilities. The Gas Utility segment consists of the regulated businesses of Laclede Gas and Alagasco. Due to the year ended December 31, 2012 net incomeseasonal nature of $253.6 million, or $3.51 per diluted share. This 19.7 percent decrease inthe Utilities' business, earnings per diluted share (EPS) largely reflected increased depreciation, depletionof Laclede Group, Laclede Gas and amortization (DD&A) expense, a year-over-year after-tax $67.8 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.6 million non-cash mark-to-market loss on derivatives for 2013 and an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012), higher lease operating expense excluding production taxes, increased administrative expense, increased production taxes, higher exploration expense, lower commodity prices forAlagasco are typically concentrated during the heating season of November through April each fiscal year.
Gas Utility - Laclede Gas
Laclede Gas is Missouri’s largest natural gas liquidsdistribution company and increased interest expense. Positively affecting net incomeis regulated by the Missouri Public Service Commission (MoPSC). Laclede Gas serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through MGE, which was acquired on September 1, 2013. Laclede Gas delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The earnings of Laclede Gas are primarily generated by the sale of heating energy. The rate design for both service territories serve to lessen the impact of a net 2.1 million barrels of oil equivalent (MMBOE) increase in production volumesweather volatility on its customers during cold winters and stabilize Laclede Gas' earnings.
Gas Utility - Alagasco
On August 31, 2014, the Company purchased from Energen Resources Corporation, Energen’s oil and gas subsidiary, and higher oil and100% of the outstanding common stock of Alagasco. Alagasco is the largest natural gas commodity prices. For the year ended December 31, 2013, Energen Resources earned $146.8 million, as compared with $204.1 milliondistribution utility in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net incomestate of $57.4 millionAlabama. Alagasco’s service territory is located in central and northern Alabama. Among the current year, which includes an after-tax gain of $6.8 million oncities served by Alagasco are Birmingham, the salecenter of the Metro Operations Center, as compared with net incomelargest metropolitan area in Alabama, and Montgomery, the prior period of $49.4 million. For the year ended December 31, 2011, Energen reported net income of $259.6 million, or $3.59 per diluted share.
2013 vs 2012: Energen Resources’ net income totaled $146.8 million in 2013 as compared with $204.1 million in 2012. Energen Resources’ income from continuing operations totaled $135.3 million in 2013 as compared with $205.7 million in 2012. Income from discontinued operations for the current year was $11.4 million, as compared with a loss of $1.7 million from the prior year. Income from discontinued operations in 2013 included an after-tax gain of $22.5 million on the sale of the Black Warrior Basin coalbed methane properties partially offset by the non-cash impairment writedown on North Louisiana/East Texas natural gas and oil properties of $18.9 million after-tax. Loss from discontinued operations in 2012 included a non-cash impairment on certain properties in East Texas of approximately $13.4 million after-tax. From continuing operations, increased DD&A expense of approximately $73 million after-tax, a year-over-year after-tax $67.8 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.6 million non-cash mark-to-market loss on derivatives for 2013 and an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012), higher lease operating expense excluding production taxes of approximately $39 million after-tax, increased administrative expense of approximately $23 million after-tax, increased production taxes of approximately $9 million after-tax, higher exploration expense of approximately $6 million after-tax, lower commodity prices for natural gas liquids of approximately $3 million after-tax, increased interest expense of approximately $3 million after-tax and lower natural gas production volumes of approximately $3 million were partially offset by significantly greater oil and natural gas liquid production volumes of approximately $103 million after-tax and higher oil and natural gas commodity prices of approximately $49 million after-tax.
Alagasco earned net income of $57.4 million in 2013 as compared with net income of $49.4 million in 2012 which primarily reflects the utility’s ability to earn on a higher level of equity in support of Alagasco’s investment in its distribution system and support systems devoted to public service and an after-tax gain of $6.8 million on the sale of the Metro Operations Center.
2012 vs 2011: For the year ended December 31, 2012, Energen Resources’ net income totaled $204.1 million as compared to $213 million in the prior year. Energen Resources’ income from continuing operations totaled $205.7 million in 2012 as compared with $177.5 million in 2011. Loss from discontinued operations for 2012 was $1.7 million, as compared with income of $35.3 million from 2011. Loss from discontinued operations in 2012 included a non-cash impairment on certain properties in East Texas of approximately $13.4 million after-tax. Lower natural gas and natural gas liquids commodity prices of approximately $70 million after-tax, increased DD&A expense of approximately $83 million after-tax, higher lease operating expense of approximately $32 million after-tax, increased interest expense of approximately $12 million after-tax, higher exploration expense of approximately $4 million after-tax, the 2011 after-tax gain of $3.6 million on the sale of certain oil properties were partially offset by increased production volumes of approximately $153 million after-tax, a year-over-year after-tax $60.6 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012 and an after-tax $23.4 million non-cash mark-to-market loss on derivatives for 2011) and higher oil commodity prices of approximately $20 million after-tax.
Alagasco’s net income of $49.4 million in 2012 compared to net income of $46.6 million in 2011. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity in support of Alagasco’s investment in its distribution system and support systems devoted to public service.
Operating Income
Consolidated operating income in 2013, 2012 and 2011 totaled $351.2 million, $461.9 million and $393.7 million, respectively. Lower operating income for 2013 is primarily due to higher DD&A, higher lease operating expense and the non-cash mark-to-market decrease in derivatives partially offset by increased oil and natural gas liquids production and higher natural gas and oil commodity prices at Energen Resources. Growth in operating income for 2012 was influenced by increased production and higher oil commodity prices partially offset by lower natural gas and natural gas liquids commodity prices. During 2013 and 2012, Alagasco contributed to operating income consistent with the level of equity supporting the investment in its distribution system and support systems devoted to public service.
Oil and Gas Operations: Revenues from continuing oil and gas operations increased in the current year largely as a result of significantly higher oil and natural gas liquids production volumes and higher realized oil and natural gas commodity prices partially offset by the non-cash mark-to-market decrease in derivatives combined with lower natural gas liquids commodity prices and decreased natural gas production volumes. Production increased due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties partially offset by normal production declines. Revenue per unit of production for natural gas production rose 14.5 percent to $4.19 per thousand cubic feet (Mcf), oil revenue per unit of production increased 5 percent to $87.65 per barrel and natural gas liquids revenue per unit of production fell 5.1 percent to $0.75 per gallon during 2013. Production from continuing operations rose 9.9 percent to 23.3 MMBOE during 2013. Natural gas production decreased 1.8 percent to 58.1 billion cubic feet (Bcf) while oil volumes rose 18.5 percent to 10,364 thousand barrels (MBbl). Production of natural gas liquids increased 25.6 percent to 135.8 million gallons (MMgal). Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the non-cash mark-to-market hedges.
In 2012, revenues from continuing oil and gas operations increased largely as a result of higher production volumes and higher oil commodity prices partially offset by lower natural gas and natural gas liquids commodity prices. Production increased due to higher volumes related to increased field development in certain Permian Basin properties and increased volumes related to acquisitions of certain Permian Basin properties partially offset by normal production declines. During 2012, revenue per unit of production for natural gas production fell 29.6 percent to $3.66 per Mcf, oil revenue per unit of production rose 4.5 percent to $83.46 per barrel and natural gas liquids revenue per unit of production decreased 17.7 percent to $0.79 per gallon. Production from continuing operations rose 21.1 percent to 21.2 MMBOE during 2012. Natural gas production increased 9.3 percent to 59.2 Bcf and oil volumes rose 38.9 percent to 8,749 MBbl. Production of natural gas liquids increased 18.3 percent to 108.1 MMgal.
|
| | | | | | | | | |
| Years ended December 31, (in thousands, except sales price data) | 2013 | 2012 | 2011 |
| Operating revenues from continuing operations | | | |
| Natural gas | $ | 239,643 |
| $ | 216,073 |
| $ | 281,501 |
|
| Oil | 865,100 |
| 788,937 |
| 465,735 |
|
| Natural gas liquids | 101,550 |
| 85,938 |
| 87,464 |
|
| Other | (981 | ) | (1,718 | ) | 3,460 |
|
| Total operating revenues | $ | 1,205,312 |
| $ | 1,089,230 |
| $ | 838,160 |
|
| Non-cash mark-to-market gains (losses) (included in operating revenues above) | | |
| Natural gas | $ | (3,919 | ) | $ | (515 | ) | $ | — |
|
| Oil | (43,261 | ) | 58,786 |
| (37,473 | ) |
| Natural gas liquids | (652 | ) | 479 |
| (114 | ) |
| Total | $ | (47,832 | ) | $ | 58,750 |
| $ | (37,587 | ) |
| Production volumes from continuing operations | | | |
| Natural gas (MMcf) | 58,104 |
| 59,166 |
| 54,132 |
|
| Oil (MBbl) | 10,364 |
| 8,749 |
| 6,300 |
|
| Natural gas liquids (MMgal) | 135.8 |
| 108.1 |
| 91.4 |
|
| Total production volumes from continuing operations (MBOE) | 23,281 |
| 21,183 |
| 17,499 |
|
| Production volumes | | | |
| Natural gas (MMcf) | 70,506 |
| 76,362 |
| 71,718 |
|
| Oil (MBbl) | 10,378 |
| 8,766 |
| 6,318 |
|
| Natural gas liquids (MMgal) | 135.8 |
| 108.1 |
| 91.4 |
|
|
| | | | | | | | | |
| Total production volumes (MBOE) | 25,362 |
| 24,066 |
| 20,448 |
|
| San Juan Basin - Basin Field production volumes (included in production volumes above)* | |
| Natural gas (MMcf) | 29,453 |
| 34,595 |
| 33,656 |
|
| Oil (MBbl) | 13 |
| 12 |
| 13 |
|
| Natural gas liquids (MMgal) | 22.7 |
| 24.2 |
| 25.2 |
|
| Total production volumes (MBOE) | 5,462 |
| 6,354 |
| 6,223 |
|
| Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)** |
| Natural gas (MMcf) | 4,836 |
| 3,592 |
| 1,650 |
|
| Oil (MBbl) | 2,822 |
| 2,134 |
| 1,136 |
|
| Natural gas liquids (MMgal) | 38.5 |
| 25.8 |
| 14.7 |
|
| Total production volumes (MBOE) | 4,544 |
| 3,347 |
| 1,762 |
|
| Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments |
| Natural gas (per Mcf) | $ | 4.19 |
| $ | 3.66 |
| $ | 5.20 |
|
| Oil (per barrel) | $ | 87.65 |
| $ | 83.46 |
| $ | 79.87 |
|
| Natural gas liquids (per gallon) | $ | 0.75 |
| $ | 0.79 |
| $ | 0.96 |
|
| Revenue per unit of production excluding effects of all derivative instruments |
| Natural gas (per Mcf) | $ | 3.51 |
| $ | 2.69 |
| $ | 3.89 |
|
| Oil (per barrel) | $ | 92.73 |
| $ | 87.56 |
| $ | 90.54 |
|
| Natural gas liquids (per gallon) | $ | 0.67 |
| $ | 0.75 |
| $ | 1.11 |
|
| Average production (lifting) cost (per BOE) (excludes ad valorem tax) | $ | 11.06 |
| $ | 9.55 |
| $ | 9.11 |
|
| Average ad valorem tax (per BOE) | $ | 1.14 |
| $ | 1.05 |
| $ | 0.88 |
|
| Average production tax (per BOE) | $ | 2.90 |
| $ | 2.53 |
| $ | 2.95 |
|
| Average DD&A rate (per BOE) | $ | 19.32 |
| $ | 16.03 |
| $ | 12.03 |
|
* The Basin Field in the San Juan Basin contained 15 percent or more of the Company’s total proved reserves as of December 31, 2013.
** The Spraberry (Trend Area) Field in the Permian Basin contained 15 percent or more of the Company’s total proved reserves as of December 31, 2013.
Operations and maintenance (O&M) expense rose $103 million in 2013 and increased $57.7 million in 2012. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting from Energen Resources’ ongoing development, exploratory and acquisition activities. During 2013, lease operating expense (excluding production taxes) increased $59.6 million largely due to additional workover and repair expense (approximately $26.5 million), increased equipment rental expense (approximately $4.5 million), increased marketing and transportation costs (approximately $4.3 million), higher gathering costs (approximately $4.2 million), higher ad valorem taxes (approximately $4 million), higher labor costs (approximately $3.6 million), increased environmental compliance costs (approximately $3.1 million), additional electrical costs (approximately $2.8 million), increased chemical usage (approximately $2.4 million) and increased nonoperated costs (approximately $2.4 million). In 2012, lease operating expense (excluding production taxes) increased $49.7 million largely due to increased water disposal costs (approximately $15.2 million), higher workover and repair expense (approximately $9.3 million), higher ad valorem taxes (approximately $6.5 million), the Permian Basin property acquisitions (approximately $5 million), additional equipment rental expense (approximately $3.5 million), increased marketing and transportation costs (approximately $3.2 million), increased chemical and treatment costs (approximately $2.7 million), additional electrical costs (approximately $2 million), increased nonoperated costs (approximately $1.7 million), increased labor costs (approximately $1.4 million) and higher environmental compliance expense (approximately $1.1 million) partially offset by decreased other O&M expense (approximately $3.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for 2013 was $12.20 per barrel of oil equivalent (BOE) as compared to $10.60 per BOE in the same period a year ago. In 2013, administrative expense rose $34.9 million primarily due to increased costs related to the Company’s benefit and performance-based compensation plans (approximately $21.7 million), higher labor costs (approximately $7.4 million), increased legal expenses (approximately $3 million) and higher professional services (approximately $1.1 million). Administrative expense rose $1.6 million in 2012 largely due to increased labor costs (approximately $4.3 million) partially offset by decreased costs from the Company’s benefit and performance-based compensation plans (approximately $1.8 million). Exploration expense increased $8.6 million in 2013 largely due to the
expected expiration of certain leasehold acreage. Exploration expense rose $6.4 million during 2012 primarily due to charges incurred of $5.3 million for unproved capitalized leasehold costs.
DD&A expense increased $110.3 million in 2013 and $129.3 million in 2012. The average DD&A rates were $19.32 per BOE in 2013, $16.03 per BOE in 2012 and $12.03 per BOE in 2011. The increase in the 2013 and 2012 per unit DD&A rates, which contributed approximately $76.6 million and $84.7 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $33.6 million and $44.3 million to the increase in DD&A expense in 2013 and 2012, respectively.
Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $67.5 million, $53.7 million and $51.6 million for 2013, 2012 and 2011, respectively. In 2013, severance taxes were $13.8 million higher resulting from increased oil and natural gas commodity market prices and higher oil and natural gas liquids production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $8.5 million and $5.3 million to the increase in severance taxes, respectively. Severance taxes were $2.1 million higher in 2012 resulting from higher production volumes largely offset by lower commodity market prices. Increased production volumes contributed approximately $10.9 million to the increase in severance taxes while decreased commodity market prices lowered severance taxes by approximately $8.8 million. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.
Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements,state capital. Alagasco is subject to regulationregulated by the Alabama Public Service Commission (APSC). Alagasco purchases natural gas through interstate and was allowedintrastate suppliers and distributes the purchased gas through its distribution facilities for sale to earnresidential, commercial, and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a rangefee to transport such customer-owned gas through its distribution system to the customers’ facilities.
Gas Marketing
Laclede Energy Resources, Inc. is engaged in the marketing of returnnatural 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 13.15 percent to 13.65 percent on average equity through December 31, 2013. Rate StabilizationLaclede Gas’ traditional service territory, including large retail and Equalization (RSE) limited the utility’s equity upon which a return is permitted to 55 percent of total capitalization,wholesale customers. LER’s operations and customer base are more subject to certain adjustments. Alagasco’s original RSE order hadfluctuations in market conditions than the Utilities. LER entered into a term extending10-year contract for 1 Bcf of natural gas storage effective August 1, 2013 and has contracts for an additional 3.5 Bcf of storage that expire at various times through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term will continue beyond SeptemberApril 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event2016.
Business Evaluation Factors
Based on the nature of force majeurethe business of the Company and includingits 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 Utilities' ability to recover the costs of purchasing and distributing natural gas from their 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 Utilities' ability to earn its authorized rate of return in all service territories they serve;
the Utilities' 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 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.
Gas Utility
The Utilities seek to provide reliable natural gas services at a changereasonable cost, while maintaining and building secure and dependable infrastructures. The Utilities’ strategies focus on improving both performance and the ability to recover their authorized distribution costs and rates of return. The Utilities' distribution costs are the essential, primarily fixed, expenditures it must incur to operate and maintain more than 53,000 miles of mains and services comprising the natural gas distribution systems and related storage facilities for Laclede Gas and Alagasco.
The Utilities' 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 control the APSCrate-making process, and recovery of these types of costs is included in revenues generated through the Utilities' tariff rates. Laclede Gas' tariff rates are approved by the MoPSC, whereas Alagasco's tariff rates are approved by the APSC. Laclede Gas also has an off-system sales and capacity release income stream that is regulated by tariff.
Laclede Gas’ income from off-system sales and capacity release remains subject to fluctuations in market conditions. Laclede Gas is allowed to retain the following portions annual income (shown by service territory):
|
| | |
| Laclede Gas Company (eastern Missouri) | | |
| Pre-tax Income | Customer Share | Company Share |
| First $2.0* | 100% | —% |
| Next $2.0 | 80% | 20% |
| Next $2.0 | 75% | 25% |
| Amounts exceeding $6.0 | 70% | 30% |
| * Customer share reverts to 85% and company share reverts to 15% in 2017. | | |
| | | |
| MGE (western Missouri) | | |
| Pre-tax Income | Customer Share | Company Share |
| First $1.2 | 85% | 15% |
| Next $1.2 | 80% | 20% |
| Next $1.2 | 75% | 25% |
| Amounts exceeding $3.6 | 70% | 30% |
Some of the factors impacting the level of off-system sales include the availability and cost of Laclede Gas’ natural gas supply, the weather in its service area, and the weather in other markets. When Laclede Gas’ service area experiences warmer-than-
normal weather while other markets experience colder weather or supply constraints, some of Laclede Gas' natural gas supply is available for off-system sales.
Laclede Gas and Alagasco will consultwork actively to reduce the impact of wholesale natural gas price volatility on their costs by strategically structuring their natural gas supply portfolios to increase their gas supply availability and pricing alternatives. The Utilities may also use derivative instruments to hedge against significant changes in good faith with respect to modifications, if any. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to O&M expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.
Alagasco generates revenues through the sale and transportationcommodity price of natural gas. The transportation rate does not contain an amount representingNevertheless, the overall cost of purchased gas remains subject to fluctuations in market conditions. Laclede Gas’ Purchased Gas Adjustment (PGA) clause and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues; as such, Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers and is adjusted through theAlagasco's Gas Supply Adjustment (GSA) rider. Other non-temperature weather related conditions that may affect customer usage are not included inrider allows the temperature adjustment.
Alagasco’s natural gas and transportation sales revenues totaled $533.3 million, $451.6 million and $535.0 million in 2013, 2012 and 2011, respectively. Sales revenue in 2013 rose primarily dueUtilities to an increase in gasflow through to customers, subject to prudence review by, as applicable, the MoPSC or APSC, the cost of approximately $37 million along with an increase in customer usage of approximately $36 million. In 2013, Alagasco had a net reduction in revenues of $10.6 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. During the year ended December 31, 2012, Alagasco had a net reduction in revenues of $6.3 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. In 2013, weather that was 38.4 percent colder than in the prior year contributed to a 26.6 percent increase in residential sales volumespurchased gas supplies, including costs, cost reductions, and a 19.1 percent increase in commercial and industrial volumes. Transportation volumes fell 1.2 percent. In 2012, sales revenue declined largely due to decreased customer usage of approximately $53 million and a decline in gas cost of approximately $38 million. Alagasco had a net reduction in revenues of $6.3 million pre-tax in 2012, as discussed above. During the year ended December 31, 2011, Alagasco had a net reduction in revenues of $6.7 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. Weather was 27.1 percent warmer in 2012 than in the prior year. Residential sales volumes declined 24.2 percent while commercial and industrial volumes decreased 16.2 percent. Transportation volumes increased 7.8 percent. In 2013, higher gasrelated carrying costs along with increased gas purchase volumes contributed to a 51.5 percent increase in cost of gas. A significant decrease in gas purchase volumes combined with a decrease in gas costs resulted in a 39.1 percent decrease in cost of gas in 2012.
O&M expense at the utility rose 1.3 percent in 2013 largely due to increased labor-related costs (approximately $3.5 million) and increased bad debt expense (approximately $0.6 million) partially offset by decreased consulting and technology costs (approximately $1 million). O&M expense at the utility rose 1.7 percent in 2012 largely due to higher business development and marketing expense (approximately $1.9 million), increased distribution operations (approximately $0.8 million), additional technology costs (approximately $0.6 million) and increased legal expense (approximately $0.4 million) partially offset by decreased bad debt expense (approximately $2.3 million) impacted by warmer weather in the current year and enhanced credit and collection processes implemented in 2011. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013, 2012 and 2011.
Depreciation expense increased 3.9 percent and 5.9 percent in 2013 and 2012, respectively, largely due to the extension and replacement of the utility’s distribution system and replacement of its support systems. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013, 2012 and 2011, respectively.
Alagasco’s expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Natural gas transportation and sales revenues | $ | 533,338 |
| $ | 451,589 |
| $ | 534,953 |
|
| Cost of gas | (215,455 | ) | (142,228 | ) | (233,523 | ) |
| Operations and maintenance | (143,138 | ) | (141,334 | ) | (139,030 | ) |
| Depreciation and amortization | (43,907 | ) | (42,270 | ) | (39,916 | ) |
| Income taxes | (34,687 | ) | (30,244 | ) | (26,670 | ) |
| Taxes, other than income taxes | (37,070 | ) | (32,541 | ) | (36,268 | ) |
| Operating income | $ | 59,081 |
| $ | 62,972 |
| $ | 59,546 |
|
| Natural gas sales volumes (MMcf) | | | |
| Residential | 20,279 |
| 16,014 |
| 21,132 |
|
| Commercial and industrial | 9,968 |
| 8,372 |
| 9,994 |
|
| Total natural gas sales volumes | 30,247 |
| 24,386 |
| 31,126 |
|
| Natural gas transportation volumes (MMcf) | 47,534 |
| 48,106 |
| 44,614 |
|
| Total deliveries (MMcf) | 77,781 |
| 72,492 |
| 75,740 |
|
Non-Operating Items
Consolidated: Interest expense rose $3.7 million in 2013 largely due to higher short-term borrowings and the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. The $600 million issuance includes $400 million with a floating rate of LIBOR plus 1.625 percent, currently 1.792 percent at December 31, 2013 and $200 million swapped to a fixed rate at 2.6675 percent. These increases in interest expense for 2013 were partially offset by the October 2013 repayment of $50 million of 5 percent Notes and the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011. In 2012, interest expense increased $20.7 million primarily due to the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the November 2011 issuance of $300 million of Senior Term Loans. The $300 million issuance included $100 million with a floating rate of LIBOR plus 1.375 percent and $200 million swapped to a fixed rate at 2.4175 percent. Higher short-term borrowings also contributed to the increase in interest expense for 2012. The average daily outstanding balance under credit facilities was $804.9 million in 2013. The average daily outstanding balance under credit facilities was $331.1 million in 2012 as compared to $229.1 million in 2011. Other income for the Company increased $12.5 million in 2013 primarily due to the pre-tax gain of $10.9 million on the August 2013 sale of Alagasco’s Metro Operations Center. Income tax expense decreased in 2013 largely due to lower pre-tax income while income tax expense increased in 2012 primarily due to higher pre-tax income.
FINANCIAL POSITION AND LIQUIDITY
The Company’s net cash from operating activities totaled $927.4 million, $735.7 million and $761.8 million in 2013, 2012 and 2011, respectively. During 2013, operating cash flows increased due to an increase in oil and natural gas liquids production and
higher natural gas and oil commodity prices at Energen Resources. Net income in 2013 was also significantly impacted by non-cash charges, including higher DD&A, the change in derivative fair value and a gain on the sale of certain assets. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices, and the timing of payments and recoveries, including gas supply pass-through adjustments. Net income decreased during 2012 largely due to lower realized natural gas and natural gas liquids commodity prices partially offset by increased production volumes at Energen Resources and higher oil commodity prices. During 2011, net income decreased largely due to lower realized natural gas commodity prices partially offset by increased production volumes at Energen Resources and higher oil and natural gas liquids commodity prices. During 2011, the income tax receivable decreased approximately $37.1 million primarily from an income tax refund associated with the 2010 impactuse of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs during 2013, 2012 and 2011 at Alagasco were largely affected by gas costs, accrued taxes and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments and recoveries, including gas supply pass-through adjustments and refundable negative salvage costs, combinedderivative instruments to create the remaining increases in all years.
The Company made net investments of $1,053.6 million during 2013. Energen Resources invested $31.3 million in property acquisitions including approximately $26.8 million of unproved leaseholds; $675.4 million for development costs (excludes the reversal of approximately $23.9 million of accrued development cost) including approximately $457 million to drill 179 net development and service wells; and $423.7 million for exploration including approximately $295 million to drill 90 net exploratory wells. Energen Resources had cash proceeds in 2013 of $161 million primarily from the sale of certain Black Warrior Basin properties. Utility expenditures in 2013 totaled $86.0 million (excludes approximately $2 million of accrued capital cost) and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems. Alagasco had cash proceeds in 2013 of $13.8 million from the sale of its Metro Operations Center. During 2012, the Company made net investments of $1,322.2 million. Energen Resources invested $139.6 million in property acquisitions including approximately $58.6 million of unproved leaseholds; $692.4 million for development costs (excludes the reversal of approximately $46.8 million of accrued development cost) including approximately $560 million to drill 288 net development and service wells; and $416.7 million for exploration including approximately $376.6 million to drill 75 net exploratory wells. In February 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million adding approximately 8.2 MMBOE of proved reserves. Energen Resources had cash proceeds in 2012 of $3 million primarily from the sale of certain Black Warrior Basin properties. Utility expenditures in 2012 totaled $69.9 million (excludes approximately $1.3 million of accrued capital cost). During 2011, the Company made net investments of $1,193.5 million. Energen Resources invested $310.2 million in property acquisitions including approximately $91.9 million of unproved leaseholds; $618 million for development costs (excludes the reversal of approximately $1 million of accrued development cost) including approximately $520 million to drill 403 net development and service wells; and $188.7 million for exploration including approximately $178.8 million to drill 24 net exploratory wells. In November 2011, Energen Resources completed a purchase of liquids-rich properties located in the Permian Basin for a cash price of approximately $162 million adding approximately 13.6 MMBOE in proved reserves. Energen Resources completed, in December 2011, a purchase of oil properties located in the Permian Basin for a cash price of approximately $60 million. The acquisition added approximately 3.4 MMBOE in proved reserves. Energen Resources had cash proceeds in 2011 of $8 million primarily from the sale of certain Permian and Black Warrior basin properties. Utility expenditures in 2011 totaled $73.4 million (includes approximately $0.4 million of accrued capital cost).
During 2013, Energen Resources added 37 MMBOE of proved reserves from discoveries and other additions, primarily the result of development and exploratory drilling that increased the number of proved undeveloped locations in the Permian Basin. Also during 2013, the Company added approximately 0.2 MMBOE of proved reserves primarily from Permian Basin oil property acquisitions. Energen Resources added approximately 69 MMBOE and 66 MMBOE of proved reserves in 2012 and 2011, respectively.
The Company provided $122.1 million from net financing activities in 2013 largely from the December 2013 issuance of $600 million of Senior Term Loans with a floating interest rate partially offset the repayment of long-term debt of $350.1 million combined with a decrease in short-term borrowings. In 2012, the Company provided $586.6 million from net financing activities largely from an increase in short-term borrowings used to fund development activity at Energen Resources. In 2011, the Company provided $418.6 million from net financing activities largely from the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the November 2011 issuance of $300 million of Senior Term Loans with a floating interest rate, partially offset by a decrease in short-term debt borrowings. In addition, long-term debt was reduced by $1.2 million and $5.5 million for current maturities in 2012 and 2011, respectively. For each of the years, net cash used in financing activities also reflected dividends paid to common shareholders which were partially offset by the issuance of common stock through the Company’s stock-based compensation plan.
Capital Expenditures
Oil and Gas Operations: Capital projects at Energen Resources are detailed below. The expanded exploratory expenditures are the result of our activities following the acquisitions of significant unproved leasehold in the Permian Basin in 2012 and 2011.
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Capital and exploration expenditures for: | | | |
| Property acquisitions | $ | 31,481 |
| $ | 138,496 |
| $ | 306,881 |
|
| Development | 654,222 |
| 748,251 |
| 621,550 |
|
| Exploration | 423,698 |
| 416,678 |
| 188,660 |
|
| Other | 11,352 |
| 4,543 |
| 9,277 |
|
| Total | 1,120,753 |
| 1,307,968 |
| 1,126,368 |
|
| Less exploration expenditures charged to income | 16,008 |
| 16,757 |
| 10,916 |
|
| Net capital expenditures | $ | 1,104,745 |
| $ | 1,291,211 |
| $ | 1,115,452 |
|
Natural Gas Distribution: Capital projects at Alagasco are detailed below.
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Capital expenditures for: | | | |
| Renewals, replacements, system expansion and other | $ | 59,750 |
| $ | 50,075 |
| $ | 53,970 |
|
| Support systems and facilities | 29,019 |
| 21,794 |
| 20,014 |
|
| Total | $ | 88,769 |
| $ | 71,869 |
| $ | 73,984 |
|
FUTURE CAPITAL RESOURCES AND LIQUIDITY
Oil and Gas Operations
The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2014, the Company expects its oil and gas capital spending to total approximately $1.05 billion, including $780 million for existing properties and $265 million for exploration. Included in this $780 million is approximately $306 million for the development of previously identified proved undeveloped reserves.
Capital expenditures by area during 2014 are planned as follows:
|
| | | |
| Year ended December 31, (in thousands) | 2014 |
| Permian Basin development | $ | 765,000 |
|
| Permian Basin exploration | 265,000 |
|
| San Juan Basin | 15,000 |
|
| Other | 5,000 |
|
| Total | $ | 1,050,000 |
|
Energen anticipates having the following drilling rigs and net wells by area during 2014. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.
|
| | |
| | Drilling Rigs | Net Wells |
| Permian Basin | 14 | 161 |
The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace.
Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.
Discontinued Operations
In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.
In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas natural gas and oil properties for $31.5 million (subject to closing adjustments). The Company expects to complete the sale in the first quarter of 2014 and will use the proceeds to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.
During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations for the year ended December 31, 2012. The impairment was caused by the impact of lower future natural gas prices. This impairment writedown is classified as Level 3 fair value.
Natural Gas Distribution
Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider which permits the pass-through to customers for changesmitigate volatility in the cost of natural gas, as well as gas inventory carrying costs. As of September 30, 2015, Laclede Gas had active derivative positions, but Alagasco has had no derivative instrument activity since 2010. The Utilities believe they will continue to be able to obtain sufficient gas supply. The GSA rider is designed to capture the Company’s costprice of natural gas supplies and provides for a pass-through of gas cost fluctuationsother economic conditions may affect sales volumes, due to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management realized gains and losses.
Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco’s average customer count for 2013 declined approximately 0.6 percent from 2012 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco’s average customer count include recent weather trends, enhanced credit and collectionconservation efforts and the loss of customers, due to a 2011 weather event. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices, weather conditions and the underlying current and future economic conditions facing the utility’s customer base. During the year ended December 31, 2013, Alagasco reduced the bad debt reserve by approximately $0.7 million primarily due to certain aged receivables transitioned to the utility’s long-term collections, in addition to the impact of its collection related initiatives.
Alagasco maintains an investment in storage gas that is expected to average approximately $28 million in 2014 but will vary depending upon the price of natural gas. During 2014, Alagasco plans to invest approximately $74 million in capital expenditures for the normal needs of its distribution, support systems and technology-related projects designed to improve customer service and the construction of two service centers to replace the Metro Operations Center sold during 2013. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.
In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues
from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.
Credit Facilities and Working Capital
Access to capital is an integral part of the Company’s business plan. While the Company expects to have ongoing access to its credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco. Both the Company and Alagasco were in compliance with the terms of the syndicated credit facilities at December 31, 2013.
At December 31, 2013, the Company reported negative working capital of $682.7 million arising from current liabilities of $1,109.9 million exceeding current assets of $427.2 million. The negative working capital is primarily due to a $628 million increase in borrowings during 2012 partially offset by a $104 million decrease in borrowings during 2013 under the syndicated unsecured credit facilities and in support of Energen’s capital projects. Generally Accepted Accounting Principles require classification as short-term for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated unsecured credit facilities were entered into on October 30, 2012 and have a five-year term. Accordingly, the Company believes that it has adequate financing capacity available for its expected liquidity needs.
Working capital of Energen is also influenced by the fair value of the Company’s derivative financial instruments associated with future production. Energen’s accounts receivable and accounts payable at December 31, 2013 include $17.5 million and $30.3 million, respectively, associated with its derivative financial instruments. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco’s business and reflects an expected pass-through to rate payers of $15.8 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by its syndicated unsecured credit facilities to fund working capital needs.
Credit Ratings
On April 26, 2013, Moody’s Investor Service updated its credit opinion for Energen and Alagasco confirming Energen’s senior unsecured credit rating as investment grade with a negative outlook. Alagasco’s senior unsecured credit rating was lowered one notch but remains investment grade with a negative outlook. On December 16, 2013, Standard & Poor’s lowered its debt ratings for Energen and Alagasco’s from investment grade with a stable outlook to investment grade with a negative outlook.
Dividends
Energen expects to pay annual cash dividends of $0.60 per share on the Company’s common stock in 2014. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.
Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2013:
|
| | | | | | | | | | | | | | | |
| | Payments Due Before December 31, |
(in thousands) |
Total |
2014 |
2015-2016 |
2017-2018 | 2019 and Thereafter |
Long-term debt (1) | $ | 1,403,923 |
| $ | 60,000 |
| $ | 200,000 |
| $ | 439,000 |
| $ | 704,923 |
|
| Interest payments on debt | 455,171 |
| 54,585 |
| 100,763 |
| 82,812 |
| 217,011 |
|
Purchase obligations (2) | 171,110 |
| 47,810 |
| 93,840 |
| 26,791 |
| 2,669 |
|
| Operating leases | 31,627 |
| 5,270 |
| 9,331 |
| 6,389 |
| 10,637 |
|
Asset retirement obligations (3) | 709,451 |
| 11,538 |
| 6,162 |
| 5,933 |
| 685,818 |
|
| Nonqualified supplemental retirement plans | 36,597 |
| 6,145 |
| 1,112 |
| 9,939 |
| 19,401 |
|
| Total contractual cash obligations | $ | 2,807,879 |
| $ | 185,348 |
| $ | 411,208 |
| $ | 570,864 |
| $ | 1,640,459 |
|
(1) Long-term cash obligations include approximately $0.5 million of unamortized debt discounts as of December 31, 2013.
(2) Certain of the Company’s long-term contracts associated with the delivery and storagetiming of natural gas include fixed charges of approximately $171 million through September 2024. The Company also is committed to purchase minimum quantitiescollection of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 134 Bcf through August 2020.
(3) Represents the estimated future asset retirement obligation on an undiscounted basis. Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.
Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.1 MMBOE through September 2017.
Energen Resources entered into an agreement which commenced on January 15, 2012 and expires in January 2015 to secure a drilling rig necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of this drilling rig, Energen Resources’ total resulting exposure could be as much as $3.9 million depending on the contractor’s ability to remarket the drilling rig.
There are no required contributions to the qualified pension plans during 2014. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $3 million to the qualified pension plans in January 2014. During 2014, the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. The contractual obligations reported above exclude any payments the Company expects to make to postretirement benefit program assets.
The contractual obligations reported above exclude the Company’s liability of $16.0 million related to the Company’s provision for uncertain tax positions. The Company cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.
During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.
As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2013.
OUTLOOK
Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2014. Production in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE, including approximately 22.1 MMBOE of estimated production from proved reserves owned at December 31, 2013. Production estimates do not include amounts for potential future acquisitions. In the event Energen Resources is unable to fully invest in its capital investment opportunities, future operating revenues, production and proved reserves could be negatively affected.
Production volumes by area are expected to be as follows:
|
| |
Year ended December 31, (MMBOE) | 2014 |
Permian Basin | 16.5 |
San Juan Basin/other | 8.4 |
Total (midpoint of range) | 24.9 |
Production volumes by commodity are expected to be as follows:
|
| |
Year ended December 31, (MMBOE) | 2014 |
Gas | 9.7 |
Oil | 11.4 |
Natural gas liquids | 3.8 |
Total (midpoint of range) | 24.9 |
During 2014, Energen Resources expects an annualized decline rate of approximately14 percent for its proved developed producing properties owned at December 31, 2013. During the same period, total production from proved properties is expected to decrease approximately 5 percent and total production is expected to increase approximately 6.7 percent. The above proved developed producing properties decline rate is not necessarily indicative of the Company’s expectations for its terminal decline rate on a long-term basis.
Various factors influence decline rates. For example, certain properties may have production curves that decline at faster rates in the early years of production and at slower rates in later years. Accordingly, the decline rate for a single year is influenced by numerous factors, including but not limited to, the mix of types of wells, the mix of newer versus older wells, and the effect of enhanced recovery activities, but it is not necessarily indicative of future decline rates. Energen Resources expects a compound annual decline rate for proved producing properties owned at December 31, 2013 for the 5 year period 2013 to 2018, for the 10 year period 2013 to 2023 and for the 20 year period 2013 to 2033 of approximately 13.2 percent, 10.6 percent and 8.7 percent, respectively.
Energen Resources’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties.
Revenues and related accounts receivable from oilcustomers.
Both Laclede Gas and gasAlagasco rely on short-term credit and long-term capital markets, as well as cash flows from operations, primarily are generated fromto satisfy their seasonal cash requirements and fund their capital expenditures. The Utilities' ability to issue commercial paper, access their lines of credit, issue long-term bonds, or obtain new lines of credit is dependent on current conditions in the salecredit 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 their foreseeable obligations. See the Liquidity and Capital Resources section on page 41 for additional information. Gas Marketing
LER provides both on-system Laclede Gas transportation customers and customers outside of produced oil,Laclede Gas' traditional service area with another choice in non-regulated natural gas andsuppliers. LER utilizes its natural gas liquidssupply agreements, transportation agreements, park and loan agreements, storage agreements, and other executory contracts to energy marketing companies. Suchsupport 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 subject to more fluctuations in market conditions than Laclede Gas’ operations.
LER’s business is directly impacted by the effects of competition in the marketplace, the impacts of new 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 be challenged by significant commodity pricing declines that occurred through fiscal 2015 and that are expected to remain constrained for the foreseeable future.
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 typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales tofrom customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit qualityindustry. 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 of operations.
LER carefully monitors the creditworthiness of counterparties to its transactions. LER performs in-house credit reviews of potential customers and in certain instances, may require credit assurances such as a deposit, letterprepayments, letters of credit, or parent guarantee.parental guarantees when appropriate. Credit limits for customers are established and monitored.
Derivative Commodity Instruments
Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. At December 31, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at December 31, 2013. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production.
In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.
Energen Resources entered into the following transactions for 2014 and subsequent years:
|
| | | | |
| Production Period | Total Hedged Volumes | Average Contract Price |
Description |
| Natural Gas |
| 2014 | 10.6 | Bcf | $4.55 Mcf | NYMEX Swaps |
| | 31.4 | Bcf | $4.60 Mcf | Basin Specific Swaps - San Juan |
| | 9.7 | Bcf | $3.81 Mcf | Basin Specific Swaps - Permian |
| 2015 | 6.0 | Bcf | $4.07 Mcf | Basin Specific Swaps - San Juan |
| Oil |
| 2014 | 9,796 | MBbl | $92.64 Bbl | NYMEX Swaps |
| 2015 | 5,760 | MBbl | $88.85 Bbl | NYMEX Swaps |
Energen Resources has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2013, Energen Resources was in a net loss position of $7.4 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $165 million change in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the impact of related taxes on actual cash prices.
All derivatives are recognized at fair value under the fair value hierarchy as discussed in Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements. Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to New York Mercantile Exchange (NYMEX) natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties’ valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen or Alagasco. As of the balance sheet date, the Company believes that these prices represent the best estimate of the exit price for these instruments and are representative of the prices for which the contract will ultimately settle or realize.
The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:
|
| | | | | | | | | |
| | December 31, 2013 |
| (in thousands) | Level 2* | Level 3* | Total |
| Current assets | $ | (1,658 | ) | $ | 19,121 |
| $ | 17,463 |
|
| Noncurrent assets | 4,383 |
| 1,056 |
| 5,439 |
|
| Current liabilities | (28,414 | ) | (1,888 | ) | (30,302 | ) |
| Net derivative asset (liability) | $ | (25,689 | ) | $ | 18,289 |
| $ | (7,400 | ) |
|
| | | | | | | | | |
| | December 31, 2012 |
| (in thousands) | Level 2* | Level 3* | Total |
| Current assets | $ | (3,629 | ) | $ | 68,421 |
| $ | 64,792 |
|
| Noncurrent assets | 18,899 |
| 21,678 |
| 40,577 |
|
| Current liabilities | (2,593 | ) | — |
| (2,593 | ) |
| Noncurrent liabilities | (8,520 | ) | (1,080 | ) | (9,600 | ) |
| Net derivative asset | $ | 4,157 |
| $ | 89,019 |
| $ | 93,176 |
|
* Amounts classified in accordance with accounting guidance which permits offsetting fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
As of December 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.
Level 3 assets as of December 31, 2013 represent an immaterial amount of both total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $19 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $19 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012. However, the Company could experience increased costs and reduced liquidity in the markets as a result of the new rulesinfrastructure optimization activities and regulations,an abundance of natural gas supply, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically. As such, certain transactions entered into in fiscal years 2015, 2014, and 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 could reduce hedging opportunities and negatively affectmay cause volatility in the Company’s operating revenues, but has no effect on operating income or net income.
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 cash flows.
Natural Gas Distribution: The extension of RSE effective January 1, 2014 provides Alagascosale transactions are not recognized in earnings until the opportunity to continue earning an allowed return on average equity between 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent through September 30, 2018. Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider which permitsis physically delivered, while other energy-related transactions, including those designated as trading activities, are required to be accounted for as derivatives, with the pass-through to customers for 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 costrecognition of gas supply. Alsoearnings under GAAP and economic earnings realized upon settlement. The Company reports both GAAP and net economic earnings (non-GAAP), as discussed below.
Other
In addition to the Gas Utility and Gas Marketing segments, the Company's business includes certain other non-utility activities reported as Other. Other includes:
unallocated corporate costs, including certain debt and associated interest costs,
Laclede Pipeline Company, a subsidiary of Laclede Group which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction, and
Laclede Group's subsidiaries that are engaged in Note 2, Regulatory Matters,compression of natural gas, oil production, real estate development, risk management, and financial investments in the Notes to Financial Statements, the utility’s CCM is based on the rate of inflation. Decreases in residential customers and declines in usage per customer in the residential and small commercial classes, as well as market sensitive load losses from large industrial and commercial customers, will make it more difficult for the utility to earn within its allowed range of return on equity. With the support of the APSC, Alagasco has implemented a variety of programs to help it compete for gas load in all market segments. The Company has been effective in utilizing these programs to deter load loss to competitive fuels.
other enterprises, among other activities. All subsidiaries are wholly owned.
CRITICAL ACCOUNTING POLICIES AND ESTIMATESEARNINGS
The Company’s consolidated financial statementsNet income reported by the Laclede Group, Laclede Gas and Alagasco are prepareddetermined in accordance with accounting principles generally accepted in the United States of America.America (GAAP). Management has identifiedalso uses the following critical accounting policies in the applicationnon-GAAP measures of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company. The application of these accounting policies necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material impact on the financial statements.
Oil and Gas Operations
Accounting for Oil and Natural Gas Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its oil and natural gas producing activities. Acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existingnet economic earnings, net economic earnings per share and operating conditions. The technologiesmargin when internally evaluating and reporting results of operations. These non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income.
Non-GAAP Measures - Net Economic Earnings and Net Economic Earnings Per Share
Net economic earnings and net economic earnings per share are non-GAAP measures that exclude from net income the after-tax impacts of fair value accounting and timing adjustments associated with these proved reserve estimates are analysis of well production data, geophysical data, wireline and core data. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have audited the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company’s net interests in oil and gas properties as of December 31, 2013. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. The Company’s production of proved undeveloped reserves requires the drilling of development wells and the installation or completion of related infrastructure facilities.
Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted.
The table below reflects an estimated increase in 2014 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2013:
|
| | | | | | |
| | Percentage Change in Oil & Gas Reserves |
| | From Reported Reserves as of December 31, 2013 |
| (dollars in thousands) | -5% | -10% |
Estimated increase in DD&A expense for the year ended December 31, 2014, net of tax | $ | 15,197 |
| $ | 31,912 |
|
Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred.
Asset Impairments: Oil and gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The Company monitors its oil and gas propertiesenergy-related transactions as well as acquisition, divestiture, and restructuring activities. These fair value and timing adjustments are made in instances where the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, substantial commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, Energen Resources makes an estimate of undiscounted future cash flows to determine whetheraccounting treatment differs from the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book valueeconomic substance of the propertiesunderlying 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 properties. Thecarrying 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.
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 properties typicallyactual gains or losses realized when the associated physical transaction(s) occur. While management uses these non-GAAP measures to evaluate both the Utilities and LER, the net effect of adjustments on the Utilities' earnings are minimal. This is estimated using discounted cash flows.due to gains or losses on Laclede Gas' natural gas derivative instruments being deferred pursuant to its PGA clause, as authorized by the MoPSC.
Cash flow andManagement believes that excluding the earnings volatility caused by recognizing changes in fair value estimates require Energen Resourcesprior to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount ratessettlement and other factorstiming 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. In addition, management excludes the impact related to unique acquisition, divestiture, and restructuring activities when evaluating on-going performance, and therefore excludes these impacts from net economic earnings. Net economic earnings per share also exclude the impacts of the May 2013 and June 2014 equity offerings to fund the acquisitions of MGE and Alagasco, respectively. Management believes that this presentation provides a useful representation of operating performance by facilitating comparisons of year-over-year results. The definition and measurement of net economic earnings provided above is consistent with that used by management and the Board of Directors in assessing the Company's, Laclede Gas' and Alagasco's performance as well as determining performance under the Company's, Laclede Gas' and Alagasco's incentive compensation plans. Further, the Company believes this better enables an investor to view the Company's, Laclede Gas' and Alagasco's performance in that period on a basis that would be comparable to prior periods.
Reconciliations of net economic earnings and net economic earnings per share to the Company's most directly comparable GAAP measures are provided on the following pages.
Non-GAAP Measure - Operating Margin
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 Utilities pass to their customers (subject to prudence review by, as applicable, the MoPSC or APSC) increases and decreases in the wholesale cost of natural gas in accordance with their PGA clauses (Missouri Utilities) and GSA rider (Alabama Utility). 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 and gross receipts tax expense, which are calculated as a percentage of revenues, with the same amount, excluding immaterial timing differences, included in revenues, has no direct effect on operating income. As these costs are included in revenue and operating expenses and management does not have any control over these amounts for many years into the future. These variables can,Utilities, management believes that beginning with operating margins is a more useful measure. In addition, it is management's belief that operating margins and often do, differthe remaining operating expenses that calculate operating income is a more useful measure in assessing the Company's and the Utilities' performance as management has more ability to influence control over these revenues and expenses.
LACLEDE GROUP
Overview – Net Income (Loss)
|
| | | | | | | | | | | | | | | | | | | | |
| | | Gas Utility | | Gas Marketing | | Other | | Consolidated | | Per Diluted Share |
| Year Ended September 30, 2015 | | | | | | | | | |
| | Net Income (Loss) (GAAP) | $ | 153.3 |
| | $ | 4.1 |
| | $ | (20.5 | ) | | $ | 136.9 |
| | $ | 3.16 |
|
| | Unrealized (gain) on energy-related derivatives* | (0.1 | ) | | (1.7 | ) | | — |
| | (1.8 | ) | | (0.04 | ) |
| | Lower of cost or market inventory adjustments* | — |
| | 0.3 |
| | — |
| | 0.3 |
| | 0.01 |
|
| | Realized loss on economic hedges prior to the sale of the physical commodity* | — |
| | 1.5 |
| | — |
| | 1.5 |
| | 0.03 |
|
| | Acquisition, divestiture and restructuring activities* | 1.9 |
| | — |
| | 4.2 |
| | 6.1 |
| | 0.14 |
|
| | Gain on sale of property* | (4.7 | ) | | — |
| | — |
| | (4.7 | ) | | (0.11 | ) |
| | Net Economic Earnings (Loss) (Non-GAAP) | $ | 150.4 |
| | $ | 4.2 |
| | $ | (16.3 | ) | | $ | 138.3 |
| | $ | 3.19 |
|
| | | | | | | | | | | |
| Year Ended September 30, 2014 | | | | | | | | | |
| | Net Income (Loss) (GAAP) | $ | 87.1 |
| | $ | 12.2 |
| | $ | (14.7 | ) | | $ | 84.6 |
| | $ | 2.35 |
|
| | Unrealized loss (gain) on energy-related derivatives* | 0.2 |
| | (1.1 | ) | | — |
| | (0.9 | ) | | (0.02 | ) |
| | Lower of cost or market inventory adjustments* | — |
| | (0.7 | ) | | — |
| | (0.7 | ) | | (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* | 5.5 |
| | — |
| | 11.8 |
| | 17.3 |
| | 0.48 |
|
| | Weighted average shares adjustment ** | | | | | | | | | 0.27 |
|
| | Net Economic Earnings (Loss) (Non-GAAP) | $ | 92.8 |
| | $ | 10.2 |
| | $ | (2.9 | ) | | $ | 100.1 |
| | $ | 3.05 |
|
| | | | | | | | | | | |
| 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 |
|
| | Less: Acquisition, divestiture and restructuring activities* | 0.3 |
| | — |
| | 10.5 |
| | 10.8 |
| | 0.42 |
|
| | Weighted average shares adjustment *** | | | | | | | | | $ | 0.38 |
|
| | Net Economic Earnings (Loss) (Non-GAAP) | $ | 56.7 |
| | $ | 8.9 |
| | $ | (0.6 | ) | | $ | 65.0 |
| | $ | 2.87 |
|
| |
| * | 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. |
| |
| ** | 2014 net economic earnings per share excludes the impact of the June 2014 equity offerings to fund the acquisition of Alagasco, but includes the May 2013 equity offering to fund the MGE acquisition. The weighted-average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2014 was 32.7 compared to 35.9 in the GAAP EPS calculation. |
| |
| *** | 2013 net economic earnings per share excludes the impact of the May 2013 equity offering to fund the acquisition of MGE. The weighted-average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2014 was 22.5 compared to 26.0 in the GAAP EPS calculation. |
2015 vs. 2014
Consolidated
Laclede Group’s net income was $136.9 in fiscal year 2015, compared with $84.6 in fiscal year 2014. Basic and diluted earnings per share were $3.16 for fiscal year 2015 compared with basic and diluted earnings per share of $2.36 and $2.35, respectively, for fiscal year 2014. Net economic earnings were $138.3 (or $3.19 per share) in fiscal year 2015, compared with $100.1 (or $3.05 per share) in fiscal year 2014. Net income increased in fiscal year 2015 compared to fiscal year 2014 primarily due to $66.2 income growth in the Gas Utility segment, which reflects $50.9 improvement relating to the inclusion of a full year of Alagasco earnings versus the $2.9 Alagasco loss included in 2014 for the month of September. Gas Utility also
benefited from $15.3 income growth from the estimatesMissouri Utilities. The increased net income from Gas Utility was partially offset by an $8.1 decrease in Gas Marketing net income and can have a positive or negative impact on$5.8 higher loss from other non-utility activities, principally due to interest expense relating to the Company’s need2014 financing of the Alagasco acquisition.
Gas Utility
Gas Utility net income and net economic earnings increased by $66.2 and $57.6, respectively, in 2015, compared to 2014. The increases to net income and net economic earnings were primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $271.3, which reflects the inclusion of Alagasco operating margin of $285.1 for impairment or on the amounttwelve months in 2015 versus $14.8 for one month in 2014, and a $1.0 increase in Laclede Gas operating margin. The increase in operating margin was partially offset by an increase in other operating expenses of impairment. In addition, further changes$112.1 and an increase in depreciation and amortization expenses totaling $47.5, as discussed in the Gas Utility section below. Additionally, interest expense for 2015 was $11.6 higher than 2014 due to the inclusion of full year Alagasco results offsetting the $1.0 decline experienced by Laclede Gas. Income taxes were also higher by $38.8, due to higher Missouri Utilities operating results and from the inclusion of twelve months of Alagasco operating results in 2015 versus only the month of September in 2014.
Gas Marketing
Gas Marketing reported GAAP earnings totaling $4.1, a decrease of $8.1 compared with the same period last year. Net economic earnings for fiscal year 2015 decreased $6.0 from fiscal year 2014. The decreases in net income and business environment cannet economic earnings were primarily attributable to decreases in operating margin, with the impact to net economic earnings being partly mitigated by mark-to-market activity as discussed in the Company’s originalGas Marketing section below.
Other
The combined net loss and ongoing assessmentsnet economic loss for the Company's other non-utility activities were $5.8 and $13.4 larger, respectively, for the 2015 fiscal year compared to the same period last year. The increase in net loss was primarily the result of potential impairment.$16.6 increased interest expense related to the 2014 debt issued to finance the Alagasco acquisition, partially offset by lower transaction and integration expenses in fiscal year 2015 as compared to 2014.
Operating Revenues and Operating Expenses
Energen Resources also may recognize impairmentsReconciliations of capitalized costsoperating margin to the most directly comparable GAAP measure are shown below. |
| | | | | | | | | | | | | | | | |
| | Gas Utility | Gas Marketing | Other | Eliminations | Consolidated |
| Year Ended September 30, 2015 | | | | | |
| | Operating Revenues | $ | 1,895.8 |
| $ | 153.4 |
| $ | 3.7 |
| $ | (76.5 | ) | $ | 1,976.4 |
|
| | Natural and propane gas expense | 957.6 |
| 140.5 |
| 0.3 |
| (75.5 | ) | 1,022.9 |
|
| | Gross receipts tax expense | 96.1 |
| 0.2 |
| — |
| — |
| 96.3 |
|
| | Operating margin (non-GAAP) | 842.1 |
| 12.7 |
| 3.4 |
| (1.0 | ) | 857.2 |
|
| | Depreciation and amortization | 129.9 |
| 0.3 |
| 0.6 |
| — |
| 130.8 |
|
| | Other operating expenses | 437.6 |
| 5.6 |
| 11.7 |
| (1.0 | ) | 453.9 |
|
| | Operating income (Loss) (GAAP) | $ | 274.6 |
| $ | 6.8 |
| $ | (8.9 | ) | $ | — |
| $ | 272.5 |
|
| | | | | | | |
| Year Ended September 30, 2014 | |
| |
| |
| | |
|
| | Operating revenues | $ | 1,467.8 |
| $ | 246.6 |
| $ | 3.8 |
| $ | (91.0 | ) | $ | 1,627.2 |
|
| | Natural and propane gas expense | 821.8 |
| 220.4 |
| — |
| (90.2 | ) | 952.0 |
|
| | Gross receipts tax expense | 75.2 |
| 0.2 |
| — |
| — |
| 75.4 |
|
| | Operating margin (non-GAAP) | 570.8 |
| 26.0 |
| 3.8 |
| (0.8 | ) | 599.8 |
|
| | Depreciation and amortization | 82.4 |
| 0.4 |
| 0.5 |
| — |
| 83.3 |
|
| | Other operating expenses | 325.5 |
| 5.4 |
| 20.0 |
| (0.8 | ) | 350.1 |
|
| | Operating income (Loss) (GAAP) | $ | 162.9 |
| $ | 20.2 |
| $ | (16.7 | ) | $ | — |
| $ | 166.4 |
|
| | | | | | | |
| 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 |
| (35.7 | ) | 606.3 |
|
| | Gross receipts tax expense | 40.2 |
| 0.1 |
| — |
| — |
| 40.3 |
|
| | Operating margin (non-GAAP) | 348.5 |
| 17.7 |
| 4.9 |
| (0.7 | ) | 370.4 |
|
| | Depreciation and amortization | 48.3 |
| 0.3 |
| 0.7 |
| — |
| 49.3 |
|
| | Other operating expenses | 200.6 |
| 4.6 |
| 20.1 |
| (0.7 | ) | 224.6 |
|
| | Operating income (Loss) (GAAP) | $ | 99.6 |
| $ | 12.8 |
| $ | (15.9 | ) | $ | — |
| $ | 96.5 |
|
Consolidated
Laclede Group reported operating revenues of $1,976.4 for unproved properties.the fiscal year ended September 30, 2015 compared with $1,627.2 for the same period last year. Laclede Group's operating margin increased $257.4 for the twelve months ended September 30, 2015, compared to the same period last year primarily due to higher Gas Utility operating margin, slightly offset by the lower operating margin reported by Gas Marketing as discussed below. Other operating expenses and depreciation and amortization increased $103.8 and $47.5, respectively, for the twelve months ended September 30, 2015 as compared to the same period last year. These increases were primarily due to the impact of eleven additional months of Alagasco other operating expenses and depreciation and amortization expenses in fiscal 2015 totaling $134.4 and $43.4, respectively. The greatest portionincrease in other operating expenses was partially offset by $22.3 lower expenses in the Missouri Utilities and a $8.3 decrease in expenses in Other, as discussed below. The remaining increase in depreciation and amortization was related to higher capital spending within the Missouri Utilities in 2015.
Gas Utility
Operating Revenues – Gas Utility Operating Revenues for fiscal year 2015 increased $428.0, compared to fiscal year 2014, was primarily attributable to the following factors:
|
| | | |
| New customer revenue from Alagasco acquisition | $ | 459.5 |
|
| Variance due to Missouri Utilities: | |
| Lower system volumes and off-system pricing | (42.2 | ) |
| Base rate increases and Infrastructure System Replacement Surcharge (ISRS) charges | 10.9 |
|
| Higher wholesale gas prices passed to customers | 7.1 |
|
| Higher optimization of assets in the prior year | (6.2 | ) |
| Lower gross receipts tax | (1.8 | ) |
| All other variance | 0.7 |
|
| Total Variation | $ | 428.0 |
|
Operating Margin – Gas Utility operating margin was $842.1 for fiscal year 2015, a $271.3 increase over the same period last year. The increase was attributable to the following factors:
|
| | | |
| Operating margin from Alagasco | $ | 270.3 |
|
| Variance due to Missouri Utilities: | |
| Base rate increases and ISRS charges | 10.9 |
|
| Lower system volumes and off-system pricing | (8.3 | ) |
| Higher optimization of assets in the prior year | (3.1 | ) |
| All other variance | 1.5 |
|
| Total Variation | $ | 271.3 |
|
The increase was primarily attributable to the acquisition of leaseholdAlagasco totaling $270.3. Temperatures in the Laclede Gas service area in 2015 were 11.2% warmer than in the same period in the prior year, negatively impacting current year revenues by $8.3. The prior year also benefited $3.1 due to a higher level of asset optimization. These negative impacts to revenue were mostly offset by base rate increases and ISRS charges of $10.9.
Operating Expenses – Gas Utility other operating expenses in fiscal year 2015 increased $112.1 from fiscal year 2014, with $134.4 attributable to the Alagasco acquisition offset by a decrease in other operating expenses within the Missouri Utilities. Of the $22.3 decrease in Missouri, $7.6 was due to a gain on the sale of property, $7.5 was the result of lower payroll and benefits expenses, and $9.8 resulted from cost efficiencies. Depreciation and amortization expense increased $4.1 at the Missouri Utilities primarily due to higher levels of capital expenditures, with the remaining $43.4 increase reflecting the inclusion of Alagasco for the full fiscal year.
Gas Marketing
Operating Revenues – Gas Marketing operating revenue for the twelve months ended September 30, 2015 decreased $93.2 from the same period last year due to higher per unit gas sales prices in the prior year as the colder weather in the Midwest created higher market volatility and basis differentials (pricing differences between supply regions). Gas commodity pricing has also declined $1.35/MMBtu versus the prior year. Overall gas commodity pricing in the current year is below the prior year, negatively impacting revenues in the current year. The prior year also included a $3.3 higher benefit from mark-to-market impact on derivatives and inventory.
Operating Margin – Gas Marketing operating margin was $12.7 for fiscal year 2015, a $13.3 decrease compared to the same period last year. Of this decrease, $10.0 was primarily attributable to higher sales margins (operating margin less fair value adjustments) last year reflecting higher market volatility and basis differentials of natural gas prices and the expiration of a favorable gas supply contract in the first quarter of fiscal 2014. The remaining variance was due to $3.3 higher pre-tax income in the prior year associated with unrealized gains on derivatives and lower-of-cost-or-market adjustments to inventory.
Other
Operating Revenue and Operating Expenses - Other operating revenue was essentially flat with the prior year, as volume increases at the Company's Spire LNG fueling operations were offset by lower prices. Other operating expenses decreased $8.3 primarily due to the Alagasco acquisition-related transaction expenses in the prior year being higher than the MGE and Alagasco integration related expenses incurred in fiscal 2015.
Interest Charges
Interest charges during the twelve months ended September 30, 2015 increased $28.4 from the same period last year. The increase was primarily due to the Company's August 2014 issuance of long-term debt totaling $625.0, and the June 2014 issuance of equity units totaling $143.8. These increases were partially offset by Laclede Gas' early redemption of $80.0 of 6.35% first mortgage bonds on January 6, 2014. The assumption of Alagasco debt contributed $12.6 to the increase in interest expense. For the twelve months ended September 30, 2015 and 2014, average short-term borrowings were $300.6 and $82.3, respectively, and the average interest rates on those borrowings were 0.7% and 0.5%, respectively.
Income Taxes
Consolidated Income tax expense increased $29.9 in fiscal year 2015 from fiscal year 2014 primarily due to higher pre-tax income and a higher effective tax rate. The current year effective tax rate of 31.2% is approximately 3.6 percentage points higher than the prior year primarily due to the full-year inclusion of Alagasco, which has a higher effective tax rate than Laclede Gas.
In connection with the acquisition of 100% of the common stock of Alagasco (Alagasco Transaction), the Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco Transaction as a deemed purchase and sale of assets for tax purposes. As a result of the election, goodwill was generated for tax purposes at Alagasco. For book purposes, goodwill was recorded on the Laclede Group parent entity balance sheet and not pushed down to Alagasco. Consequently, a deferred tax asset (DTA) was recorded at Alagasco related to the excess of tax deductible goodwill over book goodwill for the stand-alone entity. That initial goodwill DTA is eliminated (along with the investment in subsidiary and Alagasco’s equity) in the Laclede Group consolidated balance sheet because, at that consolidated level, there is no excess of tax deductible goodwill over book goodwill. As the tax goodwill is amortized and deducted for tax purposes, the DTA at Alagasco is reduced, and for Laclede Group, a deferred tax liability (DTL) is created. For both Alagasco and consolidated Laclede Group, the change to the goodwill DTA/DTL is reported as a component of deferred tax expense in the statements of income. Because the deferred tax expense impact is offset by an opposite current tax expense impact, there is no significant impact on the effective tax rate of the Company.
LACLEDE GAS
Summary Operating Results
|
| | | | | | | |
| Year ended September 30, | 2015 | | 2014 |
| Operating revenues | $ | 1,416.6 |
| | $ | 1,448.2 |
|
| Natural and propane gas expense | 786.1 |
| | 816.9 |
|
| Gross receipts tax expense | 73.5 |
| | 75.2 |
|
| Operating margin (non-GAAP) | 557.0 |
| | 556.1 |
|
| Depreciation and amortization | 82.6 |
| | 78.5 |
|
| Other operating expenses | 289.0 |
| | 311.2 |
|
| Operating income (GAAP) | $ | 185.4 |
| | $ | 166.4 |
|
| Net Income | $ | 105.3 |
| | $ | 90.1 |
|
Operating revenues during the twelve months ended September 30, 2015 decreased $31.6 from the same period last year. Base rate increases and ISRS charges of $10.9 and $7.1 in higher wholesale gas costs passed onto customers were more than offset by $42.2 in lower system volumes and off-system pricing and $6.2 higher optimization of assets in the prior year.
Operating margin for the twelve months ended September 30, 2015 increased $0.9 from the same period last year. Higher base rates and ISRS charges of $10.9 and other positive variations of $1.5 were mostly offset by lower system volumes and off-system pricing of $8.3 in the current year and $3.1 in higher optimization of assets in the prior year.
Other operating expenses for the twelve months ended September 30, 2015 decreased $22.2 versus the same period last year. Primary drivers of the expense decrease were a $7.6 gain on the sale of property, $9.8 of cost efficiencies and a $7.5 decrease in payroll and benefits expenses. Resulting net income for the twelve months ended September 30, 2015 increased $15.2 from the same period last year.
Temperatures experienced in the Missouri Utilities' service area during 2015 were 11.2% warmer than the same period last year and 1.5% warmer than normal. Total system therms sold and transported were 1,684.3 million for fiscal year 2015 compared with 1,828.1 million for fiscal year 2014. Total off-system therms sold and transported outside of Laclede Gas' service area were 193.5 million for fiscal year 2015 compared with 125.8 million for fiscal year 2014. This increase was due to warmer temperatures and decreased heating demand in Laclede Gas' services areas, increasing the gas supply resources
available for off-system sales or capacity release. However, the increase in off-system volume revenue was more than offset by lower gas commodity pricing realized during 2015.
ALAGASCO
Change in Fiscal Year
Effective September 2, 2014, Alagasco changed its fiscal year end from December 31 to September 30. The various periods that are covered in the discussion below are defined as follows:
"current year" means October 1, 2014 through September 30, 2015; and
"transition period" means January 1, 2014 through September 30, 2014.
Summary Operating Results
|
| | | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 |
| Operating revenues | $ | 479.2 |
| | $ | 417.2 |
|
| Natural gas expense | 171.5 |
| | 184.5 |
|
| Gross receipts tax expense | 22.6 |
| | 20.6 |
|
| Operating margin (non-GAAP) | 285.1 |
| | 212.1 |
|
| Depreciation and amortization | 47.3 |
| | 34.4 |
|
| Other operating expenses | 148.6 |
| | 115.5 |
|
| Operating income (GAAP) | $ | 89.2 |
| | $ | 62.2 |
|
| Net Income | $ | 48.0 |
| | $ | 33.0 |
|
Operating revenues for the twelve months ended September 30, 2015 increased $62.0 versus the transition period ended September 30, 2014. Of the increase, $142.7 was attributable to the current year including one more quarter of operating activity, offset by lower system volumes and lower pricing in the current year totaling $80.7.
Operating margin increased $73.0, due primarily to the inclusion of $84.3 relating to the extra quarter of activity included in the current year results, offset slightly by the previously mentioned lower system volumes and pricing.
Other operating expenses for the twelve months ended September 30, 2015 increased $33.1 versus the transition period ended September 30, 2014. $38.4 of the increase was due to the current year including one more quarter of activity than the prior year. This increase was offset slightly by $2.6 lower labor-related costs and exploratory drilling costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes$2.7 in economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluatenet other cost reductions during the need for impairment of these costs.
Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Energen Resources enters into derivative transactions that are accounted for as mark-to-market transactions with gains and losses reported in current period operating revenues. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.
Natural Gas Distribution
Regulated Operations: Alagasco capitalizes costs as regulatory assets that otherwise would be charged to expense if it is probable that the cost is recoverableyear. Net income increased $15.0 in the future through regulated rates. Likewise, if current recovery is providedyear, $19.8 due to the inclusion of an extra quarter of activity in 2015 partly offset due to the factors described above.
Temperatures in Alagasco's service area during the twelve months ended September 30, 2015 were 9.7% colder than normal. However, temperatures were 7.8% warmer than the same period a year earlier. The colder than normal temperatures still resulted in comparatively higher gas usage for a cost that will be incurred incycle customers versus the future,prior year. Alagasco's total therms sold and transported were 865.0 million for the cost would be recognized as a regulatory liability. Alagasco’s rate setting methodology,twelve months ended September 30, 2015, compared with 840.1 million for the same period last year.
For further information on the GSA and Rate Stabilization and Equalization has been in effect since 1983.
Consolidated
Employee Benefit Plans: An employer is required to recognize the net funded status(RSE) mechanisms, please see Note 1, Summary of defined benefit pensionsSignificant Accounting Policies, and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. The pension benefit obligation is the projected benefit obligation, a measurement of earned benefit obligations at expected retirement salary levels; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation, a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods.
Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to the Company’s benefit plans includes assumptions regarding the appropriate weighted average discount rate, the expected long-term rate of return on the plans’ assets and the estimated weighted average rate of increase in the compensation level of its employee base for defined benefit pension plans. The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans,15, Regulatory Matters, in the Notes to Financial Statements.
2014 vs. 2013
In selecting each discount rate, considerationLACLEDE GROUP
Consolidated
Laclede Group’s net income was given$84.6 in fiscal year 2014, including net loss of $2.9 relating to Moody’s Aa corporate bond rates, alongAlagasco's operations for the month ended September 30, 2014, compared with a yield curve applied$52.8 in fiscal year 2013. Basic and diluted earnings per share were $2.36 and $2.35 respectively for fiscal year 2014 compared with basic and diluted earnings per share of $2.03 and $2.02 respectively for fiscal year 2013. Net economic earnings were $100.1 (or $3.05 per share) in fiscal year 2014, compared with $65.0 (or $2.87 per share) in fiscal year 2013. GAAP earnings increased in fiscal year 2014 compared to paymentsfiscal year 2013 primarily due to improved results in Laclede Group's Gas Utility segment, which reflects the Company expects to make out of its retirement plans. The yield curve is comprisedinclusion of a broad basefull year of Aa bondsMGE operations,
improved earnings from Gas Marketing and the impact of colder weather in fiscal 2014, partially offset by Alagasco acquisition costs and MGE integration costs incurred during the year.
Gas Utility
Gas Utility net income and net economic earnings increased by $30.8 and $36.1, respectively, in 2014, compared with maturities between zero2013. The increase to net income and thirty years.net economic earnings were primarily due to higher operating margin (a non-GAAP measure discussed below) of $222.3, which reflects the inclusion of MGE operating margin of $186.5 and Alagasco operating margin of $14.8. These increases were partially offset by an increase in other operating expenses of $124.9, including MGE other operating expenses of $103.5; Alagasco other operating expenses of $14.2; an increase in depreciation and amortization expenses totaling $34.1, including MGE depreciation and amortization expenses totaling $26.0 and Alagasco depreciation and amortization of $3.9; higher interest expense totaling $12.6; and increased income tax expenses of $14.5.
Gas Marketing
Gas Marketing reported GAAP earnings totaling $12.2, an increase of $4.6 compared with the same period in 2013. Net economic earnings for fiscal year 2014 increased $1.3 from fiscal year 2013. The discount rateincreases in net income and net economic earnings were primarily attributable to increases in operating margin, as discussed in the Gas Marketing section below.
Other
Other net income and other net economic earnings for each plan was developedfiscal 2014 decreased $3.6 and $2.3, respectively, compared with the fiscal 2013. The decrease in net income is primarily due to expenses attributable to the Alagasco acquisition in fiscal 2014 being higher than the expenses attributable to the MGE and NEG transaction in 2013.
Operating Revenues and Operating Expenses
Reconciliations of the Company's operating margin to the most directly comparable GAAP measure are shown below.
Consolidated
Laclede Group reported operating revenues of $1,627.2 for the fiscal year ended September 30, 2014 compared with $1,017.0 for the 2013 fiscal year. Laclede Group's operating margin increased $229.4 for the twelve months ended September 30, 2014, compared to the same period in 2013 primarily due to higher Gas Utility operating margin, and growth in the operating margin reported by Gas Marketing as discussed below. Other operating expenses and depreciation and amortization increased $125.5 and $34.0, respectively, for the twelve months ended September 30, 2014 as compared to the twelve months ended September 30, 2013. The increases were primarily due to the incremental impact of eleven additional months of MGE other operating expenses and depreciation and amortization expenses in fiscal 2014 totaling $103.5 and $26.0, respectively, as well as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the weighted average discount rate used to determine net periodic benefit costs was 3.63 percent for the plans for the year ended December 31, 2013.inclusion of one month of Alagasco operating expenses and depreciation and amortization of $14.2 and $3.9, respectively. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic benefit cost was 7 percent for each of the applicable plans for the year ended December 31, 2013. The estimated weighted average rate ofremaining increase in other operating expenses was due to the compensation level for pay related plans was 3.71 percent for the year ended December 31, 2013.
The selection and useimpact of actuarial assumptions affects the amount of benefit expense recordedcolder weather reflected in the Company’s financial statements.higher provision for uncollectible accounts, and higher maintenance and employee-related expenses. The remaining increase in depreciation and amortization was associated with capital spending in fiscal 2014.
The table below reflects a hypothetical 25 basis point change in assumed actuarial assumptionsGas Utility
Operating Revenues – Gas Utility Operating Revenues for fiscal year 2014 increased $610.0, compared to pre-tax benefit expense forfiscal year 2013, which was primarily attributable to the year ended December 31, 2013:
following factors:
|
| | | | | | |
| (in thousands) | Pension Expense | Postretirement Expense |
| Discount rate change | $ | 1,750 |
| $ | 10 |
|
| Return on assets | $ | 530 |
| $ | 180 |
|
| Compensation increase | $ | 975 |
| $ | — |
|
|
| | | |
| Higher system sales volumes and other variations | $ | 66.3 |
|
| Lower wholesale gas costs passed on to Utility customers | (9.4 | ) |
| Lower off-system sales volumes | (11.7 | ) |
| Propane utility sales | 9.2 |
|
| Higher gross receipts tax | 3.7 |
|
| New customer revenue from MGE acquisition | 532.2 |
|
| New customer revenue from Alagasco acquisition | 19.7 |
|
| Total Variation | $ | 610.0 |
|
The weighted average discount rate, return on plan assetsTemperatures experienced in Laclede Gas' service area during 2014 were 13.3% colder than 2013 and estimated rate11.4% colder than normal. Total system therms sold and transported were 1,876.6 million for fiscal year 2014 compared with 889.7 million for fiscal year 2013. Total off-system therms sold and transported outside of compensation increase used in the 2014 actuarial assumptions are 4.31 percent, 7.00 percent and 3.63 percent, respectively.Laclede Gas' service area were 125.8 million for fiscal
year 2014 compared with 229.4 million for fiscal year 2013. This decrease was due to colder temperatures and increased heating demand in our services areas, reducing the gas supply resources available for off-system sales or capacity release.
Asset Retirement Obligation: Operating MarginThe Company records the fair value of – Gas Utility operating margin was $570.8 for fiscal year 2014, a liability for an asset retirement obligation in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated$222.3 increase over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligationsame period for its recorded amount and recognize the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment.2013. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.
Uncertain Tax Positions: The Company accounts for uncertain tax positions in accordance with accounting guidance which prescribes a recognition threshold and measurement attribute for financial statement recognition. The application of income tax law is inherently complex; laws and regulation in this area are voluminous and often ambiguous. As such, the Company is required to make many subjective assumptions and judgments regarding income tax exposures. Interpretations and guidance related to income tax laws and regulation change over time. It is possible that changes in the Company’s subjective assumptions and judgments could materially affect amounts recognized in the consolidated balance sheets and statements of income. Additional information relatedincrease was attributable to the Company’s uncertain tax positions is provided in Note 4, Income Taxes, in the Notes to the Financial Statements.following factors:
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD
See Note 17, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item with respect to market risk is set forth in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Outlook” and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.
| |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
|
| | |
| | Page |
1. | Financial Statements | |
| | |
| Energen Corporation | |
| | |
| Report of Independent Registered Public Accounting Firm | |
| | |
| Consolidated Statements of Income for the years ended December 31, 2013, 2012
and 2011
| |
| | |
| Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012
and 2011
| |
| | |
| Consolidated Balance Sheets as of December 31, 2013 and 2012 | |
| | |
| Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2013, 2012
and 2011
| |
| | |
| Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 | |
| | |
| Notes to Financial Statements | |
| | |
| Alabama Gas Corporation | |
| | |
| Report of Independent Registered Public Accounting Firm | |
| | |
| Statements of Income for the years ended December 31, 2013, 2012 and 2011 | |
| | |
| Balance Sheets as of December 31, 2013 and 2012 | |
| | |
| Statements of Shareholder’s Equity for the years ended December 31, 2013, 2012
and 2011
| |
| | |
| Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 | |
| | |
| Notes to Financial Statements | |
| | |
2. | Financial Statement Schedules | |
| | |
| Energen Corporation | |
| Schedule II - Valuation and Qualifying Accounts | |
| | |
| Alabama Gas Corporation | |
| Schedule II - Valuation and Qualifying Accounts | |
|
| | | |
| Operating margin from MGE | $ | 186.5 |
|
| Operating margin from Alagasco | 14.8 |
|
| Cold weather impact - higher therms sold and transported | 11.9 |
|
| Propane utility sales | 6.1 |
|
| Other | 3.0 |
|
| Total Variation | $ | 222.3 |
|
Schedules other than those listed above are omitted because they are not required, not applicable, orThe increase is primarily attributable to the required information is shownacquisitions of MGE and Alagasco totaling $186.5 and $14.8, respectively. The higher system sales volume driven by the 13.3% colder weather in the financial statements or notes thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ToLaclede Gas service area contributed to $11.9 of the Boardincrease. $6.1 of Directors and Shareholdersthe increase was the result of Energen Corporation:
propane utility sales, with the remaining $3.0 the result of all other minor variations.
In our opinion,Operating Expenses – Gas Utility other operating expenses in fiscal year 2014 increased $124.9 from fiscal year 2013. Of the consolidated financial statements listed$124.9 increase, $103.5 is attributable to the MGE acquisition and $14.2 is the result of the Alagasco acquisition. The remaining increase in other expenses was due to the impact of colder weather reflected in the accompanying index present fairly, in all material respects,higher provision for uncollectible accounts, higher maintenance costs and employee-related expenses. Excluding the financial positionacquisition impact of Energen Corporation and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reportingappearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Birmingham, Alabama
March 3, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Alabama Gas Corporation:
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearingunder Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Birmingham, Alabama
March 3, 2014
CONSOLIDATED STATEMENTS OF INCOME
Energen Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands, except share data) | 2013 | 2012 | 2011 |
| | | | |
| Operating Revenues | | | |
| Oil and gas operations | $ | 1,205,312 |
| $ | 1,089,230 |
| $ | 838,160 |
|
| Natural gas distribution | 533,338 |
| 451,589 |
| 534,953 |
|
| Total operating revenues | 1,738,650 |
| 1,540,819 |
| 1,373,113 |
|
| Operating Expenses | | | |
| Cost of gas | 215,455 |
| 142,228 |
| 233,523 |
|
| Operations and maintenance | 562,350 |
| 458,084 |
| 398,084 |
|
| Depreciation, depletion and amortization | 497,381 |
| 385,453 |
| 253,757 |
|
| Taxes, other than income taxes | 105,268 |
| 86,801 |
| 88,351 |
|
| Accretion expense | 6,995 |
| 6,339 |
| 5,699 |
|
| Total operating expenses | 1,387,449 |
| 1,078,905 |
| 979,414 |
|
| Operating Income | 351,201 |
| 461,914 |
| 393,699 |
|
| Other Income (Expense) | | | |
| Interest expense | (69,200 | ) | (65,542 | ) | (44,822 | ) |
| Other income | 16,803 |
| 4,285 |
| 2,206 |
|
| Other expense | (375 | ) | (903 | ) | (456 | ) |
| Total other expense | (52,772 | ) | (62,160 | ) | (43,072 | ) |
| Income From Continuing Operations Before Income Taxes | 298,429 |
| 399,754 |
| 350,627 |
|
| Income tax expense | 105,282 |
| 144,534 |
| 126,322 |
|
| Income From Continuing Operations | 193,147 |
| 255,220 |
| 224,305 |
|
| Discontinued Operations, net of taxes | | | |
| Income (loss) from discontinued operations | 7,813 |
| (1,658 | ) | 35,319 |
|
| Gain on disposal of discontinued operations, net | 3,594 |
| — |
| — |
|
| Income (Loss) From Discontinued Operations | 11,407 |
| (1,658 | ) | 35,319 |
|
| Net Income | $ | 204,554 |
| $ | 253,562 |
| $ | 259,624 |
|
| | | | |
| Diluted Earnings Per Average Common Share | | | |
| Continuing operations | $ | 2.67 |
| $ | 3.53 |
| $ | 3.10 |
|
| Discontinued operations | 0.15 |
| (0.02 | ) | 0.49 |
|
| Net Income | $ | 2.82 |
| $ | 3.51 |
| $ | 3.59 |
|
Basic Earnings Per Average Common Share | | | |
| Continuing operations | $ | 2.67 |
| $ | 3.54 |
| $ | 3.11 |
|
| Discontinued operations | 0.16 |
| (0.02 | ) | 0.49 |
|
| Net Income | $ | 2.83 |
| $ | 3.52 |
| $ | 3.60 |
|
| | | | |
| Diluted Average Common Shares Outstanding | 72,470,622 |
| 72,316,214 |
| 72,332,369 |
|
| Basic Average Common Shares Outstanding | 72,317,865 |
| 72,119,021 |
| 72,055,661 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Energen Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| Net Income | $ | 204,554 |
| $ | 253,562 |
| $ | 259,624 |
|
| Other comprehensive income (loss): | | | |
| Cash flow hedges: | | | |
| Current period change in fair value of commodity derivative instruments, net of tax of ($6,660), $40,720 and $41,399, respectively | (10,866 | ) | 66,438 |
| 67,547 |
|
| Reclassification adjustment for commodity derivative instruments, net of tax of ($13,560), ($17,994) and ($8,953), respectively | (22,124 | ) | (29,359 | ) | (14,607 | ) |
| Current period change in fair value of interest rate swap, net of tax of ($80), ($1,228) and ($507), respectively | (148 | ) | (2,281 | ) | (941 | ) |
| Reclassification adjustment for interest rate swap, net of tax of $603 and $574, respectively | 1,120 |
| 1,066 |
| — |
|
| Total cash flow hedges | (32,018 | ) | 35,864 |
| 51,999 |
|
| Pension and postretirement plans: | | | |
| Amortization of net obligation at transition, net of taxes of $112, $100 and $96, respectively | 207 |
| 186 |
| 177 |
|
| Amortization of prior service cost, net of taxes of $90, $119 and $104, respectively | 167 |
| 221 |
| 194 |
|
| Amortization of net loss, net of taxes of $4,472, $1,676 and $1,270, respectively | 8,306 |
| 3,113 |
| 2,359 |
|
| Current period change in fair value of pension and postretirement plans, net of taxes of $6,237, ($9,393), and ($5,699), respectively | 11,582 |
| (17,443 | ) | (10,584 | ) |
| Total pension and postretirement plans | 20,262 |
| (13,923 | ) | (7,854 | ) |
| Comprehensive Income | $ | 192,798 |
| $ | 275,503 |
| $ | 303,769 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
Energen Corporation
|
| | | | | | | |
| (in thousands) | December 31, 2013 | | December 31, 2012 |
| | | | |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 5,555 |
| | $ | 9,704 |
|
| Accounts receivable, net of allowance for doubtful accounts of $5,694 and $6,549 at December 31, 2013 and 2012, respectively | 257,545 |
| | 277,900 |
|
| Inventories | | | |
| Storage gas inventory | 32,095 |
| | 32,205 |
|
| Materials and supplies | 16,601 |
| | 28,291 |
|
Liquified natural gas in storage | 3,634 |
| | 3,498 |
|
| Regulatory assets | 2,756 |
| | 45,515 |
|
| Income tax receivable | 5,765 |
| | 6,664 |
|
| Assets held for sale | 51,104 |
| | — |
|
| Deferred income taxes | 41,299 |
| | 8,520 |
|
| Prepayments and other | 10,877 |
| | 12,823 |
|
| Total current assets | 427,231 |
| | 425,120 |
|
| Property, Plant and Equipment | | | |
| Oil and gas properties, successful efforts method | 6,864,375 |
| | 6,439,127 |
|
| Less accumulated depreciation, depletion and amortization | 1,776,802 |
| | 1,765,241 |
|
| Oil and gas properties, net | 5,087,573 |
| | 4,673,886 |
|
| Utility plant | 1,491,433 |
| | 1,416,590 |
|
| Less accumulated depreciation | 605,924 |
| | 573,947 |
|
| Utility plant, net | 885,509 |
| | 842,643 |
|
| Other property, net | 30,556 |
| | 25,107 |
|
| Total property, plant and equipment, net | 6,003,638 |
| | 5,541,636 |
|
| Other Assets | | | |
| Regulatory assets | 84,890 |
| | 110,566 |
|
| Other postretirement assets | 35,351 |
| | 1,404 |
|
| Long-term derivative instruments | 5,439 |
| | 40,577 |
|
| Deferred charges and other | 65,663 |
| | 56,587 |
|
| Total other assets | 191,343 |
| | 209,134 |
|
| TOTAL ASSETS | $ | 6,622,212 |
| | $ | 6,175,890 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
Energen Corporation
|
| | | | | | | |
| (in thousands, except share data) | December 31, 2013 | | December 31, 2012 |
| | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities | | | |
| Long-term debt due within one year | $ | 60,000 |
| | $ | 50,000 |
|
| Notes payable to banks | 539,000 |
| | 643,000 |
|
| Accounts payable | 250,756 |
| | 257,579 |
|
| Accrued taxes | 36,228 |
| | 30,076 |
|
| Customer deposits | 21,692 |
| | 24,705 |
|
| Amounts due customers | 16,990 |
| | 19,718 |
|
| Accrued wages and benefits | 33,884 |
| | 24,984 |
|
| Regulatory liabilities | 49,006 |
| | 45,116 |
|
| Royalty payable | 51,519 |
| | 34,426 |
|
| Liabilities related to assets held for sale | 18,545 |
| | — |
|
| Other | 32,273 |
| | 30,178 |
|
| Total current liabilities | 1,109,893 |
| | 1,159,782 |
|
| Long-term debt | 1,343,464 |
| | 1,103,528 |
|
| Deferred Credits and Other Liabilities | | | |
| Asset retirement obligation | 108,533 |
| | 118,023 |
|
| Pension liabilities | 67,675 |
| | 110,282 |
|
| Regulatory liabilities | 94,125 |
| | 80,404 |
|
| Deferred income taxes | 1,013,245 |
| | 905,601 |
|
| Long-term derivative instruments | 398 |
| | 11,305 |
|
| Other | 26,860 |
| | 10,275 |
|
| Total deferred credits and other liabilities | 1,310,836 |
| | 1,235,890 |
|
| Commitments and Contingencies |
|
| |
|
|
Shareholders’ Equity Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized | — |
| | — |
|
| Common shareholders’ equity | | | |
| Common stock, $0.01 par value; 150,000,000 shares authorized, 75,574,156 shares issued at December 31, 2013 and 75,067,760 shares issued at December 31, 2012 | 756 |
| | 751 |
|
Premium on capital stock | 520,909 |
| | 492,108 |
|
Capital surplus | 2,802 |
| | 2,802 |
|
Retained earnings | 2,476,616 |
| | 2,314,055 |
|
Accumulated other comprehensive income (loss), net of tax | | | |
| Unrealized gain on hedges, net | 13,362 |
| | 46,352 |
|
| Pension and postretirement plans | (32,245 | ) | | (52,507 | ) |
| Interest rate swap | (1,184 | ) | | (2,156 | ) |
| Deferred compensation plan | 3,259 |
| | 2,774 |
|
| Treasury stock, at cost: 2,967,999 shares and 2,998,620 shares at December 31, 2013 and 2012, respectively | (126,256 | ) | | (127,489 | ) |
| Total shareholders’ equity | 2,858,019 |
| | 2,676,690 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 6,622,212 |
| | $ | 6,175,890 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Energen Corporation
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | Premium on Capital Stock | Capital Surplus | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Deferred Compensation Plan | Treasury Stock | Total Shareholders’ Equity |
| (in thousands, except share data) | Number of Shares | Par Value |
| BALANCE DECEMBER 31, 2010 | 74,786,376 |
| $ | 748 |
| $ | 468,934 |
| $ | 2,802 |
| $ | 1,880,183 |
| $ | (74,397 | ) | $ | 3,288 |
| $ | (127,515 | ) | $ | 2,154,043 |
|
| Net income | | | | | 259,624 |
| | | | 259,624 |
|
| Other comprehensive income | | | | | | 44,145 |
| | | 44,145 |
|
| Purchase of treasury shares, net | | | | | | | | (713 | ) | (713 | ) |
| Shares issued for employee benefit plans | 221,036 |
| 2 |
| 7,235 |
| | | | | | 7,237 |
|
| Deferred compensation obligation | | | | | | | 223 |
| (223 | ) | — |
|
| Stock-based compensation | | | 5,763 |
| | | | | | 5,763 |
|
| Tax benefit from employee stock plans | | | 986 |
| | | | | | 986 |
|
| Cash dividends - $0.54 per share | | | | | (38,922 | ) | | | | (38,922 | ) |
| BALANCE DECEMBER 31, 2011 | 75,007,412 |
| 750 |
| 482,918 |
| 2,802 |
| 2,100,885 |
| (30,252 | ) | 3,511 |
| (128,451 | ) | 2,432,163 |
|
| Net income | | | | | 253,562 |
| | | | 253,562 |
|
| Other comprehensive income | | | | | | 21,941 |
| | | 21,941 |
|
| Purchase of treasury shares, net | | | | | | | | (277 | ) | (277 | ) |
| Shares issued for employee benefit plans | 60,348 |
| 1 |
| 2,060 |
| | | | | | 2,061 |
|
| Deferred compensation obligation | | | | | | | (737 | ) | 737 |
| — |
|
| Stock-based compensation | | | 6,580 |
| | | | | 502 |
| 7,082 |
|
| Tax benefit from employee stock plans | | | 550 |
| | | | | | 550 |
|
| Cash dividends - $0.56 per share | | | | | (40,392 | ) | | | | (40,392 | ) |
| BALANCE DECEMBER 31, 2012 | 75,067,760 |
| 751 |
| 492,108 |
| 2,802 |
| 2,314,055 |
| (8,311 | ) | 2,774 |
| (127,489 | ) | 2,676,690 |
|
| Net income | | | | | 204,554 |
| | | | 204,554 |
|
| Other comprehensive loss | | | | | | (11,756 | ) | | | (11,756 | ) |
| Purchase of treasury shares, net | | | | | | | | (1,038 | ) | (1,038 | ) |
| Shares issued for employee benefit plans | 506,396 |
| 5 |
| 18,790 |
| | | | | | 18,795 |
|
| Deferred compensation obligation | | | | | | | 485 |
| (485 | ) | — |
|
| Stock-based compensation | | | 6,869 |
| | | | | 2,756 |
| 9,625 |
|
| Tax benefit from employee stock plans | | | 3,142 |
| | | | | | 3,142 |
|
| Cash dividends - $0.58 per share | | | | | (41,993 | ) | | | | (41,993 | ) |
| BALANCE DECEMBER 31, 2013 | 75,574,156 |
| $ | 756 |
| $ | 520,909 |
| $ | 2,802 |
| $ | 2,476,616 |
| $ | (20,067 | ) | $ | 3,259 |
| $ | (126,256 | ) | $ | 2,858,019 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Energen Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| Operating Activities | | | |
| Net income | $ | 204,554 |
| $ | 253,562 |
| $ | 259,624 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| Depreciation, depletion and amortization | 527,845 |
| 419,598 |
| 283,997 |
|
| Asset impairment | 29,794 |
| 21,545 |
| — |
|
| Accretion expense | 8,192 |
| 7,534 |
| 6,837 |
|
| Deferred income taxes | 83,650 |
| 124,399 |
| 129,041 |
|
| Bad debt expense | 781 |
| 153 |
| 2,525 |
|
| Change in derivative fair value | 48,029 |
| (41,819 | ) | 36,210 |
|
| Gain on sale of assets | (46,377 | ) | (529 | ) | (5,994 | ) |
| Stock-based compensation expense | 14,892 |
| 6,047 |
| 9,011 |
|
| Exploratory expense | 16,008 |
| 16,757 |
| 10,916 |
|
| Other, net | 23,810 |
| 8,597 |
| 7,537 |
|
| Net change in: | | | |
| Accounts receivable | 4,216 |
| (11,923 | ) | (16,359 | ) |
| Inventories | 11,596 |
| 10,018 |
| (14,710 | ) |
| Accounts payable | (58,859 | ) | (16,392 | ) | 12,978 |
|
| Amounts due customers, including gas supply pass-through | 40,542 |
| (57,747 | ) | (2,597 | ) |
| Income tax receivable | 899 |
| 679 |
| 37,146 |
|
| Pension and other postretirement benefit contributions | (11,747 | ) | (5,996 | ) | (5,986 | ) |
| Other current assets and liabilities | 29,552 |
| 1,254 |
| 11,655 |
|
| Net cash provided by operating activities | 927,377 |
| 735,737 |
| 761,831 |
|
| Investing Activities | | | |
| Additions to property, plant and equipment | (1,195,402 | ) | (1,184,300 | ) | (889,614 | ) |
| Acquisitions, net of cash acquired | (31,331 | ) | (139,563 | ) | (310,193 | ) |
| Proceeds from sale of assets | 174,824 |
| 2,562 |
| 7,987 |
|
| Purchase of short-term investments | (310,000 | ) | — |
| — |
|
| Sale of short-term investments | 310,000 |
| — |
| — |
|
| Other, net | (1,701 | ) | (881 | ) | (1,679 | ) |
| Net cash used in investing activities | (1,053,610 | ) | (1,322,182 | ) | (1,193,499 | ) |
| Financing Activities | | | |
| Payment of dividends on common stock | (41,993 | ) | (40,392 | ) | (38,922 | ) |
| Issuance of common stock | 17,780 |
| 1,224 |
| 6,415 |
|
| Issuance of long-term debt | 600,000 |
| — |
| 749,952 |
|
| Reduction of long-term debt | (350,105 | ) | (1,218 | ) | (5,547 | ) |
| Net change in short-term debt | (104,000 | ) | 628,000 |
| (290,000 | ) |
| Tax benefit on stock compensation | 3,142 |
| 550 |
| 986 |
|
| Other | (2,740 | ) | (1,556 | ) | (4,334 | ) |
| Net cash provided by financing activities | 122,084 |
| 586,608 |
| 418,550 |
|
| Net change in cash and cash equivalents | (4,149 | ) | 163 |
| (13,118 | ) |
| Cash and cash equivalents at beginning of period | 9,704 |
| 9,541 |
| 22,659 |
|
| Cash and cash equivalents at end of period | $ | 5,555 |
| $ | 9,704 |
| $ | 9,541 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF INCOME
Alabama Gas Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| Operating Revenues | $ | 533,338 |
| $ | 451,589 |
| $ | 534,953 |
|
| Operating Expenses | | | |
| Cost of gas | 215,455 |
| 142,228 |
| 233,523 |
|
| Operations and maintenance | 143,138 |
| 141,334 |
| 139,030 |
|
| Depreciation and amortization | 43,907 |
| 42,270 |
| 39,916 |
|
| Income taxes | | | |
| Current | 19,687 |
| 18,966 |
| (1,388 | ) |
| Deferred | 15,000 |
| 11,278 |
| 28,058 |
|
| Taxes, other than income taxes | 37,070 |
| 32,541 |
| 36,268 |
|
| Total operating expenses | 474,257 |
| 388,617 |
| 475,407 |
|
| Operating Income | 59,081 |
| 62,972 |
| 59,546 |
|
| Other Income (Expense) | | | |
| Allowance for funds used during construction | 698 |
| 623 |
| 807 |
|
| Other income | 14,393 |
| 2,382 |
| 1,309 |
|
| Other expense | (1,124 | ) | (291 | ) | (320 | ) |
| Total other income | 13,967 |
| 2,714 |
| 1,796 |
|
| Interest Expense | | | |
| Interest on long-term debt | 13,509 |
| 13,744 |
| 12,100 |
|
| Other interest expense | 2,140 |
| 2,540 |
| 2,640 |
|
| Total interest expense | 15,649 |
| 16,284 |
| 14,740 |
|
| Net Income | $ | 57,399 |
| $ | 49,402 |
| $ | 46,602 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS
Alabama Gas Corporation
|
| | | | | | | |
| (in thousands) | December 31, 2013 | | December 31, 2012 |
| | | | |
| ASSETS | | | |
| Property, Plant and Equipment | | | |
| Utility plant | $ | 1,491,433 |
| | $ | 1,416,590 |
|
| Less accumulated depreciation | 605,924 |
| | 573,947 |
|
| Utility plant, net | 885,509 |
| | 842,643 |
|
| Other property, net | 41 |
| | 42 |
|
| Current Assets | | | |
| Cash | 3,032 |
| | 5,559 |
|
| Accounts receivable | | | |
| Gas | 103,301 |
| | 94,011 |
|
| Other | 5,447 |
| | 5,117 |
|
| Affiliated companies | 4,662 |
| | 5,742 |
|
| Allowance for doubtful accounts | (5,000 | ) | | (5,700 | ) |
| Inventories | | | |
| Storage gas inventory | 32,095 |
| | 32,205 |
|
| Materials and supplies | 5,471 |
| | 5,528 |
|
| Liquified natural gas in storage | 3,634 |
| | 3,498 |
|
| Regulatory assets | 2,756 |
| | 45,515 |
|
| Income tax receivable | 3,644 |
| | 2,762 |
|
| Deferred income taxes | 20,049 |
| | 18,799 |
|
| Prepayments and other | 4,654 |
| | 4,451 |
|
Total current assets | 183,745 |
| | 217,487 |
|
| Other Assets | | | |
| Regulatory assets | 84,890 |
| | 110,566 |
|
| Other postretirement assets | 26,457 |
| | 848 |
|
| Deferred charges and other | 17,433 |
| | 11,290 |
|
Total other assets | 128,780 |
| | 122,704 |
|
| TOTAL ASSETS | $ | 1,198,075 |
| | $ | 1,182,876 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS
Alabama Gas Corporation
|
| | | | | | | |
| (in thousands, except share data) | December 31, 2013 | | December 31, 2012 |
| | | | |
| LIABILITIES AND CAPITALIZATION | | | |
| Capitalization | | | |
Preferred stock, cumulative, $0.01 par value, 120,000 shares authorized | $ | — |
| | $ | — |
|
| Common shareholder’s equity | | | |
| Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at December 31, 2013 and 2012, respectively | 20 |
| | 20 |
|
| Premium on capital stock | 31,682 |
| | 31,682 |
|
| Capital surplus | 2,802 |
| | 2,802 |
|
| Retained earnings | 350,076 |
| | 325,999 |
|
| Total common shareholder’s equity | 384,580 |
| | 360,503 |
|
| Long-term debt | 249,923 |
| | 250,028 |
|
| Total capitalization | 634,503 |
| | 610,531 |
|
| Current Liabilities | | | |
| Notes payable to banks | 50,000 |
| | 77,000 |
|
| Accounts payable | 48,653 |
| | 51,741 |
|
| Accrued taxes | 28,027 |
| | 24,186 |
|
| Customer deposits | 21,692 |
| | 24,705 |
|
| Amounts due customers | 16,990 |
| | 19,718 |
|
| Accrued wages and benefits | 7,682 |
| | 6,703 |
|
| Regulatory liabilities | 49,006 |
| | 45,116 |
|
| Other | 10,113 |
| | 9,018 |
|
| Total current liabilities | 232,163 |
| | 258,187 |
|
| Deferred Credits and Other Liabilities | | | |
| Deferred income taxes | 205,631 |
| | 189,381 |
|
| Pension liabilities | 20,191 |
| | 43,611 |
|
| Regulatory liabilities | 94,125 |
| | 80,404 |
|
| Other | 11,462 |
| | 762 |
|
| Total deferred credits and other liabilities | 331,409 |
| | 314,158 |
|
| Commitments and Contingencies |
| |
|
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 1,198,075 |
| | $ | 1,182,876 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF SHAREHOLDER’S EQUITY
Alabama Gas Corporation
|
| | | | | | | | | | | | | | | | | |
| (in thousands, except share data) |
| | Common Stock | Premium on Capital Stock | Capital Surplus | Retained Earnings | Total Shareholder’s Equity |
| | Number of Shares | Par Value |
| Balance December 31, 2010 | 1,972,052 |
| $ | 20 |
| $ | 31,682 |
| $ | 2,802 |
| $ | 292,815 |
| $ | 327,319 |
|
| Net income | | | | | 46,602 |
| 46,602 |
|
| Cash dividends | | | | | (29,183 | ) | (29,183 | ) |
| Balance December 31, 2011 | 1,972,052 |
| 20 |
| 31,682 |
| 2,802 |
| 310,234 |
| 344,738 |
|
| Net income | | | | | 49,402 |
| 49,402 |
|
| Cash dividends | | | | | (33,637 | ) | (33,637 | ) |
| Balance December 31, 2012 | 1,972,052 |
| 20 |
| 31,682 |
| 2,802 |
| 325,999 |
| 360,503 |
|
| Net income | | | | | 57,399 |
| 57,399 |
|
| Cash dividends | | | | | (33,322 | ) | (33,322 | ) |
| Balance December 31, 2013 | 1,972,052 |
| $ | 20 |
| $ | 31,682 |
| $ | 2,802 |
| $ | 350,076 |
| $ | 384,580 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF CASH FLOWS
Alabama Gas Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| Operating Activities | | | |
| Net income | $ | 57,399 |
| $ | 49,402 |
| $ | 46,602 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| Depreciation and amortization | 43,907 |
| 42,270 |
| 39,916 |
|
| Deferred income taxes | 15,000 |
| 11,278 |
| 28,058 |
|
| Bad debt expense | 774 |
| 146 |
| 2,457 |
|
| Gain on sale of assets | (10,889 | ) | — |
| — |
|
| Other, net | 14,068 |
| 10,667 |
| 1,560 |
|
| Net change in: | | | |
| Accounts receivable | (23,955 | ) | (13,528 | ) | 4,862 |
|
| Inventories | 31 |
| 10,544 |
| (7,371 | ) |
| Accounts payable | (2,464 | ) | (5,906 | ) | (1,499 | ) |
| Amounts due customers, including gas supply pass-through | 40,542 |
| (57,747 | ) | (2,597 | ) |
| Income tax receivable | (882 | ) | 7,000 |
| 553 |
|
| Pension and other postretirement benefit contributions | (6,070 | ) | (2,725 | ) | (2,811 | ) |
| Other current assets and liabilities | 2,700 |
| (8,654 | ) | (2,802 | ) |
| Net cash provided by operating activities | 130,161 |
| 42,747 |
| 106,928 |
|
| Investing Activities | | | |
| Additions to property, plant and equipment | (86,037 | ) | (69,860 | ) | (73,447 | ) |
| Proceeds from sale of assets | 13,838 |
| — |
| — |
|
| Other, net | (62 | ) | (3,252 | ) | (2,743 | ) |
| Net cash used in investing activities | (72,261 | ) | (73,112 | ) | (76,190 | ) |
| Financing Activities | | | |
| Payment of dividends on common stock | (33,322 | ) | (33,637 | ) | (29,183 | ) |
| Proceeds from issuance of long-term debt | — |
| — |
| 50,000 |
|
| Reduction of long-term debt | (105 | ) | (218 | ) | (5,547 | ) |
| Net change in short-term debt | (27,000 | ) | 62,000 |
| (55,000 | ) |
| Other | — |
| (38 | ) | (101 | ) |
| Net cash provided by (used in) financing activities | (60,427 | ) | 28,107 |
| (39,831 | ) |
| Net change in cash and cash equivalents | (2,527 | ) | (2,258 | ) | (9,093 | ) |
| Cash and cash equivalents at beginning of period | 5,559 |
| 7,817 |
| 16,910 |
|
| Cash and cash equivalents at end of period | $ | 3,032 |
| $ | 5,559 |
| $ | 7,817 |
|
The accompanying Notes to Financial Statements are an integral part of these statements.
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Energen Corporation (Energen or the Company) is an oil and gas exploration and production company complemented by its legacy natural gas distribution business. Headquartered in Birmingham, Alabama, the Company is engaged in the development, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company’s significant accounting policies and practices.
A. Principles of Consolidation
The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years’ financial statements to the current-year presentation.
B. Oil and Gas Operations
Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion$29.9, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.increased $4.2 primarily due to additional depreciable property.
The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense during the year:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Capitalized exploratory well costs at beginning of period | $ | 79,791 |
| $ | 70,437 |
| $ | 21,438 |
|
| Additions pending determination of proved reserves | 421,599 |
| 406,226 |
| 178,005 |
|
| Reclassifications due to determination of proved reserves | (442,909 | ) | (396,872 | ) | (129,006 | ) |
| Exploratory well costs charged to expense | (881 | ) | — |
| — |
|
| Capitalized exploratory well costs at end of period | $ | 57,600 |
| $ | 79,791 |
| $ | 70,437 |
|
The following table sets forth capitalized exploratory wells costs at year end and includes amounts capitalized for a period greater than one year:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Exploratory wells in progress | $ | 14,794 |
| $ | 77,693 |
| $ | 70,437 |
|
| Capitalized exploratory well costs for a period of one year or less | 42,481 |
| — |
| — |
|
| Capitalized exploratory well costs for a period greater than one year | 1,206 |
| 2,098 |
| — |
|
| Total capitalized exploratory well costs | $ | 58,481 |
| $ | 79,791 |
| $ | 70,437 |
|
At December 31, 2013, the Company had 48 gross exploratory wells either drilling or waiting on results from completion and testing. All of these wells are located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.
Gas Marketing
Operating Revenues:Revenues – Gas Marketing operating revenues for the twelve months ended September 30, 2014 increased $57.2 from the twelve months ended September 30, 2013 due to higher volumes sold and higher per unit gas sales prices. Higher gas sales prices were driven by the colder weather that resulted in a constrained infrastructure creating higher volatility between differing regions.
Operating Margin Energen Resources utilizes the sales method of accounting– Gas Marketing operating margin was $26.0 for fiscal year 2014, an $8.3 increase compared to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities soldfiscal 2013. The increase in operating margin was primarily attributable to purchasers.
Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no significant production imbalances at December 31, 2013 and 2012.
Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its exposure tohigher price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swapsvolatility and basis hedges typically with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimatedifferentials that stemmed from unusually cold winter. The higher weather-related margins offset lower run-rate margins versus the prior year, reflecting the expiration of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.
The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.
Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.
Effective March 31,two favorable gas supply contracts during 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Gains and losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.
Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.early 2014.
Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Mark-to-market gain (loss) on derivatives | $ | (47,832 | ) | $ | 58,750 |
| $ | (37,587 | ) |
All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged.
Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.
Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is 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). Fair value measurements also utilize assumptions of market participants. Energen Resources uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in operations and maintenance (O&M) expense on the consolidated income statements.
C. Natural Gas Distribution
Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.
Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $16.3 million, $14.2 million, $22.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $15.8 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $39.7 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a five year period beginning January 1, 2015. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve (ESR) and other APSC approved charges. The refunds as of December 2013 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013, 2012 and 2011, respectively.
Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.
Other
Operating Revenue and Gas Costs:Operating Expenses – Other operating revenue decreased $2.4 primarily due to fiscal 2013 having a one-time sale of propane inventory by Laclede Pipeline totaling $1.7. Other operating expenses decreased $0.1 primarily due to the 2014 Alagasco records natural gas distribution revenuesacquisition-related expenses discussed above being lower than the MGE acquisition expenses incurred in 2013.
Interest Charges
Interest charges during fiscal year 2014 increased $17.6 from fiscal year 2013. The increase was primarily due to the December 2012, March 2013, August 2013 and August 2014 issuance of additional long-term debt of $25.0, $100.0, $450.0 and $625.0, respectively, the June 2014 issuance of equity units totaling $143.8, offset by the early bond redemption of $80.0, 6.35% first mortgage bonds on January 6, 2014 and the October 2012 maturity of $25.0, 6.5% first mortgage bonds. The assumption of Alagasco debt contributed $1.3 to the increase in interest expense.
Average short-term interest rates were 0.5% and 0.3% for fiscal years 2014 and 2013. Average short-term borrowings were $82.3 and $34.2 for fiscal years 2014 and 2013, respectively.
Income Taxes
Income tax expense increased $14.7 in fiscal year 2014 from fiscal year 2013 primarily due to higher pre-tax income, slightly higher effective tax rates, and other minor variations.
As explained for Laclede Group above, changes to the goodwill DTA are not expected to have a significant impact on Alagasco's effective tax rate.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources are based upon our financial statements, which have been prepared in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2013 and 2012.
Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors,GAAP, which do not authorize speculative positions. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.
Taxes on Revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes, other than income taxes on the consolidated statements of income as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Taxes on revenues | $ | 25,870 |
| $ | 21,479 |
| $ | 25,268 |
|
The collection and payment of utility gross receipts tax is presented on a net basis.
D. Fair Value Measurements
The carrying values of cash and cash equivalents, accounts payable and receivable, derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the pricerequires 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). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is defined as follows:
| |
Level 1 - | Unadjusted quoted prices in active markets for identical assets or liabilities; |
| |
Level 2 - | Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date; |
| |
Level 3 - | Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints. |
Derivative commodity instruments are OTC derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties’ valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.
Pension and postretirement plan assets include mutual and comingled funds and limited partnerships. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership.
E. Income Taxes
The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.
F. Accounts Receivable and Allowance for Doubtful Accounts
Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
G. Cash and Cash Equivalents
Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.
H. Short-term Investments
All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2013 and 2012, Energen had no short-term investments.
I. Earnings Per Share (EPS)
The Company’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.
J. Stock-Based Compensation
The Company measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. The Company recognizes all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2013, 2012 and 2011, the Company recognized an excess tax benefit of $3.1 million, $0.6 million and $1.0 million, respectively, related to its stock-based compensation.
K. Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management towe make estimates and assumptionsjudgments 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 atthat are not readily apparent from other sources. Actual results may differ from these estimates. We believe the datefollowing represent the more significant items requiring the use of thejudgment and estimates in preparing our financial statements:
Regulatory Accounting – The Utilities account for their regulated operations in accordance with FASB ASC Topic 980, “Regulated Operations.” The provisions of this accounting guidance require, among other things, that financial statements andof a rate-regulated enterprise reflect the reported amountactions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses duringin time periods that are different than non-rate-regulated enterprises. When this occurs, costs are deferred as assets in the reporting period. The major estimatesbalance sheet (regulatory assets) and assumptions identified by management include, butrecorded as expenses when those amounts are not limitedreflected 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 physical quantitiesbe incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption thatthese regulatory accounting will continue as the applicable accounting standard for the Company’s regulated operations, the Company’s obligations under its employee pensionprinciples and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations, self insurance reserves andthat all regulatory assets and liabilities. Dueregulatory 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:
PGA Clause – Laclede Gas' PGA clauses allows Laclede Gas and MGE to flow through to customers, subject to a prudence review by the inherent uncertainty involved in making estimates,MoPSC, the cost of purchased gas supplies, including the costs, cost reductions, and related carrying costs associated with the Missouri Utilities' use of natural gas derivative instruments to hedge the purchase price of natural gas. The difference between actual results reported in future periods may differ fromcosts incurred and costs recovered through the estimates.
L. Employee Benefit Plans
Energen has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majorityapplication of the Company’s employeesPGA clauses are based on yearsrecorded as regulatory assets and regulatory liabilities that are recovered or refunded in a subsequent period. The PGA clauses also permit the application of servicecarrying costs to all over- or under-recoveries of gas costs, including costs and final earnings; one plan is based on yearscost reductions associated with the use of servicederivative instruments, and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefitsprovide for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.
For retirement plans and other postretirement plans, certain financial assumptions are used in determining the Company’s projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.
Measurement: The Company calculates periodic expense for defined benefit pension plans and other postretirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligationincome from off-system sales and capacity release revenues to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be providedflowed through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.
Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.
Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.
Other Significant Assumptions: The estimated weighted average rate of increase in the compensation level for pay related plans is another assumption used in calculation of the net periodic pension cost.
M. Environmental Costs
Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary O&M expenses related to environmental response costs.
2. REGULATORY MATTERS
Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term of the order is extended through September 30, 2018. The term will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to O&M expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for Securities and Exchange Commission reporting purposes.
Alagasco’s allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco��s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the years ended December 31, 2013, 2012 and 2011, Alagasco had net pre-tax reductions in revenues of $10.6 million, $6.3 million and $6.7 million, respectively, to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, a $10.3 million annual increase, $7.8 million annual increase and $13.0
million annual increase in revenues became effective December 1, 2013, 2012, and 2011, respectively. On January 1, 2014 an $8.5 million decrease in revenues became effective as a result of the December 20, 2013 RSE modification.
RSE limits the utility’s equity upon which a return was permitted to 55 percent of total capitalization, subject to certain adjustments through December 31, 2013. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment was required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference was returned to customers. ToLaclede Gas' PGA clause also authorizes it to recover costs it incurs to finance its investment in gas supplies that are purchased during the extentstorage injection season for sale during the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless Alagasco exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013, 2012 and 2011.heating season.
GSA Rider –Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.
In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco. Alagasco currently has no active derivative positions.
Revenue Recognition – The Utilities read meters and bill customers on monthly cycles. The Utilities record their 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.
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, and adjustments are recorded during the measurement period to finalize the allocation of purchase price. Laclede Gas has recorded goodwill related to the 2013 acquisition of MGE and Laclede Group also has recorded goodwill related to the 2014 acquisition of Alagasco. Alagasco has no goodwill on its balance sheet as push down accounting was not applied. Laclede Group and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. The goodwill impairment test compares the fair value of the determined reporting unit to its carrying amount, including goodwill. Laclede Group has one reporting unit, which is the Gas Utility segment, and Laclede Gas has one reporting
unit, which is the entire Laclede Gas Company. At July 1, 2015 and 2014, Laclede Group and Laclede Gas each applied a quantitative goodwill evaluation model to its reporting unit and concluded goodwill was not impaired because the fair value exceeded the carrying amount.
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 Utilities, 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 amount of net periodic pension and other postretirement benefit cost recognized in the financial statements related to the Utilities' qualified pension plans and other postretirement benefit plans is based upon allowances, as approved by the MoPSC (for Laclede Gas) and as approved by the APSC (for Alagasco). The allowances 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 Utilities' 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.
The tables below reflect the sensitivity of Laclede Group's plans to potential changes in key assumptions:
|
| | | | | | | | | | | |
| Pension Plan Benefits: | | | | | | |
| Actuarial Assumptions | | Increase/ (Decrease) | | Estimated Increase/(Decrease) to Projected Benefit Obligation | | Estimated Increase/ (Decrease) to Annual Net Pension Cost* |
| Discount Rate | | 0.25 | % | | $ | (15.9 | ) | | $ | 0.3 |
|
| | | (0.25 | )% | | 16.5 |
| | (0.4 | ) |
| Rate of Future Compensation Increase | | 0.25 | % | | 6.3 |
| | 0.7 |
|
| | | (0.25 | )% | | (6.3 | ) | | (0.8 | ) |
| Expected Return on Plan Assets | | 0.25 | % | | — |
| | (1.2 | ) |
| | | (0.25 | )% | | — |
| | 1.2 |
|
|
| | | | | | | | | | | |
| Postretirement Benefits: | | | | | | |
| Actuarial Assumptions | | Increase/ (Decrease) | | Estimated Increase/(Decrease) to Projected Postretirement Benefit Obligation | | Estimated Increase/(Decrease) to Annual Net Postretirement Benefit Cost* |
| Discount Rate | | 0.25 | % | | $ | (5.1 | ) | | $ | — |
|
| | | (0.25 | )% | | 5.3 |
| | — |
|
| Expected Return on Plan Assets | | 0.25 | % | | — |
| | (0.5 | ) |
| | | (0.25 | )% | | — |
| | 0.5 |
|
| Annual Medical Cost Trend | | 1.00 | % | | 9.2 |
| | 1.6 |
|
| | | (1.00 | )% | | (8.5 | ) | | (1.5 | ) |
* Excludes the impact of regulatory deferral mechanism. See Note 13, Pension Plans and Other Postretirement Benefits, of the Notes to Financial Statements for information regarding the regulatory treatment of these costs. 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, Laclede Gas 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. Similarly, Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC.
As part of the MGE and Alagasco acquisitions, Laclede Gas and Laclede Group had estimated the asset retirement obligation of their long-lived assets as of their respective acquisition dates. Subsequent valuations were finalized for the MGE acquisition as of September 30, 2014 and for the Alagasco acquisition as of September 30, 2015.
For further discussion of significant accounting policies, see Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements. REGULATORY AND OTHER MATTERS
Laclede Gas
On December 19, 2014, the MoPSC Staff proposed a contingent disallowance of approximately $1.0 related to Laclede Gas' recovery of its purchased gas costs in fiscal 2013. Laclede Gas opposed the disallowance and reached an agreement with the MoPSC Staff under which the proposed disallowance was withdrawn. The MoPSC approved this agreement effective August 29, 2015.
On April 17, 2015, Laclede Gas filed to increase its Infrastructure System Replacement Surcharge (ISRS) revenues by $5.5 in its Laclede Gas' eastern Missouri service territory and by $2.9 in its MGE service territory, to recover the cost of gas safety replacement investments and public improvement projects over six months from September 2014 through February 2015. Effective May 22, 2015, the MoPSC approved an increase to the ISRS tariffs in the amounts of $5.4 for Laclede Gas' eastern Missouri service territory and $2.8 for MGE's service territory.
On August 3, 2015, Laclede Gas filed applications to increase its ISRS revenues by $4.3 in its Laclede Gas eastern Missouri service territory and by $1.8 in its MGE service territory, to recover the cost of replacement investments related to gas safety and public improvement projects over six months from March through August 2015. On November 12, 2015, the MoPSC approved an incremental ISRS amount of $4.4 for Laclede Gas' eastern Missouri service territory and $1.9 for MGE, effective December 1, 2015, bringing total annualized ISRS revenue to $19.6 for Laclede Gas' eastern Missouri service territory and $6.7 for MGE's service territory.
Alagasco
On April 14, 2014, Laclede Group, along with Energen and Alagasco, filed a joint application with the APSC for approval to acquire from Energen 100% of the common stock of Alagasco. On July 22, 2014 the APSC unanimously voted to approve the Alagasco Transaction and subsequently issued a written order reflecting their decision effective July 24, 2014. This sale closed August 31, 2014.
Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. The previous allowed range of return on average common equity was 13.15% to 13.65% through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4% of prior-year revenues.
The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75% (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, Alagasco benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. The benefit for fiscal 2015 was $4.9, and $2.4 for 2014.
On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, and a regulatory liability set up for Alagasco, with the revised prospective composite depreciation rate approximating 3.1%. Refunds from such negative salvage liability will be passed back to eligible customers on a declining basis through lower tariff rates through rate year 2019 pursuant to the terms of this Negative Salvage Rebalancing (NSR) rider. The total amount refundable to customers is subject to adjustments over the remaining period for charges made to the Enhanced Stability Reserve (ESR) and other APSC-approved charges. The refunds are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements. For fiscal 2015, Alagasco refunded $13.1 to customers. For fiscal 2016, $10.8 of the remaining customer refund of $27.0 will be returned to customers. This order also required a comprehensive depreciation study to occur every 5 years. This was completed and provided to the APSC in a timely manner in fiscal 2015.
The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insuranceself-insurance costs that exceed $1$1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insuranceself-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000$0.3 and $412,500,$0.4, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000$0.4 during a rate year.
Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribeprescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine yearnine-year period and subject to APSC authorization, Alagasco anticipates recoveringexpects to be able to recover underfunded ESR balances over a five yearfive-year amortization period with an annual limitation of $660,000.$0.7. Amounts in excess of this limitation are deferred for recovery in future years.
ACCOUNTING PRONOUNCEMENTS
The excessCompany, Laclede Gas and Alagasco have evaluated or are in the process of total acquisitionevaluating the impact that recently issued accounting standards will have on their 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 Financial Statements. INFLATION
The accompanying financial statements reflect the historical costs over book value of net assetsevents and transactions, regardless of acquired municipal gas distribution systemsthe purchasing power of the dollar at the time. Due to the capital-intensive nature of the businesses of the Company, Laclede Gas and Alagasco, the most significant impact of inflation is included inon the depreciation of utility plant. Rate regulation, to which the Utilities are subject, allows recovery through its rates of only the historical cost of utility plant as depreciation. The Utilities expect to incur significant capital expenditures in future years, primarily related to the planned increased replacements of distribution plant. The Company, Laclede Gas and is being amortizedAlagasco believe that any higher costs experienced upon replacement of existing facilities will be recovered through Alagasco’s rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 13 years. At December 31, 2013 and 2012, the net unamortized acquisition adjustments were $3.2 million and $3.8 million, respectively.normal regulatory process.
FINANCIAL CONDITION
CASH FLOWS
Laclede Group
The Company’s short-term borrowing requirements typically peak during colder months when the Utilities borrow 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 Laclede Gas' use of natural gas derivative instruments), variations in the timing of collections of gas cost under Laclede Gas' PGA clause and Alagasco's GSA rider, 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.
|
| | | | | | | | |
| Cash Flow Summary | 2015 |
| | 2014 |
| | 2013 |
|
| Net cash provided by operating activities | 322.4 |
| | 122.6 |
| | 163.9 |
|
| Net cash used in investing activities | (298.7 | ) | | (1,437.6 | ) | | (1,108.3 | ) |
| Net cash (used in) provided by financing activities | (26.0 | ) | | 1,278.1 |
| | 969.9 |
|
3. LONG-TERM DEBTNet cash provided by operating activities for fiscal years 2015, 2014 and 2013 was $322.4, $122.6 and $163.9, respectively. The increase from 2014 to 2015 was primarily due to the incremental change for Alagasco reflecting the inclusion of a full year in 2015, which provided $96.3 of cash from operating activities. The remaining increase was driven by the timing of collections of gas costs under the PGA and changes in natural gas inventory values. The decrease in net cash provided by operating activities in 2014 as compared to 2013 is primarily attributable to delayed customer billings increases reflecting the inclusion of MGE's operations and the timing of collections of gas cost under Laclede Gas' PGA clauses, accelerated build of natural gas stored underground, the cash paid on interest rate swaps and other working capital changes. These uses of cash were only partly offset by higher net income and higher depreciation, amortization and accretion reflecting the inclusion of MGE and colder weather.
Net cash used in investing activities for fiscal years 2015, 2014 and 2013 was $298.7, $1,437.6 and $1,108.3, respectively. The increased use of cash, excluding $1,305.2 for the 2014 acquisition of Alagasco, was driven by higher capital expenditures of approximately $118.8, which includes the incremental increase of $80.2 for Alagasco and an increase of $35.6 at Laclede Gas. Additionally, the current year included a payment for the final reconciliation associated with the Alagasco acquisition, whereas the prior year included the cash receipts associated with the MGE acquisition and the sale of New England Gas Company (NEG) to Algonquin Power & Utility Corp. (APUC). The increase in net cash used in 2014 as compared to 2013 is attributable to $1,305.2 for the acquisition of Alagasco, offset partially by cash receipts for the final reconciliation amount for the MGE acquisition and for the sale of NEG to APUC. Net cash used in 2013 includes $975.0 for the acquisition of MGE. The remaining net cash used in investing activities in 2014 primarily reflected the increase in capital expenditures related to distribution plant and information technology investments. Laclede Group estimates its capital expenditures for fiscal 2016 will be approximately $315, comprised of $220 for Laclede Gas, $90 for Alagasco, and $5 for non-regulated businesses.
Net cash used in financing activities for fiscal year 2015 was $26.0, while the net cash provided by financing activities for 2014 and 2013 was $1,278.1 and $969.9, respectively. Excluding the proceeds from the prior year common stock issuance of 10.350 million shares of $457.1 and the prior year issuance of long-term debt of $768.8 for the acquisition of Alagasco, the difference between net cash used in 2015 and net cash provided in 2014 was $78.2. This change primarily reflects the decrease in short-term borrowing and the increase in dividends paid, partially offset by the lower repayment of long term-debt. The increase in net cash provided by financing activities in fiscal year 2014 from fiscal year 2013 primarily reflects the issuance of common stock, equity units, and long-term debt related to the Alagasco acquisition in 2014, exceeding the common stock and long-term debt issuance associated with the MGE acquisition in 2013.
LIQUIDITY AND NOTES PAYABLECAPITAL RESOURCES
Cash and Cash Equivalents
Laclede Group had no temporary cash investments as of September 30, 2015.
Laclede Gas had no temporary cash investments as of September 30, 2015, but the balance of its short-term investments ranged between $0 and $10.0 during fiscal 2015 and ranged between $0.0 and $983.5 during fiscal year 2014.
Alagasco had no short-term investments as of September 30, 2015. Its bank deposits were used to support working capital needs of the business.
Short-term Debt
The Utilities' short-term borrowings requirements typically peak during the colder months, while the Company's needs are less seasonal. 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, 2015, Laclede Gas had a syndicated line of credit in place of $450.0 from nine banks. The largest portion provided by a single bank under the line is 15.6%. The Laclede Gas 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 50% of total capitalization on September 30, 2015.
At September 30, 2015, Alagasco had a $150.0 syndicated line of credit with twelve banks. The largest portion provided by a single bank is 10%. The line of credit, which matures on September 2, 2019, has a covenant limiting total debt to 70% of Alagasco’s total capitalization. As defined in the line of credit, this ratio stood at 24% on September 30, 2015. Borrowing under Alagasco's line during fiscal year 2015 ranged from $0.0 to $69.5, with a balance at September 30, 2015 of $31.0. Borrowings under Alagasco's line for the month of September of fiscal 2014 ranged from $9.0 to $16.0, with a balance at September 30, 2014 of $16.0.
At September 30, 2015, the Laclede Group parent company had a $150.0 syndicated line of credit from nine banks, with the largest portion provided by a single bank being 15.6%. 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 58% on September 30, 2015. Laclede Group’s line may be used to provide for the funding needs of various
subsidiaries. Borrowings under Laclede Group’s line during fiscal year 2015 ranged from $32.5 to $80.0, with the balance at September 30, 2015 at $74.0. Borrowings under this line of credit during fiscal year 2014 ranged from $0.0 to $40.0, with the balance at September 30, 2014 of $32.5.
On September 3, 2014, Laclede Group and Laclede Gas entered into extension agreements to extend the maturity dates on their loan agreements for a period of one year from September 3, 2018 to September 3, 2019.
Information about Laclede Group’s consolidated short-term borrowings during the twelve months ended September 30, 2015 and 2014 and as of September 30, 2015 and 2014 is presented below:
|
| | | | |
| | Laclede Gas Commercial Paper Borrowings | Laclede Group*** Bank Line Borrowings | Alagasco Bank Line Borrowings * | Total Short-Term Borrowings ** |
| Year Ended September 30, 2015 | | | | |
| Weighted average borrowings outstanding | $212.7 | $65.6 | $22.3 | $300.6 |
| Weighted average interest rate | 0.4% | 1.4% | 1.1% | 0.7% |
| Range of borrowings outstanding | $ 102.1 - $341.0 | $32.5 - $80.0 | $0 - $69.5 | $180.1 - $488.5 |
| As of September 30, 2015 | | | | |
| Borrowings outstanding at end of period | $233.0 | $74.0 | $31.0 | $338.0 |
| Weighted average interest rate | 0.5% | 1.5% | 1.2% | 0.8% |
| Year Ended September 30, 2014 | | | | |
| Weighted average borrowings outstanding | $77.6 | $3.6 | $13.2 | $82.3 |
| Weighted average interest rate | 0.3% | 1.4% | 1.2% | 0.5% |
| Range of borrowings outstanding | $0 – $244.5 | $0 – $40.0 | $9.0 – $16.0 | $0 – $300.5 |
| As of September 30, 2014 | | | | |
| Borrowings outstanding at end of period | $238.6 | $32.5 | $16.0 | $287.1 |
| Weighted average interest rate | 0.3% | 1.4% | 1.2% | 0.5% |
* Weighted average borrowings for Alagasco for the year ended September 30, 2014 represents Laclede Group's ownership period of one month. The one-month average approximates the Alagasco daily outstanding balance for the fiscal year ended September 30, 2014.
** Represents twelve-month weighted average for Laclede Group***, Laclede Gas, and Alagasco.
*** The Laclede Group, Inc., excluding its wholly owned subsidiaries.
Based on average short-term borrowings for the year ended September 30, 2015, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $3.0 on an annual basis, portions of which may be offset through the application of PGA carrying costs.
Long-term Debt and Equity
Laclede Group
At September 30, 2015, including the current portion but excluding unamortized discounts and net hedging gains, Laclede Group had fixed-rate long-term debt consistedtotaling $1,603.8 and floating rate debt totaling $250.0, of which $810.0 was issued by Laclede Gas and $250.0 was issued by Alagasco. With the exception of the following:
|
| | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| | | |
| Energen Corporation: | | |
| Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028 | $ | 154,000 |
| $ | 154,000 |
|
| 5% Notes | — |
| 50,000 |
|
| 4.625% Notes, due September 1, 2021 | 400,000 |
| 400,000 |
|
| Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017 | 600,000 |
| — |
|
| Senior Term Loans, (floating rate interest LIBOR plus 1.375%) | — |
| 300,000 |
|
| Alabama Gas Corporation: | | |
| 5.20% Notes, due January 15, 2020 | 40,000 |
| 40,000 |
|
| 5.70% Notes, due January 15, 2035 | 34,923 |
| 35,028 |
|
| 5.368% Notes, due December 1, 2015 | 80,000 |
| 80,000 |
|
| 5.90% Notes, due January 15, 2037 | 45,000 |
| 45,000 |
|
| 3.86% Notes, due December 21, 2021 | 50,000 |
| 50,000 |
|
| Total | 1,403,923 |
| 1,154,028 |
|
| Less amounts due within one year | 60,000 |
| 50,000 |
|
| Less unamortized debt discount | 459 |
| 500 |
|
| Total | $ | 1,343,464 |
| $ | 1,103,528 |
|
The aggregate maturities of Energen’s long-term debt for the next five years are as follows:
|
| | | | |
Years ending December 31, (in thousands) |
| 2014 | 2015 | 2016 | 2017 | 2018 |
| $60,000 | $140,000 | $60,000 | $439,000 | — |
The aggregate maturities of Alagasco’s long-term debt for the next five years are as follows:
|
| | | | |
Years ending December 31, (in thousands) |
| 2014 | 2015 | 2016 | 2017 | 2018 |
| — | $80,000 | — | — | — |
In December 2013, the Company$250.0 floating rate senior notes issued $600 millionby Laclede Group in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31,August 2014, through December 17, 2017. The Company used the long-term debt proceedsissues are fixed-rate and are subject to repaychanges 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 Senior Term LoansCompany were to reacquire any of $300 million issuedthese issues in November 2011the open market prior to maturity. Under GAAP applicable to the Utilities' 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 $1,710.0 senior long-term debt, $25.0 has no call options, $710.0 has make-whole call options, $725.0 are callable at par one to repay short-term obligationssix months prior to maturity and $250.0 are callable at par one year prior to maturity. The remainder of the Company's long-term debt is $143.8 of junior subordinated notes associated with the equity units. None of the debt has any put options
Laclede Group has a shelf registration statement on Form S-3 on file with the SEC for the issuance and sale of up to 168,698 shares of its common stock under its syndicated credit facility.Dividend Reinvestment and Direct Stock Purchase Plan. There were 129,413 and 123,889 shares at September 30, 2015 and November 24, 2015, respectively, remaining available for issuance under its Form S-3. Laclede Group also has a shelf registration statement on Form S-3 on file with the SEC for the issuance of equity and debt securities.
Consolidated capitalization at September 30, 2015 consisted of 47.0% of Laclede Group common stock equity and 53.0% of long-term debt, compared to 44.9% of Laclede Group common stock equity and 55.1% of long-term debt at September 30, 2014.
Laclede Gas
At December 31, 2013,Of Laclede Gas' $810.0 in long-term debt, $25.0 has no call option, $435.0 has make-whole call options, and $350.0 are callable at par one to six months prior to maturity. None of the Companydebt has any put options.
Laclede Gas had interest rate swapauthority from the MoPSC 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, with a notional of $200 million. The interest rate swaps exchange a variable interest rateall for a fixed interest ratetotal of 2.6675 percent. The fair valueup to $518.0. This authorization was effective through June 30, 2015. On April 15, 2015, Laclede Gas filed with the MoPSC for a new financing authorization. On June 24, 2015 the MoPSC granted an extension of the Company’s interest rate swap wascurrent authorization until the pending application is resolved. During the year ended September 30, 2015, Laclede Gas issued no securities under this authorization. As of November 24, 2015, $369.7 remains available under this authorization. Laclede Gas has a $1.8 millionshelf registration on Form S-3 on file with the SEC for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires August 6, 2016. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations.
Laclede Gas capitalization at September 30, 2015 consisted of 56.2% of common stock equity and 43.8% of long-term debt compared to 55.5% of common stock equity and 44.5% of long-term debt at September 30, 2014.
Alagasco
All of Alagasco's $250.0 long-term debt, including the current portion of long-term debt, has a $3.3 million liability at December 31, 2013 and 2012, respectively, and is classified as a Level 2 fair value liability. The fair valuemake-whole call option. None of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.debt has any put options.
TheAlagasco has no standing authority to issue long-term debt and short-term debt agreements of Energenmust petition the APSC for planned issuances. On November 3, 2014, Alagasco received authorization and Alagasco contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens.
Although none of the agreements have covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of the Company’s debt is unsecured.
Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.
Energen and Alagasco Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Borrowings under these credit facilities are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under these credit facilities are classified as short term obligations in the accompanying consolidated financial statements. Alagasco has been authorized byapproval from the APSC to borrow up$35.0 for the purposes of redeeming, without penalty, $34.8 in existing long-term, callable debt financed at 5.7%. Pursuant to $200 milliona call notice issued on December 14, 2014, Alagasco redeemed $34.8 of debt effective January 15, 2015. On February 3, 2015, Alagasco received authorization and approval from the APSC to borrow $80.0 for the purpose of refinancing $80.0 of existing debt scheduled to mature on December 1, 2015. Pursuant to these authorizations, Alagasco entered into a master note purchase agreement on June 5, 2015 with certain institutional purchasers pursuant to which Alagasco committed to issue $115.0 unsecured notes in the private placement market: $35.0 at any one time undera rate of 3.21% for 10 years issued on September 15, 2015, and $80.0 at a rate of 4.31% for 30 years settling December 1, 2015. As of September 30, 2015, the short-termcurrent portion of long-term debt for Alagasco consisted of this $80.0 fixed-rate note maturing on December 1, 2015.
Alagasco's capitalization at September 30, 2015 consisted of 83.7% of common stock equity and 16.3% of long-term debt compared to 77.3% of common stock equity and 22.7% of long-term debt at September 30, 2014.
The Company’s, Laclede Gas' and Alagasco's access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit facilities.
Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenantsrating of the Energenentity that is accessing the capital markets. The credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent asratings of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.
Similarly, the financial covenants of theCompany, Laclede Gas and Alagasco credit facility limit Alagascoremain at investment grade, but are subject to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default.
Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.
Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted credit facility, if any, depending on the nature of the event of default will automatically, or may upon noticereview and change by the administrative agent orrating agencies.
It is management’s view that the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. EnergenCompany, Laclede Gas, and Alagasco were in compliancehave 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, interest payments of long-term debt, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.
CONTRACTUAL OBLIGATIONS
As of September 30, 2015, Laclede Group had contractual obligations with the terms of their respective credit facilitiespayments due as of December 31, 2013.
The following is a summary of information relating to the credit facilities:summarized below:
|
| | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| Energen outstanding | $ | 489,000 |
| $ | 566,000 |
|
| Alagasco outstanding | 50,000 |
| 77,000 |
|
| Notes payable to banks | 539,000 |
| 643,000 |
|
| Available for borrowings | 811,000 |
| 707,000 |
|
| Total | $ | 1,350,000 |
| $ | 1,350,000 |
|
| Energen maximum amount outstanding at any month-end | $ | 901,000 |
| $ | 643,000 |
|
| Energen average daily amount outstanding | $ | 804,895 |
| $ | 331,068 |
|
| Energen weighted average interest rates based on: | | |
| Average daily amount outstanding | 1.38 | % | 1.82 | % |
| Amount outstanding at year-end | 1.32 | % | 1.35 | % |
| Alagasco maximum amount outstanding at any month-end | $ | 75,000 |
| $ | 77,000 |
|
| Alagasco average daily amount outstanding | $ | 35,027 |
| $ | 21,254 |
|
| Alagasco weighted average interest rates based on: | | |
| Average daily amount outstanding | 1.12 | % | 1.44 | % |
| Amount outstanding at year-end | 1.26 | % | 1.11 | % |
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payments due by period |
| Contractual Obligations | Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | More than 5 Years |
| Principal Payments on Long-Term Debt | $ | 1,853.8 |
| | $ | 80.0 |
| | $ | 350.0 |
| | $ | 215.0 |
| | $ | 1,208.8 |
|
| Interest Payments on Long-Term Debt (a) | 977.1 |
| | 72.5 |
| | 127.9 |
| | 111.0 |
| | 665.7 |
|
| Operating Leases (b) | 101.5 |
| | 11.0 |
| | 18.3 |
| | 12.7 |
| | 59.5 |
|
| Purchase Obligations – Natural Gas (c) | 1,369.3 |
| | 587.7 |
| | 565.7 |
| | 152.6 |
| | 63.3 |
|
| Purchase Obligations – Other (d) | 102.7 |
| | 47.2 |
| | 35.1 |
| | 19.9 |
| | 0.5 |
|
| Other Long-Term Liabilities | 122.7 |
| | 13.3 |
| | 26.8 |
| | 27.8 |
| | 54.8 |
|
| Total (e) | $ | 4,527.1 |
| | $ | 811.7 |
| | $ | 1,123.8 |
| | $ | 539.0 |
| | $ | 2,052.6 |
|
| |
| (a) | Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at September 30, 2015 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 6, Long-Term Debt, of the Notes to Financial Statements. Does not reflect Laclede Group's ability to defer quarterly interest and contract adjustment payments related to its equity units, as discussed in Note 5, Stockholders' Equity. |
The principal and interest payments on long-term debt included in the table above do not include obligations associated with Alagasco's commitment to issue $80 million of 4.31% 30-year unsecured notes in private placements scheduled for settlement in December 2015.
| |
| (b) | 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. |
| |
| (c) | 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. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using September 30, 2015 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. Alagasco recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its GSA gas rider clause, subject to prudence review by the APSC. Variations in the timing of collections of gas costs from customers may affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season. |
| |
| (d) | These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations. |
| |
| (e) | Long-term liabilities associated with unrecognized tax benefits, totaling $7.2, 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 contribute $26.0 to its qualified, trusteed pension plans and $0.5 to its non-qualified pension plans during fiscal year 2016. With regard to the postretirement benefits, the Company anticipates it will contribute $14.3 to the qualified trusts and $0.4 directly to participants from Laclede Gas funds during fiscal year 2016. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 13, Pension Plans and Other Postretirement Benefits, of the Notes to Financial Statements. |
MARKET RISK
Commodity Price Risk
Gas Utility
The Utilities' 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 and Alagasco's GSA rider. The PGA clauses and GSA rider allows the Utilities to flow through to customers, subject to prudence review by the MoPSC and APSC, the cost of purchased gas supplies, as well as gas inventory carrying costs. Laclede Gas is allowed the flexibility to make up to three discretionary PGA
Energen’s total interest expense was $69.2 million, $65.5 millionchanges during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. Laclede Gas is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and $44.8 millionregional supply diversity. The Utilities also have risk management policies that allow for the years ended December 31, 2013, 2012purchase 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 2011, respectively. Energen’s total interest expense forcost reduction, including carrying costs, associated with the years ended December 31, 2013 and 2012 included capitalized interest expenseuse of $0.2 million and $0.5 million. Total interest expense for Alagasco was $15.6 million, $16.3 million and $14.7 million fornatural gas derivative instruments are allowed to be passed on to customers through the years ended December 31, 2013, 2012 and 2011, respectively. At December 31, 2013, Energen and Alagasco paid commitment fees on the unused portion of available credit facilities ranging from 15 to 25 basis points per annum.
4. INCOME TAXES
The components of Energen’s income taxes consistedoperation of the following:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Taxes estimated to be payable currently: | | | |
| Federal | $ | 23,342 |
| $ | 16,295 |
| $ | 11,595 |
|
| State | 2,516 |
| 3,125 |
| 5,065 |
|
| Total current | 25,858 |
| 19,420 |
| 16,660 |
|
| Taxes deferred: | | | |
| Federal | 85,950 |
| 119,053 |
| 125,622 |
|
| State | (2,300 | ) | 5,346 |
| 3,419 |
|
| Total deferred | 83,650 |
| 124,399 |
| 129,041 |
|
| Total income tax expense | $ | 109,508 |
| $ | 143,819 |
| $ | 145,701 |
|
The componentsPGA clauses or GSA rider. As of Energen’s income taxes consisted ofSeptember 30, 2015, Laclede Gas had active derivative positions, but Alagasco did not have any open derivative positions. Accordingly, the following:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Income tax expense from continuing operations | $ | 105,282 |
| $ | 144,534 |
| $ | 126,322 |
|
| Income tax expense (benefit) from discontinued operations | 2,215 |
| (715 | ) | 19,379 |
|
| Income tax expense from gain on disposal of discontinued operations | 2,011 |
| — |
| — |
|
| Total income tax expense | $ | 109,508 |
| $ | 143,819 |
| $ | 145,701 |
|
The components of Alagasco’s income taxes consisted of the following:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Taxes estimated to be payable currently: | | | |
| Federal | $ | 17,495 |
| $ | 18,227 |
| $ | (1,280 | ) |
| State | 2,192 |
| 739 |
| (108 | ) |
| Total current | 19,687 |
| 18,966 |
| (1,388 | ) |
| Taxes deferred: | | | |
| Federal | 13,252 |
| 9,066 |
| 24,938 |
|
| State | 1,748 |
| 2,212 |
| 3,120 |
|
| Total deferred | 15,000 |
| 11,278 |
| 28,058 |
|
| Total income tax expense | $ | 34,687 |
| $ | 30,244 |
| $ | 26,670 |
|
Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:
|
| | | | | | | | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| | Current | Noncurrent | Current | Noncurrent |
| Deferred tax assets: | | | | |
| Unbilled and deferred revenue | $ | 12,547 |
| $ | — |
| $ | 10,137 |
| $ | — |
|
| Allowance for doubtful accounts | 2,066 |
| — |
| 2,408 |
| — |
|
| Insurance and other accruals | 4,851 |
| — |
| 3,821 |
| — |
|
| Compensation accruals | 15,405 |
| — |
| 13,116 |
| — |
|
| Inventories | 1,260 |
| — |
| 1,664 |
| — |
|
| Other comprehensive income | — |
| 15,350 |
| — |
| 19,158 |
|
| Gas supply adjustment related accruals | 698 |
| — |
| 969 |
| — |
|
| Derivative instruments | 10,769 |
| — |
| — |
| — |
|
| State net operating losses and other carryforwards | — |
| 4,577 |
| — |
| 3,577 |
|
| Other | 1,219 |
| 1 |
| 1,340 |
| 25 |
|
| Total deferred tax assets | 48,815 |
| 19,928 |
| 33,455 |
| 22,760 |
|
| Valuation allowance | (299 | ) | (2,674 | ) | (268 | ) | (2,793 | ) |
| Total deferred tax assets | 48,516 |
| 17,254 |
| 33,187 |
| 19,967 |
|
| Deferred tax liabilities: | | | | |
| Depreciation and basis differences | — |
| 1,008,026 |
| — |
| 898,625 |
|
| Pension and other costs | — |
| 15,379 |
| — |
| 20,143 |
|
| Derivative instruments | — |
| 2,048 |
| 4,272 |
| 3,162 |
|
| Other comprehensive income | 5,540 |
| — |
| 18,133 |
| — |
|
| Other | 1,677 |
| 5,046 |
| 2,262 |
| 3,638 |
|
| Total deferred tax liabilities | 7,217 |
| 1,030,499 |
| 24,667 |
| 925,568 |
|
| Net deferred tax assets (liabilities) | $ | 41,299 |
| $ | (1,013,245 | ) | $ | 8,520 |
| $ | (905,601 | ) |
Temporary differences and carryforwards which gave rise to Alagasco’s deferred tax assets and liabilities were as follows:
|
| | | | | | | | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| | Current | Noncurrent | Current | Noncurrent |
| Deferred tax assets: | | | | |
| Unbilled and deferred revenue | $ | 12,547 |
| $ | — |
| $ | 10,137 |
| $ | — |
|
| Allowance for doubtful accounts | 1,815 |
| — |
| 2,155 |
| — |
|
| Insurance accruals | 1,769 |
| — |
| 1,856 |
| — |
|
| Compensation accruals | 2,480 |
| — |
| 2,645 |
| — |
|
| Inventories | 1,260 |
| — |
| 1,664 |
| — |
|
| Gas supply adjustment related accruals | 698 |
| — |
| 969 |
| — |
|
| Other | 984 |
| 1 |
| 774 |
| 2 |
|
| Total deferred tax assets | 21,553 |
| 1 |
| 20,200 |
| 2 |
|
| Deferred tax liabilities: | | | | |
| Depreciation and basis differences | — |
| 186,601 |
| — |
| 167,329 |
|
| Pension and other costs | — |
| 19,031 |
| — |
| 22,054 |
|
| Other | 1,504 |
| — |
| 1,401 |
| — |
|
| Total deferred tax liabilities | 1,504 |
| 205,632 |
| 1,401 |
| 189,383 |
|
| Net deferred tax assets (liabilities) | $ | 20,049 |
| $ | (205,631 | ) | $ | 18,799 |
| $ | (189,381 | ) |
The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a noncurrent deferred tax asset of $1.6 million relating to Energen Resources’ $35.0 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income to fully realize this benefit. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.0 million arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely thanUtilities do not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.
In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $37.0 million and would result in an additional deferred tax liability of $14.0 million.
Total income tax expense from continuing operations for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent toexpect any adverse earnings before taxes as illustrated below:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Income tax expense at statutory federal income tax rate | $ | 104,450 |
| $ | 139,914 |
| $ | 122,719 |
|
| Increase (decrease) resulting from: | | | |
| State income taxes, net of federal income tax benefit | 3,799 |
| 4,755 |
| 8,341 |
|
| Impact of state law changes | (1,966 | ) | — |
| (2,059 | ) |
| Qualified Section 199 production activities deduction | — |
| (61 | ) | (495 | ) |
| 401(k) stock dividend deduction | (449 | ) | (514 | ) | (532 | ) |
| Other, net | (552 | ) | 440 |
| (1,652 | ) |
| Total income tax expense | $ | 105,282 |
| $ | 144,534 |
| $ | 126,322 |
|
| Effective income tax rate (%) | 35.28 |
| 36.16 |
| 36.03 |
|
Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Income tax expense at statutory federal income tax rate | $ | 32,230 |
| $ | 27,876 |
| $ | 25,645 |
|
| Increase (decrease) resulting from: | | | |
| State income taxes, net of federal income tax benefit | 2,588 |
| 2,238 |
| 2,059 |
|
| Reversal of tax reserves from audit settlements, net | — |
| — |
| (1,365 | ) |
| Other, net | (131 | ) | 130 |
| 331 |
|
| Total income tax expense | $ | 34,687 |
| $ | 30,244 |
| $ | 26,670 |
|
| Effective income tax rate (%) | 37.67 |
| 37.97 |
| 36.40 |
|
A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:
|
| | | |
| (in thousands) | |
| Balance as of December 31, 2010 | $ | 24,590 |
|
| Additions based on tax positions related to the current year | 3,644 |
|
| Additions for tax positions of prior years | 2,324 |
|
| Reductions for tax positions of prior years | (39 | ) |
| Lapse of statute of limitations | (1,482 | ) |
| Settlements | (18,444 | ) |
| Balance as of December 31, 2011 | 10,593 |
|
| Additions based on tax positions related to the current year | 3,731 |
|
| Additions for tax positions of prior years | 269 |
|
| Reductions for tax positions of prior years | (446 | ) |
| Lapse of statute of limitations | (1,592 | ) |
| Balance as of December 31, 2012 | 12,555 |
|
| Additions based on tax positions related to the current year | 4,546 |
|
| Additions for tax positions of prior years | 366 |
|
| Reductions for tax positions of prior years | (46 | ) |
| Lapse of statute of limitations | (1,435 | ) |
| Balance as of December 31, 2013 | $ | 15,986 |
|
The reduction for settlements in 2011 are primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property that was in dispute under an Internal Revenue Service (IRS) examination of the Company’s 2007-2008 federal consolidated income tax returns. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.
During 2011, the Company had a gross addition of $5.9 million and recognized in its effective income tax rate $2.9 million of income tax expense for additional unrecognized tax benefit liabilities. These liabilities were partially offset by a $1.5 million benefit for the release of the unrecognized income tax benefit liability due to the Company’s settlement with the IRS discussed above.
The amount of unrecognized tax benefits at December 31, 2013 that would favorably impact the Company’s effective tax rate, if recognized, is $6.9 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013, 2012, and 2011, the Company recognized approximately $15,000 of expense, $25,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. The Company had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012, respectively.
A reconciliation of Alagasco’s beginning and ending amount of unrecognized tax benefits is as follows:
|
| | | |
| (in thousands) | |
| Balance as of December 31, 2010 | $ | 18,941 |
|
| Additions based on tax positions related to the current year | 13 |
|
| Additions for tax positions of prior years | 1 |
|
| Reductions for tax positions of prior years (lapse of statute of limitations) | (409 | ) |
| Settlements | (18,444 | ) |
| Balance as of December 31, 2011 | 102 |
|
| Additions based on tax positions related to the current year | 62 |
|
| Additions for tax positions of prior years | 201 |
|
| Reductions for tax positions of prior years (lapse of statute of limitations) | (58 | ) |
| Balance as of December 31, 2012 | 307 |
|
| Reductions for tax positions of prior years (lapse of statute of limitations) | (31 | ) |
| Balance as of December 31, 2013 | $ | 276 |
|
The reduction for settlements in 2011 are primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property discussed above. None of Alagasco’s unrecognized tax benefits at December 31, 2013 would impact the Company’s effective tax rate, if recognized. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013, 2012, and 2011, Alagasco recognized approximately $4,000 of expense, $1,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $8,000 and $4,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012, respectively.
The Company and Alagasco’s tax returns for years 2010-2012 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of
various auditsthe 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. For more information about the Utilities' natural gas derivative instruments, see Note 10, Derivative Instruments and the expirationHedging Activities, of the statuteNotes to Financial Statements.Gas Marketing
In the course of limitations. Althoughits 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 timingpotential to impact earnings and outcomecash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of tax examinationsa 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 highly uncertain,currently managed either by closely matching the Company doesoffsetting 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, 2015 and 2014, LER’s unmatched fixed-price positions were not expectmaterial 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 changeNYMEX 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 unrecognized tax benefit withinvalue of the next 12 months would have a material impact tohedged forecasted transactions. Information about the financial statements.
5. EMPLOYEE BENEFIT PLANSfair values of LER’s exchange-traded/cleared natural gas derivative instruments is presented below:
Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:
|
| | | | | | | | | | | |
| | Derivative Fair Values | | Cash Margin | | Derivatives and Cash Margin |
| Net balance of derivative assets at September 30, 2014 | $ | 0.4 |
| | $ | 2.1 |
| | $ | 2.5 |
|
| Changes in fair value | 4.9 |
| | — |
| | 4.9 |
|
| Settlements/purchases - net | 0.2 |
| | — |
| | 0.2 |
|
| Changes in cash margin | — |
| | (3.7 | ) | | (3.7 | ) |
| Net balance of derivative assets at September 30, 2015 | $ | 5.5 |
| | $ | (1.6 | ) | | $ | 3.9 |
|
|
| | | | | | | | | | | | | | |
| As of December 31, (in thousands) | 2013 | | 2012 | 2013 | | 2012 |
| | Pension | Postretirement Benefits |
| Accumulated benefit obligation | $ | 253,030 |
| | $ | 269,101 |
| | | |
| Benefit obligation: | | | | | | |
| Balance at beginning of period | $ | 323,540 |
| | $ | 250,619 |
| $ | 85,785 |
| | $ | 88,064 |
|
| Service cost | 14,173 |
| | 10,527 |
| 1,694 |
| | 1,853 |
|
| Interest cost | 11,239 |
| | 10,801 |
| 3,504 |
| | 4,248 |
|
| Actuarial (gain) loss | (28,339 | ) | | 65,048 |
| (21,681 | ) | | (5,413 | ) |
| Curtailment gain | (4,223 | ) | | — |
| (1,255 | ) | | — |
|
| Retiree drug subsidy program | — |
| | — |
| 261 |
| | 360 |
|
| Benefits paid | (23,036 | ) | | (13,455 | ) | (4,726 | ) | | (3,327 | ) |
| Balance at end of period | $ | 293,354 |
| | $ | 323,540 |
| $ | 63,582 |
| | $ | 85,785 |
|
| Plan assets: | | | | | | |
| Fair value of plan assets at beginning of period | $ | 209,424 |
| | $ | 195,659 |
| $ | 87,189 |
| | $ | 78,121 |
|
| Actual return on plan assets | 22,977 |
| | 24,841 |
| 14,892 |
| | 8,778 |
|
| Employer contributions | 10,169 |
| | 2,379 |
| 1,578 |
| | 3,617 |
|
| Benefits paid | (23,036 | ) | | (13,455 | ) | (4,726 | ) | | (3,327 | ) |
| Fair value of plan assets at end of period | $ | 219,534 |
| | $ | 209,424 |
| $ | 98,933 |
| | $ | 87,189 |
|
| | | | | | | |
| Funded status of plans | $ | (73,820 | ) | | $ | (114,116 | ) | $ | 35,351 |
| | $ | 1,404 |
|
| | | | | | | |
| Noncurrent assets | $ | — |
| | $ | — |
| $ | 35,351 |
| | $ | 1,404 |
|
| Current liabilities | (6,145 | ) | | (3,834 | ) | — |
| | — |
|
| Noncurrent liabilities | (67,675 | ) | | (110,282 | ) | — |
| | — |
|
| Net asset (liability) recognized | $ | (73,820 | ) | | $ | (114,116 | ) | $ | 35,351 |
| | $ | 1,404 |
|
| Amounts recognized to accumulated other comprehensive income: | | | | | |
| Prior service costs, net of taxes | $ | 323 |
| | $ | 528 |
| $ | — |
| | $ | — |
|
| Net actuarial (gain) loss, net of taxes | 37,479 |
| | 52,472 |
| (5,584 | ) | | (715 | ) |
| Transition obligation, net of taxes | — |
| | — |
| 27 |
| | 222 |
|
| Total accumulated other comprehensive income (loss) | $ | 37,802 |
| | $ | 53,000 |
| $ | (5,557 | ) | | $ | (493 | ) |
|
| | | | | | | | | | | | | | | |
| | As of September 30, 2015 |
| Maturity by Fiscal Year | Total | | 2016 | | 2017 | | 2018 |
| Fair values of exchange-traded/cleared natural gas derivatives - net | $ | 3.0 |
| | $ | 3.4 |
| | $ | (0.4 | ) | | $ | — |
|
| Fair values of basis swaps - net | 2.5 |
| | 1.5 |
| | 0.9 |
| | 0.1 |
|
| | | | | | | | |
| Position volumes: | | | | | | | |
| MMBtu – net (short) long futures/swap/option positions | (18.5 | ) | | (21.1 | ) | | 2.2 |
| | 0.4 |
|
| MMBtu - net (short) long basis swap positions | (8.9 | ) | | (4.6 | ) | | (3.8 | ) | | (0.5 | ) |
Alagasco recognized a regulatory assetCertain of $58.2 million and $89.5 millionLER’s physical natural gas derivative contracts are designated as of December 31, 2013 and 2012, respectively,normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the portion ofcontract in the pension plan obligationperiod 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 be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $26.2 million and $1.2 million as of December 31, 2013 and 2012, respectively, for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods.
settlement.
Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:
|
| | | | | | | | | | | | |
| | December 31, 2013 |
| (in thousands) | Level 1 | Level 2 | Level 3 | Total |
| Insurance contracts | $ | — |
| $ | 14,805 |
| $ | — |
| $ | 14,805 |
|
| United States equities | 5,579 |
| — |
| — |
| 5,579 |
|
| Global equities | 2,338 |
| — |
| — |
| 2,338 |
|
| Fixed income | — |
| 11,039 |
| — |
| 11,039 |
|
| Total | $ | 7,917 |
| $ | 25,844 |
| $ | — |
| $ | 33,761 |
|
|
| | | | | | | | | | | | |
| | December 31, 2012 |
| (in thousands) | Level 1 | Level 2 | Level 3 | Total |
| Insurance contracts | $ | — |
| $ | 7,399 |
| $ | 5,600 |
| $ | 12,999 |
|
| United States equities | 4,741 |
| — |
| — |
| 4,741 |
|
| Global equities | 2,109 |
| — |
| — |
| 2,109 |
|
| Fixed income | — |
| 10,219 |
| — |
| 10,219 |
|
| Total | $ | 6,850 |
| $ | 17,618 |
| $ | 5,600 |
| $ | 30,068 |
|
While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in deferred charges and other in the consolidated balance sheets.
The followingBelow is a reconciliation of insurancethe beginning and ending balances for physical natural gas contracts in Level 3accounted for as derivatives, none of the fair value hierarchy:
which will settle beyond fiscal year 2016:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Balance at beginning of period | $ | 5,600 |
| $ | 5,332 |
| $ | 5,069 |
|
| Unrealized gains relating to instruments held at the reporting date | — |
| 268 |
| 263 |
|
| Transfer out of Level 3 | (5,600 | ) | — |
| — |
|
| Balance at end of period | $ | — |
| $ | 5,600 |
| $ | 5,332 |
|
|
| | | |
| Net balance of derivative assets at September 30, 2014 | $ | 2.1 |
|
| Changes in fair value | 1.4 |
|
| Settlements | (4.0 | ) |
| Net balance of derivative assets at September 30, 2015 | $ | (0.5 | ) |
ChangesFor further details related to LER’s derivatives and hedging activities, see Note 10, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements.Counterparty Credit Risk
LER has concentrations of counterparty credit risk in Fair Value Levels: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 11, Concentrations of Credit Risk, of the Notes to Financial Statements. Interest Rate Risk
The availabilityCompany 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 2015, an increase of observable market data is monitored100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $3.0 on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At September 30, 2015, Laclede Group had $250.0 of variable rate long-term debt. An increase of 100 basis points in the underlying average interest rate for the variable long-term note would have caused an increase in interest expense of approximately $2.5 on an annual basis. At September 30, 2015, Laclede Group had fixed-rate long-term debt (including current portion) totaling $1,603.8. Laclede Gas had fixed-rate long-term debt totaling $810.0 and Alagasco has fixed rate long-term debt (including current portion) of $250.0, which are both included with Laclede Group total long-term debt (including current). While these long-term debt issues are fixed-rate, they are subject to assess the appropriate classification for financial instruments within thechanges in fair value hierarchy. Changesas market interest rates change. However, increases or decreases in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the year ended December 31, 2013, except for the transfer out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.
Transfer of Insurance Contracts: The insurance contracts consist of multiple contracts with two insurance companieswould impact earnings and are accounted for at fair value at the contracts’ cash surrender values. During 2013,flows only if the Company determined that its insurance contracts meet the requirementswere to be categorized as a Level 2 fair value measurement.
The componentsreacquire any of net periodic benefit cost were as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Pension Plans | | | |
| Components of net periodic benefit cost: | | | |
| Service cost | $ | 14,173 |
| $ | 10,527 |
| $ | 9,173 |
|
| Interest cost | 11,239 |
| 10,801 |
| 10,960 |
|
| Expected long-term return on assets | (14,731 | ) | (14,093 | ) | (15,471 | ) |
| Prior service cost amortization | 490 |
| 517 |
| 496 |
|
| Actuarial loss amortization | 13,979 |
| 8,603 |
| 6,435 |
|
| Termination benefit charge | — |
| — |
| 414 |
|
| Settlement charge | 1,373 |
| — |
| — |
|
| Net periodic expense | $ | 26,523 |
| $ | 16,355 |
| $ | 12,007 |
|
| Postretirement Benefit Plans | | | |
| Components of net periodic benefit cost: | | | |
| Service cost | $ | 1,694 |
| $ | 1,853 |
| $ | 1,769 |
|
| Interest cost | 3,504 |
| 4,248 |
| 4,443 |
|
| Expected long-term return on assets | (5,024 | ) | (4,438 | ) | (4,418 | ) |
| Actuarial (gain) loss amortization | (120 | ) | 37 |
| — |
|
| Transition obligation amortization | 1,296 |
| 1,917 |
| 1,917 |
|
| Curtailment gain | (1,229 | ) | — |
| — |
|
| Net periodic expense | $ | 121 |
| $ | 3,617 |
| $ | 3,711 |
|
Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Pension Plans | | | |
| Net actuarial (gain) loss experienced during the year | $ | (14,138 | ) | $ | 28,748 |
| $ | 14,312 |
|
| Net actuarial loss recognized as expense | (8,934 | ) | (4,908 | ) | (3,755 | ) |
| Prior service cost recognized as expense | (311 | ) | (340 | ) | (298 | ) |
| Total recognized in other comprehensive income (loss) | (23,383 | ) | 23,500 |
| 10,259 |
|
| Postretirement Benefit Plans | | | |
| Net actuarial (gain) loss experienced during the year | $ | (8,057 | ) | $ | (1,787 | ) | $ | 2,111 |
|
| Net actuarial gain recognized as expense | 550 |
| — |
| — |
|
| Transition obligation recognized as expense | (283 | ) | (294 | ) | (286 | ) |
| Total recognized in other comprehensive income (loss) | $ | (7,790 | ) | $ | (2,081 | ) | $ | 1,825 |
|
Net retirement expense for Alagasco was $12.1 million, $7.8 million and $5.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, the Company recognized a curtailment gain of $1.2 millionthese issues in the fourth quarteropen market prior to maturity. Under GAAP applicable to the Utilities' regulated operations, losses or gains on early redemptions of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognizedlong-term debt would typically be deferred as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurredor regulatory liabilities and amortized over a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the fourth quarter of 2013, the Company incurred a settlement charge of $0.8 million for the payment of lump sums from a defined benefit pension plan. In the first quarter of 2011, the Company recognized a termination benefit charge of $0.4 million to provide for early retirement of certain non-highly compensated
employees. Net periodic postretirement benefit cost for Alagasco was $0.8 million, $2.7 million and $2.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2014 are as follows:
|
| | | |
| (in thousands) | |
| Amortization of prior service cost | $ | 314 |
|
| Amortization of net actuarial loss | $ | 5,422 |
|
Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2014 are as follows:
|
| | | |
| (in thousands) | |
| Amortization of net transition obligation | $ | 42 |
|
| Amortization of net actuarial gain | $ | (593 | ) |
future period.
The Company has aentered into and settled certain interest rate swap transactions in 2014 to protect itself against adverse movements in interest rates associated with the issuance of long-term disability plan covering most employees. The Company had expense fordebt to fund the years endedacquisition of Alagasco. In 2015, Alagasco entered into and settled interest swaps to protect itself against adverse movements in interest rates in anticipation of the issuance of $115.0 in debt. Refer to December 31, 2013Note 10, 2012Derivative Instruments and 2011Hedging Activities, of the Notes to Financial Statements for additional details on these interest rate swap transactions. ENVIRONMENTAL MATTERS
$0.6 millionThe Utilities own and operate 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 Utilities' financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utilities may be required to incur additional costs. For information relative to environmental matters, see Note 16, $0.7 millionCommitments and $0.5 million, respectively.Contingencies, of the Notes to Financial Statements.
OFF-BALANCE SHEET ARRANGEMENTS
Assumptions: The weighted average rate assumptionsAt September 30, 2015, none of Laclede Group or its subsidiary companies had off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of Laclede Group or its subsidiaries expects to determine net periodic benefit costs were as follows:
|
| | | | | | |
| Years ended December 31, | 2013 | 2012 | 2011 |
| Pension Plans | | | |
| Discount rate | 3.63 | % | 4.52 | % | 4.89 | % |
| Expected long-term return on plan assets | 7.00 | % | 7.00 | % | 7.25 | % |
| Rate of compensation increase for pay-related plans | 3.71 | % | 3.59 | % | 3.75 | % |
| Postretirement Benefit Plans | | | |
| Discount rate | 4.26 | % | 4.95 | % | 5.45 | % |
| Expected long-term return on plan assets | 7.00 | % | 7.00 | % | 7.25 | % |
| Rate of compensation increase | 3.70 | % | 3.55 | % | 3.61 | % |
The weighted average rate assumptions used to determineengage in any significant off-balance sheet financing arrangements in the projected benefit obligations at the measurement date were as follows:
|
| | | | |
| Years ended December 31, | 2013 | 2012 |
| Pension Plans | | |
| Discount rate | 4.31 | % | 3.47 | % |
| Rate of compensation increase for pay-related plans | 3.63 | % | 3.71 | % |
| Postretirement Benefit Plans | | |
| Discount rate | 4.95 | % | 4.15 | % |
| Rate of compensation increase for pay-related plans | 3.60 | % | 3.70 | % |
near future.
The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:
|
| | | | |
| As of December 31, | 2013 | 2012 |
| Health care cost trend rate assumed for next year | 6.50 | % | 6.75 | % |
| Rate to which the cost trend rate is assumed to decline | 5.00 | % | 5.00 | % |
| Year that rate reaches ultimate rate | 2020 |
| 2020 |
|
Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:
|
| | | | | | |
(in thousands) | |
| | 1-Percentage Point Decrease | 1-Percentage Point Increase |
| Effect on total of service and interest cost | $ | (280 | ) | $ | 336 |
|
| Effect on net postretirement benefit obligation | $ | (764 | ) | $ | 759 |
|
Investment Strategy: The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.
The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.
The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
The Company’s weighted average plan asset allocations by asset category were as follows:
|
| | | | | | | | | | | | |
| | Pension | Postretirement Benefits |
| As of December 31, | Target | 2013 | 2012 | Target | 2013 | 2012 |
| Asset category: | | | | | | |
| Equity securities | 41 | % | 34 | % | 41 | % | 60 | % | 61 | % | 60 | % |
| Debt securities | 38 | % | 28 | % | 38 | % | 40 | % | 39 | % | 40 | % |
| Other | 21 | % | 38 | % | 21 | % | — | % | — | % | — | % |
| Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
Equity securities for pension and postretirement benefits do not include the Company’s common stock.
Plan assets included in the funded status of the pension plans were as follows:
|
| | | | | | | | | | | | |
| | December 31, 2013 |
| (in thousands) | Level 1 | Level 2 | Level 3 | Total |
| United States equities | $ | 34,117 |
| $ | 8,080 |
| $ | — |
| $ | 42,197 |
|
| Global equities | 20,153 |
| 13,256 |
| — |
| 33,409 |
|
| Fixed income | — |
| 61,121 |
| — |
| 61,121 |
|
| Alternative investments | — |
| 37,292 |
| — |
| 37,292 |
|
| Cash and cash equivalents | 5,970 |
| 39,545 |
| — |
| 45,515 |
|
| Total | $ | 60,240 |
| $ | 159,294 |
| $ | — |
| $ | 219,534 |
|
| | | | | |
| | December 31, 2012 |
| (in thousands) | Level 1 | Level 2 | Level 3 | Total |
| United States equities | $ | 41,907 |
| $ | 9,072 |
| $ | — |
| $ | 50,979 |
|
| Global equities | 23,782 |
| 10,697 |
| — |
| 34,479 |
|
| Fixed income | — |
| 78,806 |
| — |
| 78,806 |
|
| Alternative investments | — |
| 27,659 |
| 14,500 |
| 42,159 |
|
| Cash and cash equivalents | — |
| 3,001 |
| — |
| 3,001 |
|
| Total | $ | 65,689 |
| $ | 129,235 |
| $ | 14,500 |
| $ | 209,424 |
|
United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets. Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure. Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.
The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Balance at beginning of period | $ | 14,500 |
| $ | 17,399 |
| $ | 26,841 |
|
| Unrealized gains (losses) | — |
| 992 |
| (752 | ) |
| Unrealized gains relating to instruments held at the reporting date | — |
| 242 |
| 635 |
|
| Settlements | — |
| (4,948 | ) | (9,604 | ) |
| Purchases | — |
| 815 |
| 279 |
|
| Transfer out of Level 3 | (14,500 | ) | — |
| — |
|
| Balance at end of period | $ | — |
| $ | 14,500 |
| $ | 17,399 |
|
Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the cumulative reporting period. For the year ended December 31, 2013, except for the transfers out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.
Transfer of Alternative Investments: The alternative investments consist of three investments that are measured at net asset value (NAV). NAV per share serves as an estimate for the fair value of an investment as long as certain requirements are met. During 2013, the Company determined that its alternative investments meet those requirements.
Plan assets included in the funded status of the postretirement benefit plans were as follows:
|
| | | | | | | | | |
| | December 31, 2013 |
| (in thousands) | Level 1 | Level 2 | Total |
| United States equities | $ | 43,054 |
| $ | — |
| $ | 43,054 |
|
| Global equities | 17,048 |
| — |
| 17,048 |
|
| Fixed income | — |
| 38,831 |
| 38,831 |
|
| Total | $ | 60,102 |
| $ | 38,831 |
| $ | 98,933 |
|
|
| | | | | | | | | |
| | December 31, 2012 |
| (in thousands) | Level 1 | Level 2 | Total |
| United States equities | $ | 37,482 |
| $ | — |
| $ | 37,482 |
|
| Global equities | 15,049 |
| — |
| 15,049 |
|
| Fixed income | — |
| 34,658 |
| 34,658 |
|
| Total | $ | 52,531 |
| $ | 34,658 |
| $ | 87,189 |
|
The Company had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.
Cash Flows: There are no required contributions to the qualified pension plans during 2014. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $3 million to the qualified pension plans in January 2014. During 2014, the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. The Company expects to make benefit payments of approximately $6.1 million during 2014 to retirees with respect to the nonqualified supplemental retirement plans.
The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:
|
| | | |
(in thousands) |
Pension Benefits | Postretirement Benefits | Postretirement Benefits – Prescription Drug Subsidy |
| 2014 | $66,816 | $4,156 | $(212) |
| 2015 | $16,572 | $4,219 | $(218) |
| 2016 | $18,174 | $4,286 | $(224) |
| 2017 | $22,167 | $4,362 | $(227) |
| 2018 | $28,374 | $4,426 | $(231) |
| 2019-2023 | $134,584 | $22,319 | $(1,202) |
In March 2010, The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, Health Care Reform) was signed into law. The impact of the legislation has been estimated and is first reflected in the December 31, 2011 measurement of the post retirement benefit obligation. Energen has applied and been approved for the Early Retiree Reinsurance Program (ERRP). Energen is currently evaluating the application of the ERRP receipts, and therefore, the post retirement benefit obligations have not been reduced to reflect actual or expected receipts under the program.
6. COMMON STOCK PLANS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Energen Employee Savings Plan (ESP):For this discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2013Market Risk, total shares reserved for issuance equaledon page 1,080,108. Expense associated with Company contributions to the ESP was $8.0 million, $7.8 million44 and $6.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Stock Incentive Plan: The Stock Incentive Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The Stock Incentive Plan also provided for the grant of performance share awards and restricted stock. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, this report.8,600,000 shares of Company common stock were reserved for issuance with 2,921,392 remaining for issuance as of December 31, 2013.
Performance Share Awards: The Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Company common stock.
No performance share awards were granted in 2012 or 2011. A summary of performance share award activity as of December 31, 2013, and transactions during the year ended December 31, 2013 is presented below:
|
| | | | | |
| | Stock Incentive Plan |
|
Shares | Weighted Average Price |
| Nonvested at December 31, 2012 | — |
| $ | — |
|
| Granted (two-year vesting period) | 86,221 |
| 61.14 |
|
| Granted (three-year vesting period) | 82,606 |
| 62.96 |
|
| Forfeited | (8,008 | ) | 60.03 |
|
| Nonvested at December 31, 2013 | 160,819 |
| $ | 62.13 |
|
The Company recorded expense of $4.0 million for the year ended December 31, 2013 for performance share awards with a related deferred income tax benefit of $1.5 million. During the years ended December 31, 2012 and 2011, the Company recorded no expense for performance share awards. As of December 31, 2013, there was $5.5 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.49 years.
Stock Options: The Stock Incentive Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.
A summary of stock option activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
|
| | | | | |
| | Stock Incentive Plan |
|
Shares | Weighted Average Exercise Price |
| Outstanding at December 31, 2010 | 1,276,043 |
| $ | 40.16 |
|
| Granted | 293,978 |
| 54.99 |
|
| Exercised | (227,405 | ) | 32.33 |
|
| Forfeited | (4,375 | ) | 35.35 |
|
| Outstanding at December 31, 2011 | 1,338,241 |
| 44.77 |
|
| Granted | 371,040 |
| 54.11 |
|
| Exercised | (58,471 | ) | 24.55 |
|
| Forfeited | (2,335 | ) | 46.45 |
|
| Outstanding at December 31, 2012 | 1,648,475 |
| 47.58 |
|
| Granted | 137,762 |
| 49.22 |
|
| Exercised | (590,119 | ) | 40.92 |
|
| Forfeited | (5,074 | ) | 51.85 |
|
| Outstanding at December 31, 2013 | 1,191,044 |
| $ | 51.06 |
|
| Exercisable at December 31, 2011 | 677,753 |
| $ | 43.72 |
|
| Exercisable at December 31, 2012 | 987,733 |
| $ | 43.75 |
|
| Exercisable at December 31, 2013 | 713,445 |
| $ | 49.80 |
|
| Remaining reserved for issuance at December 31, 2013 | 2,921,392 |
| — |
The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:
|
| | | | | | | |
| Grant date | 10/15/2013 | 1/24/2013 | 1/25/2012 | 1/26/2011 |
| Awards granted | 3,686 | 134,076 |
| 371,040 |
| 293,978 |
|
| Fair market value of stock option at grant | $30.53 | $16.66 | $18.79 | $19.65 |
| Expected life of award | 5.8 years | 5.8 years |
| 5.8 years |
| 5.8 years |
|
| Risk-free interest rate | 1.79% | 1.01 | % | 1.07 | % | 2.45 | % |
| Annualized volatility rate | 40.6% | 40.3 | % | 39.6 | % | 37.8 | % |
| Dividend yield | 0.7% | 1.2 | % | 1.0 | % | 1.0 | % |
The Company recorded stock option expense of $3.6 million, $7.0 million and $5.6 million during the years ended December 31, 2013, 2012 and 2011, respectively, with a related deferred tax benefit of $1.4 million, $2.6 million and $2.1 million, respectively.
The total intrinsic value of stock options exercised during the year ended December 31, 2013, was $15.7 million. During the year ended December 31, 2013, the Company received cash of $17.8 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2013, was $23.5 million and $14.9 million for exercisable options. The fair value of options vested for the year ended December 31, 2013 was $5.8 million. As of December 31, 2013, there was $0.5 million of unrecognized compensation cost related to outstanding nonvested stock options.
The following table summarizes options outstanding as of December 31, 2013:
|
| | |
| Stock Incentive Plan |
Range of Exercise Prices |
Shares | Weighted Average Remaining Contractual Life |
| $46.45 | 59,330 | 3.00 years |
| $60.56 | 99,965 | 4.00 years |
| $29.79 | 78,222 | 5.00 years |
| $46.69 | 203,469 | 6.00 years |
| $54.99 | 266,166 | 7.00 years |
| $54.11 | 349,754 | 8.00 years |
| $48.36 | 130,452 | 9.00 years |
| $80.48 | 3,686 | 9.83 years |
| $29.79-$80.48 | 1,191,044 | 6.77 years |
The weighted average remaining contractual life of currently exercisable stock options is 5.89 years as of December 31, 2013.
Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three year vesting period. A summary of restricted stock activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 is presented below:
|
| | | | | |
| | Stock Incentive Plan |
| |
Shares | Weighted Average Price |
| Nonvested at December 31, 2010 | 24,150 |
| $ | 35.49 |
|
| Vested | (14,875 | ) | 30.81 |
|
| Nonvested at December 31, 2011 | 9,275 |
| 42.99 |
|
| Granted | 11,115 |
| 45.24 |
|
| Vested | (9,275 | ) | 42.97 |
|
| Nonvested at December 31, 2012 | 11,115 |
| 45.24 |
|
| Granted | 52,650 |
| 52.34 |
|
| Forfeited | (1,247 | ) | 48.36 |
|
| Nonvested at December 31, 2013 | 62,518 |
| $ | 51.16 |
|
The Company recorded expense of $2.0 million, $0.1 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to restricted stock, with a related deferred income tax benefit of $746,000, $31,000 and $47,000, respectively. As of December 31, 2013, there was $1.2 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 2.05 years.
Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period.
A summary of stock appreciation rights activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
|
| | | | | |
| | Stock Appreciation Rights Plan |
|
Shares | Weighted Average Exercise Price |
| Outstanding at December 31, 2010 | 656,340 |
| $ | 38.30 |
|
| Granted | 189,984 |
| 54.99 |
|
| Exercised/forfeited | (69,106 | ) | 41.21 |
|
| Outstanding at December 31, 2011 | 777,218 |
| 42.00 |
|
| Exercised/forfeited | (124,188 | ) | 30.90 |
|
| Outstanding at December 31, 2012 | 653,030 |
| 44.14 |
|
| Granted | 88,000 |
| 48.36 |
|
| Exercised/forfeited | (363,653 | ) | 39.66 |
|
| Outstanding at December 31, 2013 | 377,377 |
| $ | 49.48 |
|
The Company issued the following awards with stock appreciation rights. The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. On December 19, 2013, the Company modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2013:
|
| | | | | |
| Grant date | 1/24/2013 | 1/24/2013 | 1/26/2011 | 1/26/2011 | 1/27/2010 |
| | | (modified) | | (modified) | |
| Awards granted | 87,069 | 931 | 182,199 | 7,785 | 171,749 |
| Fair market value of award | $34.66 | $27.89 | $27.07 | $24.21 | $30.10 |
| Expected life of award | 5.6 years | 2.5 years | 3.6 years | 2.5 years | 3.0 years |
| Risk-free interest rate | 2.04% | 0.56% | 1.06% | 0.56% | 0.80% |
| Annualized volatility rate | 40.6% | 40.6% | 40.6% | 40.6% | 40.6% |
| Dividend yield | 0.8% | 0.8% | 0.8% | 0.8% | 0.8% |
|
| | | | |
| Grant date | 2/13-16/2009 | 1/28/2009 | 2/4/2008 | 2/1/2007 |
| Awards granted | 3,292 | 305,257 | 67,093 | 85,906 |
| Fair market value of award | $39.87 | $41.18 | $18.50 | $27.03 |
| Expected life of award | 2.5 years | 2.5 years | 2.0 years | 1.5 years |
| Risk-free interest rate | 0.58% | 0.58% | 0.39% | 0.23% |
| Annualized volatility rate | 40.6% | 40.6% | 40.6% | 40.6% |
| Dividend yield | 0.8% | 0.8% | 0.8% | 0.8% |
Expense associated with stock appreciation rights of $1.5 million and $4.3 million was recorded for the years ended December 31, 2013 and 2011. Income associated with stock appreciation rights of $1.0 million was recorded for the year ended December 31, 2012. During the year ended December 31, 2013, the total intrinsic value of stock appreciation rights exercised was $8.5 million. During the year ended December 31, 2013, the Company paid $5.8 million in settlement of stock appreciation rights.
Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends.
A summary of Petrotech unit activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
|
| | | |
| ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | |
| | | Petrotech Incentive Plan | Page |
| | Shares | |
Outstanding at December 31, 2010 |
| 8,205 |
|
Granted (three-year vesting period) | | 6,314 |
|
Paid | | (1,914 | ) |
Forfeited | | (1,544 | ) |
Outstanding at December 31, 2011 | | 11,061Financial Statements: |
|
Granted (three-year vesting period) | | 102,349The Laclede Group, Inc. (for years ended September 30, 2015, 2014, and 2013) |
|
Granted (two-year vesting period) | | 3,768 |
|
Granted (18 month vesting period) | | 40,822 |
|
Paid | | (3,281 | ) |
Forfeited | | (13,476 | ) |
Outstanding at December 31, 2012 | | 141,243 |
|
Granted (three-year vesting period) | | 92,418 |
|
Granted (17 month vesting period) | | 2,952Laclede Gas Company (for years ended September 30, 2015, 2014, and 2013) |
|
Paid | | (36,792 | ) |
Forfeited | | (26,529 | ) |
Outstanding at December 31, 2013 | | 173,292 |
|
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| | Alabama Gas Corporation (for the year ended September 30, 2015, the nine months ended September 30, 2014, and the year ended December 31, 2013) | |
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The Laclede Group, Inc.
Management Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Laclede Group, Inc.'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 Laclede Group Inc.’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of the Laclede Group Inc.’s internal control over financial reporting as of September 30, 2015. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). Based on that assessment, management concluded that the Laclede Group Inc.’s internal control over financial reporting was effective as of September 30, 2015. Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on the Laclede Group Inc.’s internal control over financial reporting, which is included herein.
Laclede Gas Company
Management Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Laclede Gas 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.
Laclede Gas Company’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of Laclede Gas Company’s internal control over financial reporting as of September 30, 2015. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). Based on that assessment, management concluded that Laclede Gas Company’s internal control over financial reporting was effective as of September 30, 2015.
Alabama Gas Corporation
Management Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Alabama Gas Corporation'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.
Alabama Gas Corporation's management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of Alabama Gas Corporation's internal control over financial reporting as of September 30, 2015. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). Based on that assessment, management concluded that Alabama Gas Corporation’s internal control over financial reporting was effective as of September 30, 2015.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
The Laclede Group, Inc.
St. Louis, Missouri
NoneWe have audited the internal control over financial reporting of The Laclede Group, Inc. and subsidiaries (the "Company") as of September 30, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the awards Treadway Commission. 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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued includedby 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 as of and for the year ended September 30, 2015 of the Company and our report dated November 24, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
St. Louis, Missouri
November 24, 2015
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 consolidated statements of capitalization of The Laclede Group, Inc. and subsidiaries (the “Company”) as of September 30, 2015 and 2014, 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, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements 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 market condition. Energen Resources recognized expensetest 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2015, in conformity with accounting principles generally accepted in the United States of America.
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, 2015, based on the criteria established in $6.2 million, $2.6 millionInternal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and $0.2 million during 2013, 2012 and 2011, respectively, related to these units.our report dated November 24, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.
1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2013 there were 695,140 shares reserved for issuance from the 1997 Deferred Compensation Plan./s/ DELOITTE & TOUCHE LLP
St. Louis, Missouri
1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 13,500 shares, 11,120 shares and 12,420 shares were awarded during the years ended December 31, 2013, 2012 and 2011, respectively, leaving 138,284 shares reserved for issuance as of December 31, 2013.
Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by resolutions adopted April 26, 2000 and JuneNovember 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2013, 2012 and 2011. As of December 31, 2013, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company’s stock compensation plans. For the years ended December 31, 2013, 2012 and 2011, the Company acquired 14,766 shares, 5,459 shares and 12,867 shares, respectively, in connection with its stock compensation plans.2015
7. COMMITMENTS AND CONTINGENCIESREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Laclede Gas Company
St. Louis, Missouri
We have audited the accompanying balance sheets and statements of capitalization of Laclede Gas Company (a wholly owned subsidiary of The Laclede Group, Inc.) (the “Company”) as of September 30, 2015 and 2014, and the related statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended September 30, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial statements present fairly, in all material respects, the financial position of Laclede Gas Company as of September 30, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
St. Louis, Missouri
November 24, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Alabama Gas Corporation
Birmingham, Alabama
We have audited the accompanying balance sheets and statements of capitalization of Alabama Gas Corporation (a wholly owned subsidiary of The Laclede Group, Inc.) (the "Company") as of September 30, 2015 and 2014, and the related statements of income, common shareholder’s equity, and cash flows for the year ended September 30, 2015 and the nine months ended September 30, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial statements present fairly, in all material respects, the financial position of Alabama Gas Corporation as of September 30, 2015 and 2014, and the results of its operations and its cash flows for the year ended September 30, 2015 and the nine months ended September 30, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Birmingham, Alabama
November 24, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Alabama Gas Corporation
In our opinion, the accompanying statements of income, common shareholder’s equity and cash flows present fairly, in all material respects, the results of operations and cash flows of Alabama Gas Corporation for the year ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Birmingham, Alabama
March 3, 2014
|
| | | | | | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED STATEMENTS OF INCOME |
| (In Millions, Except Per Share Amounts) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Operating Revenues: | | | | | |
| Gas Utility | $ | 1,891.8 |
| | $ | 1,462.6 |
| | $ | 847.2 |
|
| Gas Marketing and other | 84.6 |
| | 164.6 |
| | 169.8 |
|
| Total Operating Revenues | 1,976.4 |
| | 1,627.2 |
| | 1,017.0 |
|
| Operating Expenses: | | | | | |
| Gas Utility | | | | | |
| Natural and propane gas | 882.4 |
| | 731.7 |
| | 433.4 |
|
| Other operation and maintenance expenses | 390.6 |
| | 287.8 |
| | 180.3 |
|
| Depreciation and amortization | 129.9 |
| | 82.4 |
| | 48.3 |
|
| Taxes, other than income taxes | 142.1 |
| | 112.0 |
| | 60.1 |
|
| Total Gas Utility Operating Expenses | 1,545.0 |
| | 1,213.9 |
| | 722.1 |
|
| Gas Marketing and other | 158.9 |
| | 246.9 |
| | 198.4 |
|
| Total Operating Expenses | 1,703.9 |
| | 1,460.8 |
| | 920.5 |
|
| Operating Income | 272.5 |
| | 166.4 |
| | 96.5 |
|
| Other Income and (Income Deductions) – Net | 1.2 |
| | (3.3 | ) | | 2.5 |
|
| Interest Charges: | | | | | |
| Interest on long-term debt | 66.6 |
| | 39.3 |
| | 25.5 |
|
| Other interest charges | 8.0 |
| | 6.9 |
| | 3.1 |
|
| Total Interest Charges | 74.6 |
| | 46.2 |
| | 28.6 |
|
| Income Before Income Taxes | 199.1 |
| | 116.9 |
| | 70.4 |
|
| Income Tax Expense | 62.2 |
| | 32.3 |
| | 17.6 |
|
| Net Income | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
| Weighted Average Number of Common Shares Outstanding: | | | | | |
| Basic | 43.2 |
| | 35.8 |
| | 25.9 |
|
| Diluted | 43.3 |
| | 35.9 |
| | 26.0 |
|
| Basic Earnings Per Share of Common Stock | $ | 3.16 |
| | $ | 2.36 |
| | $ | 2.03 |
|
| Diluted Earnings Per Share of Common Stock | $ | 3.16 |
| | $ | 2.35 |
| | $ | 2.02 |
|
|
| | | | | | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| (In Millions) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Net Income | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
| Other Comprehensive Income (Loss), Before Tax: | | | | | |
| Cash flow hedging derivative instruments: | | | | | |
| Net hedging gain (losses) arising during the period | (5.5 | ) | | (4.5 | ) | | 5.0 |
|
| Reclassification adjustment for losses included in net income | 4.4 |
| | 2.5 |
| | 0.3 |
|
| Net unrealized gains (losses) on cash flow hedging derivative instruments | (1.1 | ) | | (2.0 | ) | | 5.3 |
|
| Defined benefit pension and other postretirement benefit plans: | | | | | |
| Net actuarial gain (losses) arising during the period | 0.1 |
| | — |
| | (0.1 | ) |
| Amortization of actuarial loss included in net periodic pension and postretirement benefit cost | 0.4 |
| | 0.5 |
| | 0.2 |
|
| Net defined benefit pension and other postretirement benefit plans | 0.5 |
| | 0.5 |
| | 0.1 |
|
| Other Comprehensive Income (Loss), Before Tax | (0.6 | ) | | (1.5 | ) | | 5.4 |
|
| Income Tax Expense (Benefit) Related to Items of Other Comprehensive Income (Loss) | (0.3 | ) | | (0.6 | ) | | 2.1 |
|
| Other Comprehensive Income (Loss), Net of Tax | (0.3 | ) | | (0.9 | ) | | 3.3 |
|
| Comprehensive Income | $ | 136.6 |
| | $ | 83.7 |
| | $ | 56.1 |
|
|
| | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED BALANCE SHEETS |
| (In Millions) | | | |
| September 30 | 2015 | | 2014 |
| ASSETS | | | |
| Utility Plant | $ | 4,234.5 |
| | $ | 3,928.3 |
|
| Less: Accumulated depreciation and amortization | 1,307.0 |
| | 1,168.6 |
|
| Net Utility Plant | 2,927.5 |
| | 2,759.7 |
|
| Non-utility property (net of accumulated depreciation and amortization, $7.5 and $6.7 at September 30, 2015 and 2014, respectively) | 13.7 |
| | 9.2 |
|
| Goodwill | 946.0 |
| | 937.8 |
|
| Other investments | 59.9 |
| | 60.0 |
|
| Other Property and Investments | 1,019.6 |
| | 1,007.0 |
|
| Current Assets: | | | |
| Cash and cash equivalents | 13.8 |
| | 16.1 |
|
| Accounts receivable: | | | |
| Utility | 138.1 |
| | 148.2 |
|
| Other | 86.7 |
| | 86.5 |
|
| Allowance for doubtful accounts | (14.2 | ) | | (15.9 | ) |
| Delayed customer billings | 2.6 |
| | 10.8 |
|
| Inventories: | | | |
| Natural gas | 188.6 |
| | 245.5 |
|
| Propane gas | 12.0 |
| | 11.7 |
|
| Materials and supplies | 14.8 |
| | 13.0 |
|
| Natural gas receivable | 17.3 |
| | 7.3 |
|
| Derivative instrument assets | 4.6 |
| | 2.4 |
|
| Unamortized purchased gas adjustments | 12.9 |
| | 54.0 |
|
| Regulatory assets | 27.6 |
| | 26.8 |
|
| Prepayments and other | 25.3 |
| | 21.6 |
|
| Total Current Assets | 530.1 |
| | 628.0 |
|
| Deferred Charges: | | | |
| Regulatory assets | 737.6 |
| | 614.3 |
|
| Other | 75.4 |
| | 65.0 |
|
| Total Deferred Charges | 813.0 |
| | 679.3 |
|
| Total Assets | $ | 5,290.2 |
| | $ | 5,074.0 |
|
|
| | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED BALANCE SHEETS (Continued) |
| (In Millions) | | | |
| September 30 | 2015 | | 2014 |
| CAPITALIZATION AND LIABILITIES | | | |
| Capitalization: | | | |
| Common stock equity | $ | 1,573.6 |
| | $ | 1,508.4 |
|
| Long-term debt | 1,771.5 |
| | 1,851.0 |
|
| Total Capitalization | 3,345.1 |
| | 3,359.4 |
|
| Current Liabilities: | | | |
| Current portion of long-term debt | 80.0 |
| | — |
|
| Notes payable | 338.0 |
| | 287.1 |
|
| Accounts payable | 146.5 |
| | 176.7 |
|
| Advance customer billings | 44.3 |
| | 32.2 |
|
| Wages and compensation accrued | 32.7 |
| | 36.0 |
|
| Dividends payable | 21.1 |
| | 19.9 |
|
| Customer deposits | 32.1 |
| | 34.0 |
|
| Interest accrued | 14.3 |
| | 15.1 |
|
| Unamortized purchased gas adjustments | 28.2 |
| | 22.4 |
|
| Taxes accrued | 51.7 |
| | 63.4 |
|
| Deferred income taxes | — |
| | 9.9 |
|
| Regulatory liabilities | 32.4 |
| | 41.3 |
|
| Other | 32.5 |
| | 47.8 |
|
| Total Current Liabilities | 853.8 |
| | 785.8 |
|
| Deferred Credits and Other Liabilities: | | | |
| Deferred income taxes | 482.1 |
| | 383.8 |
|
| Pension and postretirement benefit costs | 253.4 |
| | 244.9 |
|
| Asset retirement obligations | 159.2 |
| | 99.2 |
|
| Regulatory liabilities | 119.3 |
| | 125.8 |
|
| Other | 77.3 |
| | 75.1 |
|
| Total Deferred Credits and Other Liabilities | 1,091.3 |
| | 928.8 |
|
|
| |
|
| Total Capitalization and Liabilities | $ | 5,290.2 |
| | $ | 5,074.0 |
|
|
| | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED STATEMENTS OF CAPITALIZATION |
| (Dollars in Millions, Except Per Share Amounts) | | | |
| September 30 | 2015 | | 2014 |
| Common Stock Equity: | | | |
| Common stock, par value $1 per share: | | | |
| Authorized – 70,000,000 shares | | | |
| Outstanding – 43,335,012 shares and 43,183,818 shares, respectively | $ | 43.3 |
| | $ | 43.2 |
|
| Paid-in capital | 1,038.1 |
| | 1,029.4 |
|
| Retained earnings | 494.2 |
| | 437.5 |
|
| Accumulated other comprehensive loss | (2.0 | ) | | (1.7 | ) |
| Total Common Stock Equity | 1,573.6 |
| | 1,508.4 |
|
| Long-Term Debt - Laclede Group: | | | |
| Floating Rate Senior Notes, due August 15, 2017 | 250.0 |
| | 250.0 |
|
| 2.55% Senior Notes, due August 15, 2019 | 125.0 |
| | 125.0 |
|
| 3.31% Notes Payable, due December 15, 2022 | 25.0 |
| | 25.0 |
|
| 2.0% Series A Remarketable Subordinated Notes, due April 1, 2022 | 143.8 |
| | 143.8 |
|
| 4.70% Senior Notes, due August 15, 2044 | 250.0 |
| | 250.0 |
|
| Long-Term Debt - Laclede Gas: | | | |
| First Mortgage Bonds: | | | |
| 2.0% Series, due August 15, 2018 | 100.0 |
| | 100.0 |
|
| 5.5% Series, due May 1, 2019 | 50.0 |
| | 50.0 |
|
| 3.0% Series, due March 15, 2023 | 55.0 |
| | 55.0 |
|
| 3.4% Series, due August 15, 2023 | 250.0 |
| | 250.0 |
|
| 3.4% Series, due March 15, 2028 | 45.0 |
| | 45.0 |
|
| 7.0% Series, due June 1, 2029 | 25.0 |
| | 25.0 |
|
| 7.9% Series, due September 15, 2030 | 30.0 |
| | 30.0 |
|
| 6.0% Series, due May 1, 2034 | 100.0 |
| | 100.0 |
|
| 6.15% Series, due June 1, 2036 | 55.0 |
| | 55.0 |
|
| 4.625% Series, due August 15, 2043 | 100.0 |
| | 100.0 |
|
| Long-Term Debt - Alagasco: | | | |
| 5.368% Notes, due December 1, 2015 | — |
| | 80.0 |
|
| 5.2% Notes, due January 15, 2020 | 40.0 |
| | 40.0 |
|
| 3.86% Notes, due December 23, 2021 | 50.0 |
| | 50.0 |
|
| 3.21% Notes, due September 15, 2025 | 35.0 |
| | — |
|
| 5.7% Notes, due January 15, 2035 | — |
| | 34.8 |
|
| 5.9% Notes, due January 15, 2037 | 45.0 |
| | 45.0 |
|
| Total | 1,773.8 |
| | 1,853.6 |
|
| Unamortized discount, net of premium, on long-term debt | (2.3 | ) | | (2.6 | ) |
| Total Long-Term Debt | 1,771.5 |
| | 1,851.0 |
|
| Total Capitalization | $ | 3,345.1 |
| | $ | 3,359.4 |
|
Long-term debt dollar amounts are not delivered. These delivery commitments are approximatelyexclusive of current portion.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY |
| | | | | | | | | | |
| | Common Stock Outstanding | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income/(Loss) | | |
| (Dollars in Millions, Except Per Share Amounts) | Shares | | Amount | | | | | Total |
| BALANCE SEPTEMBER 30, 2012 | 22,539,431 |
| | $ | 22.6 |
| | $ | 168.6 |
| | $ | 414.5 |
| | $ | (4.1 | ) | | $ | 601.6 |
|
| Net income | — |
| | — |
| | — |
| | 52.8 |
| | — |
| | 52.8 |
|
| Common stock offering | 10,005,000 |
| | 10.0 |
| | 417.2 |
| | — |
| | — |
| | 427.2 |
|
| Dividend reinvestment plan | 44,074 |
| | — |
| | 1.8 |
| | — |
| | — |
| | 1.8 |
|
| Stock-based compensation costs | — |
| | — |
| | 4.4 |
| | — |
| | — |
| | 4.4 |
|
| Equity Incentive Plan | 108,331 |
| | 0.1 |
| | 2.6 |
| | — |
| | — |
| | 2.7 |
|
Employees’ taxes paid associated with restricted shares withheld upon vesting | — |
| | — |
| | (0.9 | ) | | — |
| | — |
| | (0.9 | ) |
| Tax benefit – stock compensation | — |
| | — |
| | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock ($1.70 per share) | — |
| | — |
| | — |
| | (47.2 | ) | | — |
| | (47.2 | ) |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 3.3 |
| | 3.3 |
|
| BALANCE SEPTEMBER 30, 2013 | 32,696,836 |
| | $ | 32.7 |
| | $ | 594.3 |
| | $ | 420.1 |
| | $ | (0.8 | ) | | $ | 1,046.3 |
|
| Net income | — |
| | — |
| | — |
| | 84.6 |
| | — |
| | 84.6 |
|
| Common stock offering | 10,350,000 |
| | 10.4 |
| | 446.4 |
| | — |
| | — |
| | 456.8 |
|
| Equity units offering | — |
| | — |
| | (19.7 | ) | | — |
| | — |
| | (19.7 | ) |
| Dividend reinvestment plan | 33,667 |
| | — |
| | 1.5 |
| | — |
| | — |
| | 1.5 |
|
| Stock-based compensation costs | — |
| | — |
| | 5.8 |
| | — |
| | — |
| | 5.8 |
|
| Equity Incentive Plan | 97,902 |
| | 0.1 |
| | 1.6 |
| | — |
| | — |
| | 1.7 |
|
Employees’ taxes paid associated with restricted shares withheld upon vesting | — |
| | — |
| | (1.1 | ) | | — |
| | — |
| | (1.1 | ) |
| Tax benefit – stock compensation | — |
| | — |
| | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock ($1.76 per share) | — |
| | — |
| | — |
| | (67.2 | ) | | — |
| | (67.2 | ) |
| Other comprehensive loss, net of tax | — |
| | — |
| | — |
| — |
| — |
| | (0.9 | ) | | (0.9 | ) |
| BALANCE SEPTEMBER 30, 2014 | 43,178,405 |
| | $ | 43.2 |
| | $ | 1,029.4 |
| | $ | 437.5 |
| | $ | (1.7 | ) | | $ | 1,508.4 |
|
| Net income | — |
| | — |
| | — |
| | 136.9 |
| | — |
| | 136.9 |
|
| Dividend reinvestment plan | 31,166 |
| | — |
| | 1.6 |
| | — |
| | — |
| | 1.6 |
|
| Stock-based compensation costs | — |
| | — |
| | 3.0 |
| | — |
| | — |
| | 3.0 |
|
| Equity Incentive Plan | 125,441 |
| | 0.1 |
| | 5.0 |
| | — |
| | — |
| | 5.1 |
|
Employees’ taxes paid associated with restricted shares withheld upon vesting | — |
| | — |
| | (1.6 | ) | | — |
| | — |
| | (1.6 | ) |
| Tax benefit – stock compensation | — |
| | — |
| | 0.7 |
| | — |
| | — |
| | 0.7 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock ($1.84 per share) | — |
| | — |
| | — |
| | (80.2 | ) | | — |
| | (80.2 | ) |
| Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | (0.3 | ) | | (0.3 | ) |
| BALANCE SEPTEMBER 30, 2015 | 43,335,012 |
| | $ | 43.3 |
| | $ | 1,038.1 |
| | $ | 494.2 |
| | $ | (2.0 | ) | | $ | 1,573.6 |
|
|
| | | | | | | | | | | |
| THE LACLEDE GROUP, INC. |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| (In Millions) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Operating Activities: | | | | | |
| Net Income | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 130.8 |
| | 83.3 |
| | 49.3 |
|
| Deferred income taxes and investment tax credits | 65.5 |
| | 31.4 |
| | 22.0 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable – net | (4.8 | ) | | (5.3 | ) | | (0.7 | ) |
| Unamortized purchased gas adjustments | 46.9 |
| | (36.4 | ) | | 23.1 |
|
| Deferred purchased gas costs | (19.8 | ) | | 13.9 |
| | 13.3 |
|
| Accounts payable | (30.0 | ) | | 8.6 |
| | 35.4 |
|
| Delayed / advance customer billings – net | 20.3 |
| | (19.1 | ) | | (8.2 | ) |
| Taxes accrued | (17.0 | ) | | (0.8 | ) | | 3.7 |
|
| Inventories | 54.8 |
| | (15.5 | ) | | (30.6 | ) |
| Other assets and liabilities | (67.6 | ) | | (27.5 | ) | | 2.8 |
|
| Other | 6.4 |
| | 5.4 |
| | 1.0 |
|
| Net cash provided by operating activities | 322.4 |
| | 122.6 |
| | 163.9 |
|
| Investing Activities: | | | | | |
| Capital expenditures | (289.8 | ) | | (171.0 | ) | | (130.8 | ) |
| Acquisition of Alagasco (net of $12.1 cash acquired in 2014) | (8.2 | ) | | (1,305.2 | ) | | — |
|
| Acquisition of MGE | — |
| | 23.9 |
| | (975.0 | ) |
| Proceeds from sale of right to acquire New England Gas Company | — |
| | 11.0 |
| | — |
|
| Other | (0.7 | ) | | 3.7 |
| | (2.5 | ) |
| Net cash used in investing activities | (298.7 | ) | | (1,437.6 | ) | | (1,108.3 | ) |
| Financing Activities: | | | | | |
| Issuance of long-term debt | 35.0 |
| | 768.8 |
| | 575.0 |
|
| Repayment of long-term debt | (34.8 | ) | | (80.0 | ) | | (25.0 | ) |
| Issuance of short-term debt - net | 50.8 |
| | 198.1 |
| | 33.9 |
|
| Issuance of common stock | 3.1 |
| | 460.0 |
| | 431.7 |
|
| Dividends paid | (79.0 | ) | | (61.9 | ) | | (42.5 | ) |
| Other | (1.1 | ) | | (6.9 | ) | | (3.2 | ) |
| Net cash (used in) provided by financing activities | (26.0 | ) | | 1,278.1 |
| | 969.9 |
|
| Net (Decrease) Increase in Cash and Cash Equivalents | (2.3 | ) | | (36.9 | ) | | 25.5 |
|
| Cash and Cash Equivalents at Beginning of Year | 16.1 |
| | 53.0 |
| | 27.5 |
|
| Cash and Cash Equivalents at End of Year | $ | 13.8 |
| | $ | 16.1 |
| | $ | 53.0 |
|
| | | | | | |
| Supplemental disclosure of cash (paid) refunded for: | | | | | |
| Interest | $ | (65.3 | ) | | $ | (40.6 | ) | | $ | (26.3 | ) |
| Income taxes | 1.3 |
| | (3.4 | ) | | 9.4 |
|
Energen Resources entered into an agreement which commenced on January 15, 2012 and expires in January 2015 to secure a drilling rig necessary to execute a portion
|
| | | | | | | | | | | |
| LACLEDE GAS COMPANY |
| STATEMENTS OF INCOME |
| (In Millions) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Operating Revenues: | | | | | |
| Utility | $ | 1,416.6 |
| | $ | 1,448.1 |
| | $ | 857.8 |
|
| Other | — |
| | 0.1 |
| | 1.6 |
|
| Total Operating Revenues | 1,416.6 |
| | 1,448.2 |
| | 859.4 |
|
| Operating Expenses: | | | | | |
| Utility | | | | | |
| Natural and propane gas | 786.1 |
| | 816.9 |
| | 469.1 |
|
| Other operation and maintenance expenses | 253.6 |
| | 276.4 |
| | 180.7 |
|
| Depreciation and amortization | 82.6 |
| | 78.5 |
| | 48.3 |
|
| Taxes, other than income taxes | 108.9 |
| | 110.1 |
| | 60.1 |
|
| Total Utility Operating Expenses | 1,231.2 |
| | 1,281.9 |
| | 758.2 |
|
| Other | — |
| | (0.1 | ) | | 13.7 |
|
| Total Operating Expenses | 1,231.2 |
| | 1,281.8 |
| | 771.9 |
|
| Operating Income | 185.4 |
| | 166.4 |
| | 87.5 |
|
| Other (Income Deductions) and Income - Net | (0.5 | ) | | (3.4 | ) | | 2.0 |
|
| Interest Charges: | | | | | |
| Interest on long-term debt | 33.1 |
| | 34.4 |
| | 24.9 |
|
| Other interest charges | 3.3 |
| | 3.0 |
| | 1.2 |
|
| Total Interest Charges | 36.4 |
| | 37.4 |
| | 26.1 |
|
| Income Before Income Taxes | 148.5 |
| | 125.6 |
| | 63.4 |
|
| Income Tax Expense | 43.2 |
| | 35.5 |
| | 14.6 |
|
| Net Income | $ | 105.3 |
| | $ | 90.1 |
| | $ | 48.8 |
|
Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $171 million through September 2024. During the years ended December 31, 2013, 2012 and 2011, Alagasco recognized approximately $50 million, $51 million and $51 million, respectively, of current-year commitments through expense and its regulatory accounts inSee the accompanying financial statements. Alagasco also is committedNotes to purchase minimum quantitiesFinancial Statements.
|
| | | | | | | | | | | |
| LACLEDE GAS COMPANY |
| STATEMENTS OF COMPREHENSIVE INCOME |
| (In Millions) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Net Income | $ | 105.3 |
| | $ | 90.1 |
| | $ | 48.8 |
|
| Other Comprehensive Income, Before Tax: | | | | | |
| Cash flow hedging derivative instruments: | | | | | |
| Net hedging gain (loss) arising during the period | (1.2 | ) | | 0.1 |
| | 0.1 |
|
| Reclassification adjustment for losses (gains) included in net income | 0.9 |
| | (0.2 | ) | | (0.2 | ) |
| Net unrealized (loss) on cash flow hedging derivative instruments | (0.3 | ) | | (0.1 | ) | | (0.1 | ) |
| Defined benefit pension and other postretirement benefit plans: | | | | | |
| Net actuarial gain (loss) arising during the period | 0.1 |
| | — |
| | (0.1 | ) |
| Amortization of actuarial loss included in net periodic pension and postretirement benefit cost | 0.4 |
| | 0.4 |
| | 0.2 |
|
| Net defined benefit pension and other postretirement benefit plans | 0.5 |
| | 0.4 |
| | 0.1 |
|
| Other Comprehensive Income, Before Tax | 0.2 |
| | 0.3 |
| | — |
|
| Income Tax Expense Related to Items of Other Comprehensive Income | — |
| | 0.1 |
| | — |
|
| Other Comprehensive Income, Net of Tax | 0.2 |
| | 0.2 |
| | — |
|
| Comprehensive Income | $ | 105.5 |
| | $ | 90.3 |
| | $ | 48.8 |
|
|
| | | | | | | |
| LACLEDE GAS COMPANY |
| BALANCE SHEETS |
| (In Millions) | | | |
| September 30 | 2015 | | 2014 |
| ASSETS | | | |
| Utility Plant | $ | 2,579.1 |
| | $ | 2,403.3 |
|
| Less: Accumulated depreciation and amortization | 590.0 |
| | 542.3 |
|
| Net Utility Plant | 1,989.1 |
| | 1,861.0 |
|
| Goodwill | 210.2 |
| | 210.2 |
|
| Other Property and Investments | 55.3 |
| | 55.7 |
|
| Other Property and Investments | 265.5 |
| | 265.9 |
|
| Current Assets: | | | |
| Cash and cash equivalents | 1.7 |
| | 3.7 |
|
| Accounts receivable: | | | |
| Utility | 103.4 |
| | 111.1 |
|
| Other | 25.2 |
| | 19.2 |
|
| Allowance for doubtful accounts | (10.0 | ) | | (10.7 | ) |
| Delayed customer billings | 2.6 |
| | 10.8 |
|
| Receivables from associated companies | 2.5 |
| | 11.4 |
|
| Inventories: | | | |
| Natural gas | 138.2 |
| | 191.1 |
|
| Propane gas | 12.0 |
| | 11.7 |
|
| Materials and supplies | 9.3 |
| | 7.8 |
|
| Unamortized purchased gas adjustments | 12.9 |
| | 54.0 |
|
| Regulatory assets | 16.2 |
| | 18.0 |
|
| Prepayments and other | 12.5 |
| | 15.5 |
|
| Total Current Assets | 326.5 |
| | 443.6 |
|
| Deferred Charges: | | | |
| Regulatory assets | 573.6 |
| | 523.7 |
|
| Other | 12.8 |
| | 10.8 |
|
| Total Deferred Charges | 586.4 |
| | 534.5 |
|
| Total Assets | $ | 3,167.5 |
| | $ | 3,105.0 |
|
|
| | | | | | | |
| LACLEDE GAS COMPANY |
| BALANCE SHEETS (continued) |
| (Millions) | | | |
| September 30 | 2015 | | 2014 |
| CAPITALIZATION AND LIABILITIES | | | |
| Capitalization: | | | |
| Common stock equity | $ | 1,037.8 |
| | $ | 1,007.8 |
|
| Long-term debt | 808.1 |
| | 807.9 |
|
| Total Capitalization | 1,845.9 |
| | 1,815.7 |
|
| Current Liabilities: | | | |
| Notes payable | 233.0 |
| | 238.6 |
|
| Accounts payable | 61.5 |
| | 70.1 |
|
| Accounts payable – associated companies | 5.5 |
| | 6.0 |
|
| Advance customer billings | 25.2 |
| | 15.5 |
|
| Wages and compensation accrued | 26.8 |
| | 30.3 |
|
| Dividends payable | 19.9 |
| | 19.0 |
|
| Customer deposits | 13.0 |
| | 14.8 |
|
| Interest accrued | 7.6 |
| | 8.1 |
|
| Taxes accrued | 25.4 |
| | 43.9 |
|
| Regulatory liabilities | 0.6 |
| | 0.6 |
|
| Other | 18.5 |
| | 41.3 |
|
| Total Current Liabilities | 437.0 |
| | 488.2 |
|
| Deferred Credits and Other Liabilities: | | | |
| Deferred income taxes | 485.2 |
| | 399.8 |
|
| Pension and postretirement benefit costs | 207.8 |
| | 215.3 |
|
| Asset retirement obligations | 72.4 |
| | 71.2 |
|
| Regulatory liabilities | 70.6 |
| | 72.1 |
|
| Other | 48.6 |
| | 42.7 |
|
| Total Deferred Credits and Other Liabilities | 884.6 |
| | 801.1 |
|
|
| |
|
| Total Capitalization and Liabilities | $ | 3,167.5 |
| | $ | 3,105.0 |
|
|
| | | | | | | |
| LACLEDE GAS COMPANY |
| STATEMENTS OF CAPITALIZATION |
| (Dollars in Millions, Except Per Share Amounts) | | | |
| September 30 | 2015 | | 2014 |
| Common Stock Equity: | | | |
| Common stock, par value $1 per share: | | | |
| Authorized – 50,000,000 shares |
|
| | |
| Outstanding – 24,577 shares | 0.1 |
| | 0.1 |
|
| Paid-in capital | 748.2 |
| | 744.0 |
|
| Retained earnings | 291.2 |
| | 265.6 |
|
| Accumulated other comprehensive loss | (1.7 | ) | | (1.9 | ) |
| Total Common Stock Equity | 1,037.8 |
| | 1,007.8 |
|
| Long-Term Debt: | | | |
| First Mortgage Bonds: | | | |
| 2.0% Series, due August 15, 2018 | 100.0 |
| | 100.0 |
|
| 5.5% Series, due May 1, 2019 | 50.0 |
| | 50.0 |
|
| 3.0% Series, due March 15, 2023 | 55.0 |
| | 55.0 |
|
| 3.4% Series, due August 15, 2023 | 250.0 |
| | 250.0 |
|
| 3.4% Series, due March 15, 2028 | 45.0 |
| | 45.0 |
|
| 7.0% Series, due June 1, 2029 | 25.0 |
| | 25.0 |
|
| 7.9% Series, due September 15, 2030 | 30.0 |
| | 30.0 |
|
| 6.0% Series, due May 1, 2034 | 100.0 |
| | 100.0 |
|
| 6.15% Series, due June 1, 2036 | 55.0 |
| | 55.0 |
|
| 4.625% Series, due August 15, 2043 | 100.0 |
| | 100.0 |
|
| Total | 810.0 |
| | 810.0 |
|
| Unamortized discount, net of premium, on long-term debt | (1.9 | ) | | (2.1 | ) |
| Total Long-Term Debt | 808.1 |
| | 807.9 |
|
| Total Capitalization | $ | 1,845.9 |
| | $ | 1,815.7 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| LACLEDE GAS COMPANY |
| STATEMENTS OF COMMON SHAREHOLDER'S EQUITY |
| | | | | | | | | | |
| | Common Stock Outstanding | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income/(Loss) | | |
| (Dollars in Millions, Except Per Share Amounts) | Shares | | Amount | | | | | Total |
| BALANCE SEPTEMBER 30, 2012 | 12,804 |
| | $ | 0.1 |
| | $ | 257.3 |
| | $ | 236.0 |
| | $ | (2.1 | ) | | $ | 491.3 |
|
| Net income | — |
| | — |
| | — |
| | 48.8 |
| | — |
| | 48.8 |
|
| Stock-based compensation costs | — |
| | — |
| | 3.1 |
| | — |
| | — |
| | 3.1 |
|
| Tax benefit – stock compensation | — |
| | — |
| | 0.5 |
| | — |
| | — |
| | 0.5 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock | — |
| | — |
| | — |
| | (47.0 | ) | | — |
| | (47.0 | ) |
| Issuance of common stock to Laclede Group | 11,745 |
| | — |
| | 477.2 |
| | — |
| | — |
| | 477.2 |
|
| BALANCE SEPTEMBER 30, 2013 | 24,549 |
| | $ | 0.1 |
| | $ | 738.1 |
| | $ | 237.8 |
| | $ | (2.1 | ) | | $ | 973.9 |
|
| Net income | — |
| | — |
| | — |
| | 90.1 |
| | — |
| | 90.1 |
|
| Stock-based compensation costs | — |
| | — |
| | 4.2 |
| | — |
| | — |
| | 4.2 |
|
| Tax benefit – stock compensation | — |
| | — |
| | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock | — |
| | — |
| | — |
| | (62.3 | ) | | — |
| | (62.3 | ) |
| Issuance of common stock to Laclede Group | 28 |
| | — |
| | 1.1 |
| | — |
| | — |
| | 1.1 |
|
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 0.2 |
| | 0.2 |
|
| BALANCE SEPTEMBER 30, 2014 | 24,577 |
| | $ | 0.1 |
| | $ | 744.0 |
| | $ | 265.6 |
| | $ | (1.9 | ) | | $ | 1,007.8 |
|
| Net income | — |
| | — |
| | — |
|
| 105.3 |
| | — |
| | 105.3 |
|
| Stock-based compensation costs | — |
| | — |
| | 3.7 |
| | — |
| | — |
| | 3.7 |
|
| Tax benefit – stock compensation | — |
| | — |
| | 0.5 |
| | — |
| | — |
| | 0.5 |
|
| Dividends declared: | | | | | | | | | | | |
| Common stock | — |
| | — |
| | — |
| | (79.7 | ) | | — |
| | (79.7 | ) |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 0.2 |
| | 0.2 |
|
| BALANCE SEPTEMBER 30, 2015 | 24,577 |
| | $ | 0.1 |
| | $ | 748.2 |
| | $ | 291.2 |
| | $ | (1.7 | ) | | $ | 1,037.8 |
|
|
| | | | | | | | | | | |
| LACLEDE GAS COMPANY |
| STATEMENTS OF CASH FLOWS |
| (In Millions) | | | | | |
| Years Ended September 30 | 2015 | | 2014 | | 2013 |
| Operating Activities: | | | | | |
| Net Income | $ | 105.3 |
| | $ | 90.1 |
| | $ | 48.8 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 82.6 |
| | 78.5 |
| | 48.3 |
|
| Deferred income taxes and investment tax credits | 45.4 |
| | 35.6 |
| | 22.2 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable – net | 9.9 |
| | (21.5 | ) | | 6.7 |
|
| Unamortized purchased gas adjustments | 41.1 |
| | (36.4 | ) | | 23.1 |
|
| Deferred purchased gas costs | (19.8 | ) | | 13.9 |
| | 13.3 |
|
| Accounts payable | (11.4 | ) | | 6.8 |
| | 16.4 |
|
| Delayed / advance customer billings – net | 17.9 |
| | (19.1 | ) | | (8.3 | ) |
| Taxes accrued | (14.6 | ) | | 10.0 |
| | 1.0 |
|
| Inventories | 51.2 |
| | (26.4 | ) | | (16.2 | ) |
| Other assets and liabilities | (32.8 | ) | | (3.3 | ) | | (29.4 | ) |
| Other | 2.8 |
| | 2.8 |
| | (0.4 | ) |
| Net cash provided by operating activities | 277.6 |
| | 131.0 |
| | 125.5 |
|
| Investing Activities: | | | | | |
| Capital expenditures | (198.6 | ) | | (163.0 | ) | | (128.5 | ) |
| Acquisition of MGE | — |
| | 23.9 |
| | (975.0 | ) |
| Other | 2.9 |
| | 4.1 |
| | (1.3 | ) |
| Net cash used in investing activities | (195.7 | ) | | (135.0 | ) | | (1,104.8 | ) |
| Financing Activities: | | | | | |
| Issuance of first mortgage bonds | — |
| | — |
| | 550.0 |
|
| Repayment of long-term debt | — |
| | (80.0 | ) | | (25.0 | ) |
| Issuance (repayment) of short-term debt - net | (5.7 | ) | | 164.6 |
| | 33.9 |
|
| Borrowings from Laclede Group | 18.4 |
| | 276.1 |
| | 172.0 |
|
| Repayment of borrowings from Laclede Group | (18.4 | ) | | (322.7 | ) | | (162.4 | ) |
| Dividends paid | (78.7 | ) | | (57.2 | ) | | (42.4 | ) |
| Issuance of common stock to Laclede Group | — |
| | 1.2 |
| | 477.2 |
|
| Other | 0.5 |
| | 1.8 |
| | (2.5 | ) |
| Net cash (used in) provided by financing activities | (83.9 | ) | | (16.2 | ) | | 1,000.8 |
|
| Net (Decrease) Increase in Cash and Cash Equivalents | (2.0 | ) | | (20.2 | ) | | 21.5 |
|
| Cash and Cash Equivalents at Beginning of Year | 3.7 |
| | 23.9 |
| | 2.4 |
|
| Cash and Cash Equivalents at End of Year | $ | 1.7 |
| | $ | 3.7 |
| | $ | 23.9 |
|
| | | | | | |
| Supplemental disclosure of cash (paid) refunded for: | | | | | |
| Interest | $ | (31.0 | ) | | $ | (36.4 | ) | | $ | (25.7 | ) |
| Income taxes | 0.7 |
| | (0.2 | ) | | 7.6 |
|
|
| | | | | | | | | | | |
| ALABAMA GAS CORPORATION |
| STATEMENTS OF INCOME |
| (In Millions) | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, | | Year Ended December 31, |
| 2015 | | 2014 | | 2013 |
| Operating Revenues: | | | | | |
| Utility | $ | 479.2 |
| | $ | 417.2 |
| | $ | 533.3 |
|
| Total Operating Revenues | 479.2 |
| | 417.2 |
| | 533.3 |
|
| Operating Expenses: | | | | | |
| Utility | | | | | |
| Natural and propane gas | 171.5 |
| | 184.5 |
| | 215.5 |
|
| Other operation and maintenance expenses | 138.0 |
| | 107.5 |
| | 143.1 |
|
| Depreciation and amortization | 47.3 |
| | 34.4 |
| | 43.9 |
|
| Taxes, other than income taxes | 33.2 |
| | 28.6 |
| | 37.1 |
|
| Total Operating Expenses | 390.0 |
| | 355.0 |
| | 439.6 |
|
| Operating Income | 89.2 |
| | 62.2 |
| | 93.7 |
|
| Other Income - Net | 2.0 |
| | 2.2 |
| | 14.0 |
|
| Interest Charges: | | | | | |
| Interest on long-term debt | 11.6 |
| | 10.1 |
| | 13.5 |
|
| Other interest charges | 2.3 |
| | 1.4 |
| | 2.1 |
|
| Total Interest Charges | 13.9 |
| | 11.5 |
| | 15.6 |
|
| Income Before Income Taxes | 77.3 |
| | 52.9 |
| | 92.1 |
|
| Income Tax Expense | 29.3 |
| | 19.9 |
| | 34.7 |
|
| Net Income | $ | 48.0 |
| | $ | 33.0 |
| | $ | 57.4 |
|
|
| | | | | | | |
| ALABAMA GAS CORPORATION |
| BALANCE SHEETS |
| (In Millions) | | | |
| September 30 | 2015 | | 2014 |
| ASSETS | | | |
| Utility Plant | $ | 1,655.4 |
| | $ | 1,525.1 |
|
| Less: Accumulated depreciation and amortization | 717.0 |
| | 626.4 |
|
| Net Utility Plant | 938.4 |
| | 898.7 |
|
| Current Assets: | | | |
| Cash and cash equivalents | 7.2 |
| | 5.6 |
|
| Accounts receivable: | | | |
| Utility | 34.7 |
| | 39.0 |
|
| Other | 5.2 |
| | 5.1 |
|
| Allowance for doubtful accounts | (4.2 | ) | | (5.1 | ) |
| Inventories: | | | |
| Natural gas | 40.4 |
| | 48.0 |
|
| Materials and supplies | 5.4 |
| | 5.1 |
|
| Regulatory assets | 11.4 |
| | 8.8 |
|
| Deferred income tax | 6.2 |
| | 2.3 |
|
| Prepayments and other | 4.6 |
| | 1.6 |
|
| Total Current Assets | 110.9 |
| | 110.4 |
|
| Deferred Charges: | | | |
| Regulatory assets | 163.6 |
| | 90.6 |
|
| Deferred income tax | 248.4 |
| | 277.8 |
|
| Other | 57.7 |
| | 47.1 |
|
| Total Deferred Charges | 469.7 |
| | 415.5 |
|
| Total Assets | $ | 1,519.0 |
| | $ | 1,424.6 |
|
|
| | | | | | | |
| ALABAMA GAS CORPORATION |
| BALANCE SHEETS (continued) |
| (Millions) | | | |
| September 30, | 2015 | | 2014 |
| CAPITALIZATION AND LIABILITIES | | | |
| Capitalization: | | | |
| Common stock equity | $ | 874.6 |
| | $ | 849.6 |
|
| Long-term debt | 170.0 |
| | 249.8 |
|
| Total Capitalization | 1,044.6 |
| | 1,099.4 |
|
| Current Liabilities: | | | |
| Current portion of long-term debt | 80.0 |
| | — |
|
| Notes payable | 31.0 |
| | 16.0 |
|
| Accounts payable | 21.8 |
| | 34.2 |
|
| Accounts payable – associated companies | 0.2 |
| | 0.4 |
|
| Advance customer billings | 19.1 |
| | 16.7 |
|
| Wages and compensation accrued | 5.8 |
| | 5.7 |
|
| Customer deposits | 19.1 |
| | 19.1 |
|
| Interest accrued | 3.5 |
| | 3.9 |
|
| Unamortized purchase gas adjustment | 28.2 |
| | 22.4 |
|
| Taxes accrued | 26.0 |
| | 30.0 |
|
| Regulatory liabilities | 31.8 |
| | 40.7 |
|
| Other | 5.4 |
| | 6.8 |
|
| Total Current Liabilities | 271.9 |
| | 195.9 |
|
| Deferred Credits and Other Liabilities: | | | |
| Pension and postretirement benefit costs | 45.6 |
| | 29.6 |
|
| Asset retirement obligations | 86.6 |
| | 27.7 |
|
| Regulatory liabilities | 48.7 |
| | 53.7 |
|
| Other | 21.6 |
| | 18.3 |
|
| Total Deferred Credits and Other Liabilities | 202.5 |
| | 129.3 |
|
|
| |
|
| Total Capitalization and Liabilities | $ | 1,519.0 |
| | $ | 1,424.6 |
|
|
| | | | | | | |
| ALABAMA GAS CORPORATION |
| STATEMENTS OF CAPITALIZATION |
| (Dollars in Millions, Except Per Share Amounts) | | | |
| September 30 | 2015 | | 2014 |
| Common Stock Equity: | | | |
| Common stock, par value $1 per share, and paid-in capital: | | | |
| Authorized – 3,000,000 shares | | | |
| Outstanding – 1,972,052 shares | $ | 480.9 |
| | $ | 503.9 |
|
| Retained earnings | 393.7 |
| | 345.7 |
|
| Total Common Stock Equity | 874.6 |
| | 849.6 |
|
| Long-Term Debt: | | | |
| 5.368% Notes, due December 1, 2015 | — |
| | 80.0 |
|
| 5.2% Notes, due January 15, 2020 | 40.0 |
| | 40.0 |
|
| 3.86% Notes, due December 23, 2021 | 50.0 |
| | 50.0 |
|
| 3.21% Notes, due September 15, 2025 | 35.0 |
| | — |
|
| 5.7% Notes, due January 15, 2035 | — |
| | 34.8 |
|
| 5.9% Notes, due January 15, 2037 | 45.0 |
| | 45.0 |
|
| Total Long-Term Debt | 170.0 |
| | 249.8 |
|
| Total Capitalization | $ | 1,044.6 |
| | $ | 1,099.4 |
|
|
| | | | | | | | | | | | | | | | | | |
| ALABAMA GAS CORPORATION |
| STATEMENTS OF COMMON SHAREHOLDER'S EQUITY |
| | | | | | | | |
| | Common Stock Outstanding | | Paid-in Capital | | Retained Earnings | | |
| (Dollars in Millions, Except Per Share Amounts) | Shares | | Amount | | | | Total |
| BALANCE DECEMBER 31, 2012 | 1,972,052 |
| | $ | — |
| | $ | 34.5 |
| | $ | 326.0 |
| | $ | 360.5 |
|
| Net income | — |
| | — |
| | — |
| | 57.4 |
| | 57.4 |
|
| Dividends declared: | | | | | | | | | |
| Common stock | — |
| | — |
| | — |
| | (33.3 | ) | | (33.3 | ) |
| BALANCE DECEMBER 31, 2013 | 1,972,052 |
| | — |
| | 34.5 |
| | 350.1 |
| | 384.6 |
|
| Net income | — |
| | — |
| | — |
| | 33.0 |
| | 33.0 |
|
| Dividends declared: | | | | | | | | | |
| Common stock | — |
| | — |
| | — |
| | (37.4 | ) | | (37.4 | ) |
| Purchase accounting adjustments | — |
| | — |
| | 469.4 |
| | — |
| | 469.4 |
|
| BALANCE SEPTEMBER 30, 2014 | 1,972,052 |
| | — |
| | 503.9 |
| | 345.7 |
| | 849.6 |
|
| Net income | — |
| | — |
| | — |
| | 48.0 |
| | 48.0 |
|
| Purchase accounting adjustments | — |
| | | | 4.0 |
| | — |
| | 4.0 |
|
| Return of capital to Laclede Group | — |
| | — |
| | (27.0 | ) | | — |
| | (27.0 | ) |
| BALANCE SEPTEMBER 30, 2015 | 1,972,052 |
| | $ | — |
| | $ | 480.9 |
| | $ | 393.7 |
| | $ | 874.6 |
|
|
| | | | | | | | | | | |
| ALABAMA GAS CORPORATION |
| STATEMENTS OF CASH FLOWS |
| | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, | | Year Ended December 31, |
| (In Millions) | 2015 | | 2014 | | 2013 |
| Operating Activities: | | | | | |
| Net Income | $ | 48.0 |
| | $ | 33.0 |
| | $ | 57.4 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: | | | | | |
| Depreciation, amortization and accretion | 47.3 |
| | 34.4 |
| | 43.9 |
|
| Deferred income taxes and investment tax credits | 29.2 |
| | 4.0 |
| | 15.0 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable – net | (9.1 | ) | | 26.4 |
| | (23.2 | ) |
| Unamortized purchased gas adjustments | 5.8 |
| | 24.8 |
| | 40.3 |
|
| Accounts payable | (10.4 | ) | | (11.5 | ) | | (3.1 | ) |
| Advance customer billings – net | 2.4 |
| | (0.3 | ) | | (2.7 | ) |
| Taxes accrued | (4.0 | ) | | 1.9 |
| | 3.9 |
|
| Inventories | 7.2 |
| | (11.8 | ) | | — |
|
| Other assets and liabilities | (18.0 | ) | | 17.1 |
| | 9.9 |
|
| Other | 2.0 |
| | (3.0 | ) | | (11.4 | ) |
| Net cash provided by operating activities | 100.4 |
| | 115.0 |
| | 130.0 |
|
| Investing Activities: | | | | | |
| Capital expenditures | (85.8 | ) | | (46.2 | ) | | (86.0 | ) |
| Proceeds from the sale of assets | — |
| | 0.8 |
| | 13.8 |
|
| Other | (1.0 | ) | | — |
| | — |
|
| Net cash used in investing activities | (86.8 | ) | | (45.4 | ) | | (72.2 | ) |
| Financing Activities: | | | | | |
| Issuance of first mortgage bonds | 35.0 |
| | — |
| | — |
|
| Repayment of long-term debt | (34.8 | ) | | — |
| | — |
|
| Issuance (repayments) of short-term debt - net | 15.0 |
| | (34.0 | ) | | (27.0 | ) |
| Return of capital to Laclede Group | (27.0 | ) | | — |
| | — |
|
| Dividends paid | — |
| | (37.4 | ) | | (33.3 | ) |
| Other | (0.2 | ) | | 4.4 |
| | (0.1 | ) |
| Net cash used in financing activities | (12.0 | ) | | (67.0 | ) | | (60.4 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | 1.6 |
| | 2.6 |
| | (2.6 | ) |
| Cash and Cash Equivalents at Beginning of Period | 5.6 |
| | 3.0 |
| | 5.6 |
|
| Cash and Cash Equivalents at End of Period | $ | 7.2 |
| | $ | 5.6 |
| | $ | 3.0 |
|
| | | | | | |
| Supplemental disclosure of cash (paid) refunded for: | | | | | |
| Interest | $ | (12.3 | ) | | $ | (9.6 | ) | | $ | (13.5 | ) |
| Income taxes | — |
| | (20.4 | ) | | (23.1 | ) |
THE LACLEDE GROUP, INC., LACLEDE GAS COMPANY, AND ALABAMA GAS CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Dollars in millions, except per share and per gallon amounts)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION Various environmental laws–These notes are an integral part of the accompanying audited financial statements of The Laclede Group, Inc. (Laclede Group or the Company), as well as Laclede Gas Company (Laclede Gas or the Missouri Utilities) and regulations apply toAlabama Gas Corporation (Alagasco or the Alabama Utility). Laclede Gas, which includes the operations of Energen ResourcesMissouri Gas Energy (MGE), and Alagasco. Historically,Alagasco are wholly owned subsidiaries of the costCompany. Collectively, Laclede Gas and Alagasco are referred to as the Utilities. The accompanying audited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of environmental compliance has not materially affected the Company’sAmerica (GAAP).
The consolidated financial position, results of operations, and cash flows of Laclede Group are primarily derived from the financial position, results of operations, and cash flows of the Utilities. In compliance with GAAP, transactions between the Utilities and their affiliates, as well as intercompany balances on the Utilities' balance sheets, have not been eliminated from the Utilities' financial statements. The Company's August 31, 2014 acquisition of Alagasco and Laclede Gas' September 1, 2013 acquisition of MGE are included in the results of operations since their respective acquisition dates and impact the comparability of the financial statement periods presented for the Company and Laclede Gas. For a further discussion of the acquisitions, see Note 2, Acquisitions. The Utilities are regulated natural gas distribution utilities. Due to the seasonal nature of the Utilities, Laclede Group's earnings are typically concentrated during the heating season of November through April each fiscal year. Effective September 2, 2014, Alagasco amended its bylaws to change Alagasco's fiscal year from beginning January 1 and ending on December 31, to beginning October 1 and ending on September 30. As a result, the financial statements covering the nine-month period from January 1, 2014 through September 30, 2014 (the “transition period”) were included in the Alagasco’s transition report on Form 10-K/T for such period and are presented in the financial statements and notes herein. The period beginning January 1, 2013 through December 31, 2013 is referred to as “calendar 2013.” For the fiscal year 2015, Alagasco's financial statements cover the fiscal year October 1, 2014 to September 30, 2015.
NATURE OF OPERATIONS – The Laclede Group, Inc. (NYSE: LG), headquartered in St. Louis, Missouri, is a public utility holding company. The Company has two operating segments: Gas Utility and Gas Marketing. The Gas Utility segment consists of the regulated natural gas distribution operations of the Company and is the core business segment of Laclede Group in terms of revenue and earnings generation. The Gas Utility segment is comprised of the operations of the Missouri Utilities and the Alabama Utility and serves St. Louis and eastern Missouri, Kansas City and western Missouri (through MGE), and central and northern Alabama. Laclede Group’s primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries are described in Note 14, Information by Operating Segment, and are reported as Other. USE OF ESTIMATES – The preparation of financial statements in conformity with GAAP 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 the Missouri Utilities are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC). The accounts of Alagasco are maintained in accordance with the Uniform System of Accounts prescribed by the Alabama Public Service Commission (APSC), which system substantially conforms to that prescribed by the 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.
For Laclede Gas, 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 2015, annual depreciation and amortization expense averaged 3.0% of the original cost of depreciable and amortizable property, compared to 3.0% and 3.2% in both fiscal years 2014 and 2013, respectively.
Laclede Gas' capital expenditures were $198.6, $163.0 and $128.5 for fiscal years 2015, 2014, and 2013, respectively. Additionally, Laclede Gas had recorded accruals for capital expenditures totaling $9.6 at September 30, 2015, $3.0 at September 30, 2014, and $4.7 at September 30, 2013.
For Alagasco, depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1%. As required by the ASPC, Alagasco performed another depreciation study in 2015. The composite depreciation rate from this study was also approximately 3.1%. Alagasco anticipates refunding approximately $10.8 of refundable negative salvage costs through lower tariff rates over the next twelve months.
Related to the lower depreciation rates, an estimated $27.0 of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a four year period through 2019.
Alagasco's capital expenditures were $85.8, $46.2 and $86.0 for fiscal years 2015, 2014, and 2013, respectively. Additionally, Alagasco recorded accruals for capital expenditures totaling $3.1 at September 30, 2015, $5.0 at September 30, 2014 and $5.5 at December 31, 2013.
Accrued capital expenditures are excluded from the capital expenditures included in the statements of cash flows of the Company, Laclede Gas and Alagasco.
ASSET RETIREMENT OBLIGATIONS – Laclede Group, Laclede Gas, and Alagasco record 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, Laclede Gas and Alagasco record 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 Alagasco and Laclede Gas’ distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC and APSC, Laclede Gas and Alagasco accrue future asset removal costs associated with their 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 or assets. When the Utilities retire depreciable utility plant and equipment, they charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. 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. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is deducted from the rate base upon which the Utilities have the opportunity to earn their allowed rates of return. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.
The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, as reported in the balance sheets.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2015 | | 2014 |
| Asset retirement obligations, beginning of year | $ | 99.2 |
| | $ | 74.6 |
| | $ | 71.2 |
| | $ | 74.3 |
| | $ | 27.7 |
| | $ | 27.5 |
|
| Liabilities incurred during the period | 2.3 |
| | 0.5 |
| | 0.6 |
| | 0.5 |
| | 1.7 |
| | 0.5 |
|
| Liabilities settled during the period | (2.0 | ) | | (1.5 | ) | | (1.9 | ) | | (1.5 | ) | | (0.1 | ) | | (0.1 | ) |
| Accretion | 4.5 |
| | 3.7 |
| | 3.4 |
| | 3.7 |
| | 1.1 |
| | 0.7 |
|
| Revisions in estimated cash flows | 55.2 |
| | (5.8 | ) | | (0.9 | ) | | (5.8 | ) | | 56.2 |
| | (0.9 | ) |
| Addition of Alagasco asset retirement obligation | — |
| | 27.7 |
| | — |
| | — |
| | — |
| | — |
|
| Asset retirement obligations, end of year | $ | 159.2 |
| | $ | 99.2 |
| | $ | 72.4 |
| | $ | 71.2 |
| | $ | 86.6 |
| | $ | 27.7 |
|
REGULATED OPERATIONS – The Utilities account for their 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. In addition, 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. As authorized by the MoPSC, the Purchased Gas Adjustment (PGA) clauses allow the Missouri Utilities to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. Similarly, Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, which permits the pass-through to customers of changes in the cost of gas supply. Regulatory assets and liabilities related to the PGA clauses and the GSA rider are both labeled Unamortized Purchased Gas Adjustments herein. See additional discussion on regulated operations in Note 15 - Regulatory Matters. NATURAL GAS AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a LIFO basis and inventory of propane gas in storage is priced on a FIFO basis. For MGE and Alagasco, inventory of natural gas in storage is priced on the weighted average cost basis. The replacement cost of Laclede Gas' natural gas for current use at September 30, 2015 and September 30, 2014 was less than the LIFO cost by $20.4 and $11.4, respectively. The carrying value of Laclede Gas' inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's 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 acquisitions of MGE and Alagasco were accounted for by Laclede Gas and Laclede Group 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 acquisitions of MGE and Alagasco, refer to Note 2, Acquisitions. 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. In accordance with ASC Topic 805, “Business Combinations,” Laclede Gas recorded adjustments during the measurement period ended August 31, 2014 to finalize the allocation of purchase price for the 2013 acquisition of MGE. As part of the Alagasco acquisition (discussed in Note 2, Acquisitions), the Company initially recorded $727.6 of goodwill as of September 30, 2014. As part of the final reconciliation of net assets, $8.2of additional consideration was paid by the Company to Energen Corporation (Energen) on January 6, 2015. This payment, offset partly by other immaterial purchase price adjustments, resulted in goodwill of $735.8 as of September 30, 2015 related to the Alagasco acquisition. The Alagasco related goodwill is included in Other for segment reporting purposes. Alagasco has no goodwill on its balance sheet as push down accounting was not applied. For Laclede Group and Laclede Gas, goodwill related to the 2013 acquisition of MGE, included in the Gas Utility segment, was $210.2 as of September 30, 2015 and 2014.
Laclede Group and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. The goodwill impairment test compares the fair value of the determined reporting unit to its carrying amount, including goodwill. Laclede Group has one reporting unit, which is the Gas Utility segment, and Laclede Gas has one reporting unit, which is the entire Laclede Gas Company. At July 1, 2015 and 2014, Laclede Group and Laclede Gas each applied a quantitative goodwill evaluation model to its reporting unit and concluded goodwill was not impaired because the fair value exceeded the carrying amount.
IMPAIRMENT OF LONG-LIVED ASSETS – Long-lived assets classified as held and used are evaluated for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, The Company recognizes an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which the Company determines an asset meets held-for-sale criteria, an impairment charge is recorded to the extent the book value exceeds its fair value less cost to sell.
REVENUE RECOGNITION – The Utilities read meters and bill customers on monthly cycles. The Missouri Utilities record their 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 for Laclede Gas at September 30, 2015 and 2014 were $27.6 and $29.4, respectively.
Alagasco records natural gas distribution revenues in accordance with the tariff established by the APSC. The amount of accrued unbilled revenues, which are not recorded as revenues until billed, for Alagasco at September 30, 2015 and 2014 were $6.4 and $5.2, respectively. All related costs and margins are also deferred.
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 10, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions 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 –
Laclede Gas
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, Laclede Gas 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:
Laclede Gas 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 Laclede Gas 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.
Laclede Gas is 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. Laclede Gas' eastern Missouri service territory is also 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 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 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 Consolidated Statements of Income and under Operating Revenues on Laclede Gas' Statements of Income.
Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA clause 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 following tables, shown for each service territory for which the PGA clauses were approved by the MoPSC.
|
| | |
| Laclede Gas Company (eastern Missouri) | | |
| Pre-tax Income | Customer Share | Company Share |
| First $2.0* | 100% | —% |
| Next $2.0 | 80% | 20% |
| Next $2.0 | 75% | 25% |
| Amounts exceeding $6.0 | 70% | 30% |
| * Customer share reverts to 85% and company share reverts to 15% in 2017. | | |
| | | |
| MGE (western Missouri) | | |
| Pre-tax Income | Customer Share | Company Share |
| First $1.2 | 85% | 15% |
| Next $1.2 | 80% | 20% |
| Next $1.2 | 75% | 25% |
| Amounts exceeding $3.6 | 70% | 30% |
Alagasco
Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA rider, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather-related conditions that may affect customer usage are not included in the temperature adjustment.
INCOME TAXES – Laclede Group and its subsidiaries account for income taxes under the asset and liabilities method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and the respective tax basis and for tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effects on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income or loss for a non-regulated company, and in a regulatory asset or regulatory liability for a regulated company. A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.
The Company accounts for uncertain tax positions in accordance with authoritative guidance. The authoritative guidance addresses the determination of whether tax benefits claimed, or expected to be claimed, on a tax return should be recorded in the financial statements. Laclede Group may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Tax-related interest and penalties, if any, are classified as a liability on the balance sheets.
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. Outstanding checks on the Company’s and Utilities' 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 balance sheets. Changes in book overdrafts are reflected as Operating Activities in the statements of cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.
NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under oversightthe terms of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil andarrangements, LER purchases natural gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.
During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site. In 2008, Energen hired a third party and delivers that natural gas to transport approximately 3,000 gallonsthe pipeline company for the right to receive the same quantity of non-hazardous wastewaternatural 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 Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanupLER, concurrent with the sale of the Site.
Alagasconatural gas to a third party, the related natural gas receivable is expensed in the chainConsolidated Statements of title of nine former manufacturedIncome. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) natural gas plant sites, four of which it still owns,futures, options, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, shouldswap contracts or fixed price sales agreements to protect against market changes in future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, Alagasco and the current site owner.
In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of December 31, 2013.
Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicatessales prices.
bothEARNINGS 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 loss is probable and the amountparticipating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relationCompany’s stock-based compensation awards pay non-forfeitable dividends to the respective financial positionsparticipants 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 Energencommon 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 equity units, non-participating stock options and its affiliates. It shouldtime-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be noted, however, that there is uncertaintyantidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the valuationcalculation of pending claims and prediction of litigation results.
On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation and Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.
Energen Resources previously disclosed an adverse judgment relatingdiluted earnings per share to the ownershipextent the underlying performance and/or market conditions are satisfied (a) prior to the end of the Company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. Upon a Motion to Reconsider,reporting period or (b) would be satisfied if the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases. The Summary Judgment Order has been appealed by the other party.
New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department)end of the State of New Mexico relating to its audit, conducted on behalf ofreporting period were the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the termsend of the related leases.contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 4, Earnings Per Common Share.
As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount ofGROSS RECEIPTS AND SALES TAXES $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent– Gross receipts taxes associated with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assistnatural gas utility services are imposed on the Company, Laclede Gas, and Alagasco and billed to its customers. The revenue and expense amounts are recorded gross in evaluating the ONRR Order"Operating Revenues" and "Taxes, other than income taxes" lines, respectively, in the Department’s findings. Management is unable, at this time, to determine a rangestatements of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2013.income.
The following table presents gross receipts taxes recorded:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Laclede Group | $ | 97.3 |
| | $ | 77.5 |
| | $ | 40.8 |
|
| Laclede Gas | 74.5 |
| | 76.3 |
| | 40.8 |
|
| Alagasco | 22.6 |
| | 20.6 |
| | 25.9 |
|
| All Other | 0.2 |
| | 0.2 |
| | — |
|
Sales taxes imposed on applicable Alagasco leases the Company’s headquarters building over a 25-year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Effective July 1, 2013, Alagasco subleased the Company’s headquartersLaclede Gas sales are billed to Energen. Prior to July 2013, approximately 49 percent of the total headquarters lease payments were charged to Energen. As of July 2013, approximately 77 percent of the total headquarters lease payments are charged to Energen due to an increase in office space utilized by Energen. Alagasco recognizes Energen’s payment of rent expense in other income with an offset in other expense.customers. These amounts are not recorded in the statements of income but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the balance sheets.
TRANSACTIONS WITH AFFILIATES –Transactions between the Company and its affiliates have been eliminated onfrom the consolidated financial statements of income.Laclede Group. In addition to the normal intercompany shared services transactions, there were approximately $2.8 of employee-related integration transactions between Alagasco entered into a new lease forand Laclede Group in the current Alagasco corporate headquarters in July 2013 which is classified as an operating lease. Energen’s total lease payments included as operating lease expense were $25.0 million, $20.9 million and $19.1 million foryear ended September 30, 2015. Laclede Gas had the years ended December 31, 2013, 2012 and 2011, respectively. Minimum future rental payments required after 2013 under leasesfollowing transactions with initial or remaining noncancelable lease terms in excess of one year are as follows:affiliates:
|
| | | | | |
Years Ending December 31, (in thousands) |
| 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and thereafter |
| $5,270 | $4,940 | $4,391 | $3,980 | $2,409 | $10,637 |
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Sales of natural gas from Laclede Gas to LER | $ | 4.0 |
| | $ | 5.1 |
| | $ | 10.4 |
|
| Sales of natural gas from LER to Laclede Gas | 74.1 |
| | 89.1 |
| | 34.6 |
|
| Transportation services provided by Laclede Pipeline Company to Laclede Gas | 1.0 |
| | 1.0 |
| | 1.0 |
|
| Insurance services provided by Laclede Risk Services, Inc. to Laclede Gas | 1.0 |
| | 0.6 |
| | 0.7 |
|
| CNG sales from Laclede Gas to Laclede Venture Corporation | 0.1 |
| | — |
| | — |
|
Alagasco’s total payments related to leases included as operating expense were $2.4 million, $2.1 millionACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS and $2.3 million for– Trade accounts receivable are recorded at the years ended December 31, 2013, 2012 and 2011, respectively. These amounts are net of approximately $0.7 million, $1.0 million and $1.0 million of lease expense paid by Energen in 2013, 2012 and 2011, respectively. Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
|
| | | | | |
Years Ending December 31, (in thousands) |
| 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and thereafter |
| $4,291 | $4,062 | $3,994 | $3,979 | $2,409 | $10,637 |
Included in the table above are approximately $16.2 million of payments associated with leasingdue from customers, including unbilled amounts. Estimates of the Company’s headquarters, whichcollectability of trade accounts receivable are expectedbased 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 reimbursed to Alagascouncollectible. Laclede Group's provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by Energen through the remaining term ofMoPSC and the related lease.APSC.
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial Instruments:FINANCE RECEIVABLES The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $1,420.7 million and $1,255.8 million and has a carrying value of $1,403.9 million and $1,154.0 million at December 31, 2013 and 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $258.8 million and $284.7 million and has a carrying value of $249.9 million and $250.0 million at December 31, 2013 and 2012, respectively. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.
Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 with an aggregate purchase price of $0.5 million and a market value of $0.6 million.
Finance Receivables:– Alagasco finances third-partythird party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2013September 30, 2015 and 2012, Alagasco’sSeptember 30, 2014, the Company’s finance receivable totaled approximately $10.8 million$11.2 and $10.7 million,$10.9, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 84 months. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a
case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-partythird party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-partythird party collection agency. Alagasco had finance receivables past due 90 days or more of $0.4 million$0.4 and $0.5 million$0.3 as of December 31, 2013September 30, 2015 and 2012,September 30, 2014, respectively.
The following table sets forth a summary of changes in the Alagasco recorded an allowance for credit losses as follows:
|
| | | |
| (in thousands) | |
| Allowance for credit losses as of December 31, 2011 | $ | 421 |
|
| Provision | 49 |
|
| Allowance for credit losses as of December 31, 2012 | 470 |
|
| Provision | (47 | ) |
| Allowance for credit losses as of December 31, 2013 | $ | 423 |
|
at September 30, 2015 and September 30, 2014 of $0.4 and $0.3, respectively.
Risk Management:GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES At December 31, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements.– 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 riskthe measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.
The levels of the hierarchy are described below:
Level 1 – Unadjusted quoted prices in active markets for economic lossidentical 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 creditworthinessbest 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 counterparties. Energen Resourcesplacement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 8, Fair Value of Financial Instruments, Note 9, Fair Value Measurements, and Note 13, Pension Plans and Other Postretirement Benefits. 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 3, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans. REVISIONS TO PRIOR FINANCIAL STATEMENTS – In the Statements of Common Shareholder’s Equity in Alagasco's most recent Annual Report on Form 10-KT, $31.7 was misclassified between common stock and paid-in capital, with no impact on total shareholder’s equity. The prior period balances have been corrected in a net gain position with seven of its active counterparties andthis filing. In addition, certain amounts in a net loss positionthe prior period have been adjusted to conform with the remaining six at current period presentation for Laclede Group, Laclede Gas and Alagasco. Those adjustments primarily related to classification between current and noncurrent assets and liabilities and between categories of regulatory assets and liabilities. The Company considered the impact of the adjustments on prior period results and determined that the amounts were not material to those periods.
NEW ACCOUNTING STANDARDS – In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This standard is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principles-based approach to the recognition of revenue. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. The standard outlines a five-step model and related application guidance, which replaces most existing revenue recognition guidance. ASU No. 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which made the guidance in ASU No. 2014-09 effective for fiscal years beginning after December 31, 2013.15, 2017, and interim periods within those years, but companies may choose to adopt it one year earlier. The two largest counterparty net gain positions at Company, Laclede Gas and Alagasco are currently assessing the available transition methods and the potential impacts of the standard, which must be adopted by the first quarter of fiscal 2019.December 31, 2013
In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. Currently different balance sheet presentation requirements exist for debt issuance costs and debt discount and premium. Debt issuance costs are recorded as a deferred charge (asset), Macquarie Bank Limitedwhile debt discount and J Aron & Company, constituted approximately $8.6 million and $5.3 milliondebt premium costs are recorded as a liability adjustment. This standard will require debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of Energen Resources’ total net loss on fair value of derivatives.that debt liability, consistent with debt
discounts. The following table details the fair valuesrecognition and measurement guidance for debt issuance costs is not affected by this standard, and ASU No. 2015-15, issued in 2015, clarifies that ASU No. 2015-03 does not address presentation or subsequent measurement of commodity contracts by business segment ondebt issuance costs related to line-of-credit arrangements. The new guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those years, with early adoption permitted. The application of this standard will be retrospective, wherein the balance sheets:
|
| | | | | | | |
| (in thousands) | December 31, 2013 |
| | Oil and Gas Operations | | Natural Gas Distribution |
Total |
| Derivative assets or (liabilities) not designated as hedging instruments | | | |
| Accounts receivable | 36,224 |
| | — |
| 36,224 |
|
| Long-term asset derivative instruments | 7,992 |
| | — |
| 7,992 |
|
| Total derivative assets | 44,216 |
| | — |
| 44,216 |
|
| Accounts receivable | (18,761 | ) | * | — |
| (18,761 | ) |
| Long-term asset derivative instruments | (2,553 | ) | * | — |
| (2,553 | ) |
| Accounts payable | (30,302 | ) | | — |
| (30,302 | ) |
| Total derivative liabilities | (51,616 | ) | | — |
| (51,616 | ) |
| Total derivatives not designated | (7,400 | ) | | — |
| (7,400 | ) |
|
| | | | | | | | | | |
| (in thousands) | December 31, 2012 |
| | Oil and Gas Operations | | Natural Gas Distribution |
Total |
| Derivative assets or (liabilities) designated as hedging instruments | | | | |
| Accounts receivable | $ | 87,514 |
| | $ | — |
| $ | 87,514 |
|
| Long-term asset derivative instruments | 37,954 |
| | — |
| 37,954 |
|
| Total derivative assets | 125,468 |
| | — |
| 125,468 |
|
| Accounts receivable | (37,326 | ) | * | — |
| (37,326 | ) |
| Long-term asset derivative instruments | (6,810 | ) | * | — |
| (6,810 | ) |
| Long-term liability derivative instruments | (8,726 | ) | | — |
| (8,726 | ) |
| Total derivative liabilities | (52,862 | ) | | — |
| (52,862 | ) |
| Total derivatives designated | 72,606 |
| | — |
| 72,606 |
|
| Derivative assets or (liabilities) not designated as hedging instruments | | | |
| Accounts receivable | 14,604 |
| | — |
| 14,604 |
|
| Long-term asset derivative instruments | 9,433 |
| | — |
| 9,433 |
|
| Total derivative assets | 24,037 |
| | — |
| 24,037 |
|
| Accounts payable | — |
| | (2,593 | ) | (2,593 | ) |
| Long-term liability derivative instruments | (874 | ) | | — |
| (874 | ) |
| Total derivative liabilities | (874 | ) | | (2,593 | ) | (3,467 | ) |
| Total derivatives not designated | 23,163 |
| | (2,593 | ) | 20,570 |
|
| Total derivatives | $ | 95,769 |
| | $ | (2,593 | ) | $ | 93,176 |
|
* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed withsheet of each individual period presented will be adjusted to reflect the same counterparty under a master netting arrangement.
period-specific impacts of applying the new guidance. The Company, had a net $8.2 millionLaclede Gas and a net $28.4 million deferred tax liability included in currentAlagasco are currently assessing the timing and noncurrent deferred income taxes onimpacts of adopting this standard, which must be adopted by the consolidated balance sheets related to derivative items included in other comprehensive income asfirst quarter of December 31, 2013fiscal year 2017.
In July 2015, the FASB issued ASU No. 2015-11 – Inventory: Simplifying the Measurement of Inventory. This standard provides guidance for the subsequent measurement of inventory and 2012, respectively.
The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:
|
| | | | | | | | | | |
Years ended December 31, (in thousands) | Location on Income Statement | 2013 | 2012 | 2011 |
| Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($6,660), $40,720 and $41,399 | — | $ | (10,866 | ) | $ | 66,438 |
| $ | 67,547 |
|
Gain reclassified from accumulated OCI into income (effective portion) | Operating revenues | $ | 34,293 |
| $ | 52,694 |
| $ | 26,326 |
|
| Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) |
Operating revenues | $ | 835 |
| $ | (5,340 | ) | $ | (2,767 | ) |
The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:
|
| | | | | | | | | | |
Years ended December 31, (in thousands) | Location on Income Statement | 2013 | 2012 | 2011 |
| Gain (loss) recognized in income on derivative | Operating revenues | $ | (73,980 | ) | $ | 61,841 |
| $ | (37,587 | ) |
As of December 31, 2013, $13.4 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected torequires that inventory that is measured using average cost be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of December 31, 2013, the Company had 51.8 billion cubic feet (Bcf) and 6.0 Bcf of natural gas hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 9.8 million barrels (MMBbl) and 5.8 MMBbl of oil hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 1.9 million gallons (MMgal) of natural gas liquid hedges which expire during 2014 that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $4.5 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale or sold.
As of December 31, 2013, Energen Resources entered into the following transactions for 2014 and subsequent years:
|
| | | | |
| Production Period | Total Hedged Volumes | Average Contract Price |
Description |
| Natural Gas |
| 2014 | 10.6 | Bcf | $4.55 Mcf | NYMEX Swaps |
| | 31.4 | Bcf | $4.60 Mcf | Basin Specific Swaps - San Juan |
| | 9.7 | Bcf | $3.81 Mcf | Basin Specific Swaps - Permian |
| 2015 | 6.0 | Bcf | $4.07 Mcf | Basin Specific Swaps - San Juan |
| Oil |
| 2014 | 9,796 | MBbl | $92.64 Bbl | NYMEX Swaps |
| 2015 | 5,760 | MBbl | $88.85 Bbl | NYMEX Swaps |
As of December 31, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010.
The following sets forth derivative assets and liabilities that were measured at fairthe lower of cost and net realizable value. Net realizable value on a recurring basis:
|
| | | | | | | | | |
| | December 31, 2013 |
| (in thousands) | Level 2* | Level 3* | Total |
| Current assets | $ | (1,658 | ) | $ | 19,121 |
| $ | 17,463 |
|
| Noncurrent assets | 4,383 |
| 1,056 |
| 5,439 |
|
| Current liabilities | (28,414 | ) | (1,888 | ) | (30,302 | ) |
| Net derivative asset (liability) | $ | (25,689 | ) | $ | 18,289 |
| $ | (7,400 | ) |
|
| | | | | | | | | |
| | December 31, 2012 |
| (in thousands) | Level 2* | Level 3* | Total |
| Current assets | $ | (3,629 | ) | $ | 68,421 |
| $ | 64,792 |
|
| Noncurrent assets | 18,899 |
| 21,678 |
| 40,577 |
|
| Current liabilities | (2,593 | ) | — |
| (2,593 | ) |
| Noncurrent liabilities | (8,520 | ) | (1,080 | ) | (9,600 | ) |
| Net derivative asset | $ | 4,157 |
| $ | 89,019 |
| $ | 93,176 |
|
* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed withis the same counterparty under a master netting arrangement.
As of December 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and are includedestimated selling prices in the above table as current liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values asordinary course of December 31, 2013business, less reasonably predictable costs of completion, disposal and 2012.
The Company has prepared a sensitivity analysis to evaluatetransportation. When evidence exists that the hypothetical effect that changes in the prices used to estimate fair value would have on the fairnet realizable value of inventory is lower than its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $19 million change incost, the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations woulddifference will be an approximate $19 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.
The table below sets forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Balance at beginning of period | $ | 89,019 |
| $ | 65,801 |
| $ | 42,755 |
|
| Realized gains | 55,210 |
| 63,720 |
| 52,716 |
|
| Unrealized gains (losses) relating to instruments held at the reporting date* | (71,367 | ) | 22,160 |
| 23,980 |
|
| Settlements during period | (54,573 | ) | (62,662 | ) | (53,650 | ) |
| Balance at end of period | $ | 18,289 |
| $ | 89,019 |
| $ | 65,801 |
|
*Includes $7.6 million in mark-to-market losses, $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2013, 2012 and 2011, respectively.
The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:
|
| | | | | | |
| (in thousands) | Fair Value as of December 31, 2013 | Valuation Technique* | Unobservable Input* | Range |
| Natural Gas Basis - San Juan | | | | |
| 2014 | $ | 18,159 |
| Discounted Cash Flow | Forward Basis | ($0.17 - $0.20) Mcf |
| 2015 | $ | 1,056 |
| Discounted Cash Flow | Forward Basis | ($0.26) Mcf |
| Natural Gas Basis - Permian | | | | |
| 2014 | $ | (1,948 | ) | Discounted Cash Flow | Forward Basis | ($0.18 - $0.20) Mcf |
| Natural Gas Liquids | | | | |
| 2014 | $ | 1,022 |
| Discounted Cash Flow | Forward Price | $0.80 - $0.81 Gal |
*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.
The tables below set forth information about the offsetting of derivative assets and liabilities as follows:
|
| | | | | | | | | | | | | | | | | | |
| | December 31, 2013 |
| | | | | Gross Amounts Not Offset in the Balance Sheets | |
| (in thousands) | Gross Amounts Recognized | Gross Amounts Offset in the Balance Sheets | Net Amount Presented in the Balance Sheets | Financial Instruments | Cash Collateral Received | Net Amount |
| Derivative assets | $ | 44,215 |
| $ | (21,313 | ) | $ | 22,902 |
| $ | — |
| $ | — |
| $ | 22,902 |
|
| Derivative liabilities | $ | 51,615 |
| $ | (21,313 | ) | $ | 30,302 |
| $ | — |
| $ | — |
| $ | 30,302 |
|
|
| | | | | | | | | | | | | | | | | | |
| | December 31, 2012 |
| | | | | Gross Amounts Not Offset in the Balance Sheets | |
| (in thousands) | Gross Amounts Recognized | Gross Amounts Offset in the Balance Sheets | Net Amount Presented in the Balance Sheets | Financial Instruments | Cash Collateral Received | Net Amount |
| Derivative assets | $ | 149,504 |
| $ | (44,135 | ) | $ | 105,369 |
| $ | — |
| $ | — |
| $ | 105,369 |
|
| Derivative liabilities | $ | 56,328 |
| $ | (44,135 | ) | $ | 12,193 |
| $ | — |
| $ | — |
| $ | 12,193 |
|
Concentration of Credit Risk:Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its purchasers and, in certain instances, may require credit assurances suchrecognized as a deposit, letter of credit or parent guarantee. The two largest oil and gas purchasers accounted for approximately 35 percent and 12 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2013. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2013. During the year ended December 31, 2013, Plains Marketing, LP, accounted for approximately 25 percent of consolidated total operating revenues. All other oil and gas purchasers each accounted for less than 10 percent of consolidated total operating revenues for the year ended December 31, 2013.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 422,000 residential, commercial and industrial customers locatedloss in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.
9. RECONCILIATION OF EARNINGS PER SHARE
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Years ended December 31, | | | | | | | | | |
| (in thousands, except per share amounts) | 2013 | | | 2012 | | | 2011 | |
| | Net Income |
Shares | Per Share Amount | Net Income |
Shares | Per Share Amount | Net Income |
Shares | Per Share Amount |
| Basic EPS | $ | 204,554 |
| 72,318 |
| $ | 2.83 |
| $ | 253,562 |
| 72,119 |
| $ | 3.52 |
| $ | 259,624 |
| 72,056 |
| $ | 3.60 |
|
| Effect of dilutive securities | | | | | | | | | |
| Stock options | | 112 |
| | | 196 |
| | | 270 |
| |
| Non-vested restricted stock | | 20 |
| | | 1 |
| | | 6 |
| |
| Performance share awards | | 21 |
| | | — |
| | | — |
| |
| Diluted EPS | $ | 204,554 |
| 72,471 |
| $ | 2.82 |
| $ | 253,562 |
| 72,316 |
| $ | 3.51 |
| $ | 259,624 |
| 72,332 |
| $ | 3.59 |
|
The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive.
|
| | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Stock options | 134,138 |
| 849,583 |
| 293,978 |
|
| Non-vested restricted stock | 6,529 |
| — |
| — |
|
| Performance share awards | 4,121 |
| — |
| — |
|
10. ASSET RETIREMENT OBLIGATIONS
The Company recognizes a liability for the fair value of asset retirement obligations (ARO)earnings in the period incurred. Subsequentin which it occurs. ASU No. 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years, and is to initial measurement, liabilitiesbe applied prospectively, with early application permitted. The Company, Laclede Gas and Alagasco are accreted to their present value and capitalized costs are depreciated overcurrently evaluating the estimated useful lifeimpact of the related assets. Upon settlementadoption of this new standard, which must be adopted by the first quarter of fiscal year 2018.
In September 2015, the FASB issued ASU No. 2015-16 – Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments. The provisions of this guidance apply to acquiring companies that have reported provisional amounts for items in a business combination. Under previous guidance, when an acquirer identified an adjustment to provisional amounts, the acquirer was required to revise comparative information for the prior periods as if the accounting for the business combination had been completed as of the liability,acquisition date. Under ASU No. 2015-16, an acquirer must recognize adjustments to provisional amounts in the reporting period in which the adjustment amounts are determined. The effect on earnings as a result of the change, calculated as if the accounting had been completed as of the acquisition date, must be recorded in the reporting period in which the adjustment amounts are determined rather than retrospectively. ASU No. 2015-16 also requires that the acquirer present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance of ASU No. 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years, and is to be applied prospectively, with early application permitted. The timing and effects of adoption by the Company, may recognize a gain or loss for differences between estimatedLaclede Gas and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2013, 2012 and 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:
|
| | | |
| (in thousands) | |
| Balance as of December 31, 2010 | $ | 97,415 |
|
| Liabilities incurred | 4,627 |
|
| Liabilities settled | (1,539 | ) |
| Accretion expense (including discontinued operations of $1,138) | 6,837 |
|
| Balance as of December 31, 2011 | 107,340 |
|
| Liabilities incurred | 3,994 |
|
| Liabilities settled | (845 | ) |
| Accretion expense (including discontinued operations of $1,195) | 7,534 |
|
| Balance as of December 31, 2012 | 118,023 |
|
| Liabilities incurred | 2,772 |
|
| Liabilities settled | (5,525 | ) |
| Accretion expense (including discontinued operations of $1,197) | 8,192 |
|
| Reclassification associated with held for sale properties* | (14,929 | ) |
| Balance as of December 31, 2013 | $ | 108,533 |
|
* Asset retirement obligation associated with North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.
The Company recognizes conditional obligations if such obligations canAlagasco will be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approvedaffected by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis,timing of $27.5 millionany future business combination activity and $24.9 million to purgethe nature and cap its gas pipelines upon abandonment and to remediate otheramounts of related obligations, as a regulatory liability as of December 31, 2013 and 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.6 million and $3.3 million as of December 31, 2013 and 2012, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.measurement-period adjustments.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning Energen’s cash flow activities was as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Interest paid, net of amount capitalized | $ | 65,143 |
| $ | 61,379 |
| $ | 33,601 |
|
| Income taxes paid | $ | 25,081 |
| $ | 17,170 |
| $ | 9,432 |
|
| Noncash investing activities: | | | |
| Accrued development, exploration costs and other capital | $ | 99,128 |
| $ | 120,024 |
| $ | 72,030 |
|
| Capitalized depreciation | $ | 66 |
| $ | 80 |
| $ | 93 |
|
| Capitalized asset retirement obligations costs | $ | 3,574 |
| $ | 4,409 |
| $ | 4,927 |
|
| Allowance for funds used during construction | $ | 698 |
| $ | 623 |
| $ | 807 |
|
| Capital lease obligations | $ | — |
| $ | 5,072 |
| $ | — |
|
| Noncash financing activities: | | | |
| Issuance of common stock for employee benefit plans | $ | 1,015 |
| $ | 838 |
| $ | 822 |
|
| Treasury stock acquired in connection with tax withholdings | $ | 977 |
| $ | 277 |
| $ | 713 |
|
Supplemental information concerning Alagasco’s cash flow activities was as follows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Interest paid, net of amount capitalized | $ | 13,465 |
| $ | 13,513 |
| $ | 12,385 |
|
| Income taxes paid | $ | 23,138 |
| $ | 16,796 |
| $ | 5,143 |
|
| Interest expense (revenue) on affiliated company debt, net | $ | (18 | ) | $ | 295 |
| $ | 376 |
|
| Noncash investing activities: | | | |
| Accrued property, plant and equipment costs | $ | 5,505 |
| $ | 3,536 |
| $ | 2,229 |
|
| Capitalized depreciation | $ | 66 |
| $ | 80 |
| $ | 93 |
|
| Capitalized asset retirement obligations costs | $ | 802 |
| $ | 415 |
| $ | 300 |
|
| Allowance for funds used during construction | $ | 698 |
| $ | 623 |
| $ | 807 |
|
12. ACQUISITION AND DISPOSITION OF PROPERTIES
In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.
During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.
On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.
On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.2 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
2. ACQUISITIONS
The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (includingat the effects of closing adjustments).
acquisition date, and the acquisitions are described below. Measurement period adjustments were immaterial.
|
| | | |
| (in thousands) | |
| Consideration given | |
| Cash (net) | $ | 67,615 |
|
| Recognized amounts of identifiable assets acquired and liabilities assumed | |
| Proved properties | $ | 65,581 |
|
| Unproved leasehold properties | 911 |
|
| Accounts receivable | 1,358 |
|
| Accounts payable | (25 | ) |
| Asset retirement obligation | (210 | ) |
| Total identifiable net assets | $ | 67,615 |
|
|
| | | | | | | |
| | MGE | | Alagasco |
| Recognized amounts of identifiable assets acquired and liabilities assumed: | | | |
| Utility plant | $ | 671.1 |
| | $ | 892.7 |
|
| Cash | — |
| | 12.1 |
|
| Inventories | 62.7 |
| | 47.7 |
|
| Other current assets | 36.0 |
| | 51.7 |
|
| Deferred tax assets | — |
| | 282.0 |
|
| Other assets | 99.0 |
| | 143.4 |
|
| Current portion of long-term debt | — |
| | (15.0 | ) |
| Long-term debt | — |
| | (249.8 | ) |
| Other current liabilities | (65.9 | ) | | (173.4 | ) |
| Other liabilities | (72.9 | ) | | (130.4 | ) |
| Total identifiable net assets | 730.0 |
| | 861.0 |
|
| Goodwill | 210.2 |
| | 735.8 |
|
| Deferred tax elimination (Laclede Group) | — |
| | (271.3 | ) |
| Consideration (cash) | $ | 940.2 |
| | $ | 1,325.5 |
|
Acquisition of MGE
Included in the Company’s consolidated results of operations for the year ended December 31, 2012, were $11.7 million of operating revenues and $3.1 million in operating income resulting from the operation of the properties acquired above.
In December 2012, EnergenEffective September 1, 2013, Laclede Gas completed the purchase from Southern Union Company (SUG), and affiliate of liquids-rich properties inEnergy Transfer Equity, L.P. (ETE) and Energy Transfer Partners, L.P., of substantially all of the Permian Basinassets and liabilities of MGE for a preliminary cash purchase price of approximately $18.7 million. During 2012, Energen also completed$975.0. A subsequent reconciliation of net assets transferred resulted in a totalpayment by ETE to Laclede Gas on February 14, 2014 of approximately $18 million in various purchases of unproved leasehold properties.$23.9.
On December 27, 2011, Energen completed14, 2012, Plaza Massachusetts Acquisition, Inc. (Plaza Mass), a subsidiary of Laclede Group, agreed to purchase New England Gas Company (NEG) from SUG in a transaction related to the purchaseacquisition of certain properties inMGE. On February 11, 2013, Laclede Group agreed to sell Plaza Mass to Algonquin Power and Utilities Corp. (APUC) immediately prior to the Permian Basin for a cash purchase price of $60 million. This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percentclosing of the proved reserves are oil, 24 percent are natural gas liquidsacquisition of NEG. On December 20, 2013, Laclede Group closed the sale of Plaza Mass to APUC and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flowsreceived $11.0, which was transferred to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011 (including the effects of closing adjustments).
|
| | | |
| (in thousands) | |
| Consideration given | |
| Cash (net) | $ | 60,017 |
|
| Recognized amounts of identifiable assets acquired and liabilities assumed | |
| Proved properties | $ | 36,068 |
|
| Unproved leasehold properties | 23,686 |
|
| Accounts receivable | 680 |
|
| Accounts payable | (244 | ) |
| Asset retirement obligation | (173 | ) |
| Total identifiable net assets | $ | 60,017 |
|
Laclede Gas.
The impact to operating revenues and operating income from this acquisition was not material fororiginal payment offset by the year ended December 31, 2011.
On November 16, 2011, Energen completed the purchasesubsequent receipts of certain propertiesfunds resulted in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011 (including the effects of closing adjustments).
|
| | | |
| (in thousands) | |
| Consideration given | |
| Cash (net) | $ | 161,967 |
|
| Recognized amounts of identifiable assets acquired and liabilities assumed | |
| Proved properties | $ | 151,544 |
|
| Unproved leasehold properties | 7,883 |
|
| Accounts receivable | 3,070 |
|
| Accounts payable | (388 | ) |
| Asset retirement obligation | (142 | ) |
| Total identifiable net assets | $ | 161,967 |
|
The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.
In July 2011, Energen completed the purchase of properties in the Permian Basin for a cashfinal net purchase price of approximately $20 million. In April 2011, Energen$940.2 for MGE. The goodwill of $210.2 arising from this acquisition, $177.2 of which is expected to be deductible for tax purposes, was assigned to the Company's Gas Utility reporting unit. The goodwill is attributable to MGE's assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The acquisition allows the Company to leverage its core gas utility expertise and further expand its footprint, enabling it to support growth initiatives in new markets with new customers.
Acquisition of Alagasco
Laclede Group completed the acquisition of 100% of the common stock of Alagasco from Energen effective on August 31, 2014. Total cash consideration paid at closing, net of cash acquired and debt assumed was $1,305.2. Subsequently, the Company and Energen agreed to a final reconciliation of net assets, and $8.2 was paid by the Company to Energen on January 6, 2015, effectively increasing the total net consideration to $1,313.4.
Goodwill of $735.8 arising from this acquisition, $717.6 of which is expected to be deductible for tax purposes, was assigned to the Company's Gas Utility reporting unit. The goodwill is attributable to Alagasco's assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The acquisition was supportive of the strategic focus on growing the Company's regulated footprint and created geographic and regulatory diversity. The Company determined that the Alagasco acquisition met the scope exceptions for pushdown accounting; therefore, the goodwill was recorded on the Laclede Group parent company balance sheet rather than the Alagasco subsidiary balance sheet and included in disclosures of segment assets under Other rather than the Gas Utility segment.
The Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco acquisition as a deemed purchase and sale of unproved leasehold propertiesassets for tax purposes. As a result of the election, goodwill was generated for tax purposes at Alagasco. For book purposes, goodwill was recorded on the Laclede Group parent entity and not pushed down to Alagasco. Consequently, a Deferred Tax Asset (DTA) was recorded at Alagasco related to the excess of tax deductible goodwill over book goodwill for the stand-alone entity. That initial goodwill DTA is eliminated (along with the investment in subsidiary and Alagasco’s equity) in the Laclede Group consolidated balance sheet because, at that consolidated level, there is no excess of tax deductible goodwill over book goodwill. As the tax goodwill is amortized and deducted for tax purposes, the DTA at Alagasco is reduced, and for Laclede Group, a deferred tax liability (DTL) is created. For both Alagasco and consolidated Laclede Group, the changes to the goodwill DTA/DTL is reported as a component of deferred tax expense in the income statement. Because the deferred tax expense impact will be offset by an opposite current tax expense impact, there will be no significant impact on the effective tax rate of the Company.
Actual and Pro Forma Results
The results of operations of each of the acquisitions are included in the statement of income from the date of acquisition, as shown in the following table.
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Total Operating Revenues: | | | | | |
| MGE | $ | 556.8 |
| | $ | 554.2 |
| | $ | 22.0 |
|
| Alagasco | 479.2 |
| | 19.7 |
| | — |
|
| Net Income (Loss): | | | | | |
| MGE | $ | 39.9 |
| | $ | 39.5 |
| | $ | 1.8 |
|
| Alagasco | 48.0 |
| | (2.9 | ) | | — |
|
| Earnings (Loss) Per Share: | | | | | |
| MGE | $ | 0.92 |
| | $ | 1.10 |
| | $ | 0.07 |
|
| Alagasco | 1.11 |
| | (0.08 | ) | | — |
|
The following unaudited pro forma financial information presents the combined results of operations as though the acquisitions had occurred as of October 1, 2012. 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 is not necessarily indicative of either future results of operations or results that might have been achieved had Alagasco or MGE been part of the Company as of the beginning of fiscal 2013.
|
| | | | | | | | | | |
| | Laclede Group | | Laclede Gas |
| | 2014 | 2013 | | 2013 |
| Total Operating Revenues | $ | 2,187.1 |
| $ | 2,051.5 |
| | $ | 1,518.2 |
|
| Net Income | 133.5 |
| 102.0 |
| | 83.6 |
|
| Basic Earnings Per Share | $ | 3.11 |
| $ | 2.50 |
| |
|
|
| Diluted Earnings Per Share | 3.10 |
| 2.49 |
| |
|
|
3. STOCK-BASED COMPENSATION
The Laclede Group 2015 Equity Incentive Plan (the 2015 Plan) was approved at the annual meeting of shareholders of Laclede Group on January 29, 2015. The purpose of the 2015 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 2015 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2015 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. The 2015 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, purchaseor a combination of both. The 2015 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 2015 Plan is 1,000,000. The 2015 Plan replaced the Laclede Group 2006 Equity Incentive Plan (the 2006 Plan), which in turn replaced the Laclede Group 2003 Equity Incentive Plan (the 2003 Plan). Shares reserved under the 2006 and 2003 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2015 Plan.
The Company issues new shares to satisfy employee restricted stock awards and stock option exercises.
Restricted Stock Awards
During fiscal year 2015, the Company granted 216,476 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $36.69 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, 2017. 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 2014 and 2013 was $37.21 and $34.49 per share, respectively.
Fiscal year 2015 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 Per Share |
| Nonvested at September 30, 2014 | 293,019 |
| | $ | 36.18 |
|
| Granted (maximum shares that can be earned) | 216,476 |
| | $ | 36.69 |
|
| Vested | (60,388 | ) | | $ | 40.01 |
|
| Forfeited | (51,837 | ) | | $ | 33.06 |
|
| Nonvested at September 30, 2015 | 397,270 |
| | $ | 36.28 |
|
During fiscal year 2015, the Company granted 46,047 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $50.90 per share. These shares were awarded between December 2014 and September 2015 and vest between December 2017 and September 2018 based on terms of the agreements. 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 2014 and 2013 was $45.66 and $40.03 per share, respectively.
During fiscal year 2015, the Company granted 15,200 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $54.66 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2014 and 2013 was $46.02 and $39.92 per share, respectively.
Time-vested restricted stock and stock unit activity for fiscal year 2015 is presented below:
|
| | | | | | |
| | Shares/ Units | | Weighted Average Grant Date Fair Value Per Share |
| Nonvested at September 30, 2014 | 141,093 |
| | $ | 42.02 |
|
| Granted | 61,247 |
| | $ | 51.78 |
|
| Vested | (67,747 | ) | | $ | 43.95 |
|
| Forfeited | (5,289 | ) | | $ | 45.45 |
|
| Nonvested at September 30, 2015 | 129,304 |
| | $ | 44.89 |
|
During fiscal year 2015, 128,135 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2011, May 1, 2012, December 2, 2013 and January 1, 2014 vested. The Company withheld 31,688 of the vested shares at a weighted average price of approximately $37 million covering$50.65 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2014, 88,533 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010, September 1, 2011, October 1, 2012, January 30, 2014 and February 21, 2014 vested. The Company withheld 23,776 of these vested shares at a weighted average price of $45.96 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2013, 91,221 shares of restricted stock (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 these vested shares at a weighted average price of $39.96 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 2015, 2014, and 2013 was $6.4, $4.1, and $3.8, respectively, and the related actual tax benefit realized was $2.4, $1.6 and $1.4, respectively.
Stock Option Awards
No stock options were granted during fiscal years 2015, 2014, and 2013. Stock option activity for fiscal year 2015 is presented below:
|
| | | | | | | | | | | | |
| | Stock Options | | Weighted Average Exercise Price Per Share | | Weighted Average Remaining Contractual Term (Years) | | Aggregate Intrinsic Value |
| Outstanding at September 30, 2014 | 79,750 |
| | $ | 32.42 |
| | | | |
| Exercised | (47,000 | ) | | $ | 31.76 |
| | | | |
| Forfeited | (4,250 | ) | | $ | 30.95 |
| | | | |
| Outstanding at September 30, 2015 | 28,500 |
| | $ | 33.65 |
| | 0.8 | | $ | 0.6 |
|
| Fully Vested and Expected to Vest at September 30, 2015 | 28,500 |
| | $ | 33.65 |
| | 0.8 | | $ | 0.6 |
|
| Exercisable at September 30, 2015 | 28,500 |
| | $ | 33.65 |
| | 0.8 | | $ | 0.6 |
|
Exercise prices of options outstanding at September 30, 2015 range from $30.46 to $34.95 per share. During fiscal year 2015, cash received from the exercise of stock options was $1.5, the intrinsic value of the options exercised was $0.9 and the related actual tax benefit realized was $0.3. During fiscal year 2014, cash received from the exercise of stock options was $1.7, the intrinsic value of the options exercised was $0.9 and the related actual tax benefit realized was $0.3. During fiscal year 2013, cash received from the exercise of stock options was $2.7, the intrinsic value of the options exercised was $1.0 and the related actual tax benefit realized was $0.4.
The closing price of the Company’s common stock was $54.53 per share at September 30, 2015.
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, are 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 US Treasury yield. For shares subject to the TSR provision, the estimated 11,000 net acresimpact of this market condition is reflected in the Permian Basin.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 2015, 2014, and 2013 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:
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| Risk free interest rate | 0.83% | | 0.53% | | 0.32% |
| Expected dividend yield of stock | — | | — | | — |
| Expected volatility of stock | 14.0% | | 18.0% | | 19.6% |
| Vesting period | 2.8 years | �� | 2.8 years | | 2.8 years |
The risk free interest rate was based on the yield on US Treasury securities matching the vesting period. A zero percent dividend yield was used, which is mathematically equivalent to the assumption that dividends are reinvested as they are paid. 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:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Total equity compensation cost | $ | 6.7 |
| | $ | 5.8 |
| | $ | 4.5 |
|
| Compensation cost capitalized | (1.8 | ) | | (1.8 | ) | | (1.4 | ) |
| Compensation cost recognized in net income | $ | 4.9 |
| | $ | 4.0 |
| | $ | 3.1 |
|
| Income tax benefit recognized in net income | (1.9 | ) | | (1.5 | ) | | (1.2 | ) |
| Compensation cost recognized in net income, net of income tax | $ | 3.0 |
| | $ | 2.5 |
| | $ | 1.9 |
|
As of September 30, 2015, there was $7.8 of total unrecognized compensation cost related to non-vested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 1.8 years.
4. EARNINGS PER COMMON SHARE
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Basic EPS: | | | | | |
| Net Income | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
| Less: Income allocated to participating securities | 0.5 |
| | 0.3 |
| | 0.3 |
|
| Net Income Available to Common Shareholders | $ | 136.4 |
| | $ | 84.3 |
| | $ | 52.5 |
|
| Weighted Average Shares Outstanding | 43.2 |
| | 35.8 |
| | 25.9 |
|
| Earnings Per Share of Common Stock | $ | 3.16 |
| | $ | 2.36 |
| | $ | 2.03 |
|
| Diluted EPS: | | | | | |
| Net Income | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
| Less: Income allocated to participating securities | 0.5 |
| | 0.3 |
| | 0.3 |
|
| Net Income Available to Common Shareholders | $ | 136.4 |
| | $ | 84.3 |
| | $ | 52.5 |
|
| Weighted Average Shares Outstanding | 43.2 |
| | 35.8 |
| | 25.9 |
|
| Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units | 0.1 |
| | 0.1 |
| | 0.1 |
|
| Weighted Average Diluted Shares | 43.3 |
| | 35.9 |
| | 26.0 |
|
| Earnings Per Share of Common Stock | $ | 3.16 |
| | $ | 2.35 |
| | $ | 2.02 |
|
| Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to: | | | | | |
| Restricted stock and stock units subject to performance and/or market conditions | 0.3 |
| | 0.3 |
| | 0.2 |
|
Laclede Group's 2014 2.0% Series Equity Units issued in June 2014 are potentially dilutive securities, but were excluded from the calculation of diluted EPS for the years ended September 30, 2015 and 2014. The potential shares were not included in the outstanding shares excluded from the calculation of Diluted EPS in the table above. See Note 5 for more information.
5. STOCKHOLDERS' EQUITY
Equity Units
13. DISCONTINUED OPERATIONSIn June 2014, Laclede Group issued 2.875 million equity units, initially consisting of Corporate Units, for an aggregate stated amount of approximately $143.8. Each Corporate Unit has a stated amount of fifty dollars and consists of (i) a stock purchase contract obligating the holder to purchase shares of Laclede Group's common stock, par value $1.00 per share (Common Stock) and (ii) a 1/20, or 5%, undivided beneficial ownership interest in one thousand dollars principal amount of Laclede Group's 2014 Series A 2.00% Remarketable Junior Subordinated Notes due 2022 (RSNs). The stock purchase contracts obligate the holders to purchase shares of Common Stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is fifty dollars per Corporate Unit and the number of shares to be purchased will be determined as follows:
|
| | |
If the applicable market value per share of Laclede Group common stock is:
| | Number of shares to be purchased per purchase contract is:
|
| Equal to or greater than $57.8125 | | 0.8649 |
| Less than $57.8125, but greater than $46.25 | | $50 ÷ applicable market value |
| Less than or equal to $46.25 | | 1.0811 |
The RSNs are pledged as collateral to secure the purchase of Common Stock under the related stock purchase contracts.
The Company makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. The Company may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, interest on the RSNs and contract adjustment payments will compound on each respective payment date in which the payment was deferred. Also, during the deferral period, the Company may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Additionally, the Company may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs during the deferral period.
The Company has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase
contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In October 2013, Energen Resources completedcalculating diluted EPS, the Company applies the treasury stock method to the Corporate Units. These securities did not have an effect on diluted EPS for the years ended September 30, 2015 and 2014.
Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Laclede Group will issue between approximately 2.5 million and 3.1 million shares of its common stock in April 2017. A total of approximately 4.2 million shares of Common Stock have been reserved for issuance in connection with the stock purchase contracts. The stock purchase contracts obligate the holders to purchase shares of Common Stock at a future settlement date (April 1, 2017, or if such day is not a business day, the following business day) prior to the relevant RSN maturity date.
Selected information about the Company’s equity units is presented below:
|
| | | | | | | | | | | | |
| Issuance Date | | Units Issued (Millions) | | Total Net Proceeds | | Total Long-term Debt | | RSN Annual Interest Rate | | Stock Purchase Contract Annual Rate | | Stock Purchase Contract Liability |
| 6/11/2014 | | 2.875 | | $139.4 | | $143.8 | | 2.00% | | 4.75% | | $19.7 |
Other Stock Information
Laclede Group
On June 20, 2014, Laclede Group filed a registration statement on Form S-3 for the issuance and sale of up to 168,698 shares of its Black Warrior Basin coalbed methane properties in Alabamacommon stock under its Dividend Reinvestment and Stock Purchase Program. There were 129,413 and 123,889 shares at September 30, 2015 and November 24, 2015, respectively, remaining available for $160 million (subjectissuance under this Form S-3.
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 $450.0 were issued by Laclede Gas from this shelf registration statement on August 13, 2013. The amount, timing, and type of additional financing to closing adjustments). The Company recorded a pre-tax gainbe issued under this shelf registration statement will depend on cash requirements and market conditions.
At September 30, 2015 and 2014, Laclede Group had authorized 5,000,000 shares of preferred stock, but none were issued and outstanding.
Laclede Gas
Laclede Gas periodically sells shares of its stock to Laclede Group at prices per share equal to book value on the last day of the quarter preceding each sale. There was no sale of approximately $35 millionshares to Laclede Group during fiscal 2015. Laclede Gas sold 28 shares to Laclede Group for $1.1 during fiscal year 2014 and 11,745 shares for $477.2 during fiscal year 2013. Exemption from registration for all of the sales was claimed under section 4(a)(2) of the Securities Act of 1933, as amended.
Substantially all of Laclede Gas plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas' ability to pay cash dividends on its common stock. 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 Laclede Gas' 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 fourthmortgage. Under that formula, the maximum amount is the sum of $8.0 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, 2015 and 2014, the amount under the mortgage’s formula that was available to pay dividends was $891.7 and $936.2, respectively. Thus, all of Laclede Gas' retained earnings were free from such restrictions as of those dates.
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 is reflected in gainregistration statement will expire August 5, 2016. Bonds totaling $450.0 were issued by Laclede Gas from this shelf registration statement on disposalAugust 13, 2013. The amount, timing, and type of discontinued operations inadditional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.
Laclede Gas has authority from the MoPSC 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 $518.0. This authorization was effective through June 30, 2015. During the year ended December 31, 2013. The sale hadSeptember 30, 2015, Laclede Gas issued no securities under this authorization. On April 15, 2015, Laclede Gas filed with the MoPSC for a new financing authorization. On June 24, 2015, the MoPSC granted an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.
In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas natural gas and oil properties for $31.5 million (subject to closing adjustments). The Company expects to complete the sale in the first quarter of 2014 and will use the proceeds to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on an estimateextension of the selling price ofcurrent authorization until the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.
The following table details held-for-sale properties by major classes of assets and liabilities:
|
| | | | | | | | | |
| (in thousands) | December 31, 2013 |
| | Black Warrior Basin | North Louisiana/East Texas |
Total |
| Accounts receivable | $ | 2,829 |
| $ | 1,272 |
| $ | 4,101 |
|
| Inventories | — |
| 68 |
| 68 |
|
| Oil and gas properties | — |
| 348,379 |
| 348,379 |
|
| Less accumulated depreciation, depletion and amortization | — |
| (301,609 | ) | (301,609 | ) |
| Other property, net | — |
| 165 |
| 165 |
|
| Total assets held-for-sale | 2,829 |
| 48,275 |
| 51,104 |
|
| Accounts payable | (1,732 | ) | (11 | ) | (1,743 | ) |
| Royalty payable | (550 | ) | (869 | ) | (1,419 | ) |
| Other current liabilities | (379 | ) | (21 | ) | (400 | ) |
| Other long-term liabilities | — |
| (14,983 | ) | (14,983 | ) |
| Total liabilities held-for-sale | (2,661 | ) | (15,884 | ) | (18,545 | ) |
| Total held-for-sale properties | $ | 168 |
| $ | 32,391 |
| $ | 32,559 |
|
During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedownpending application is reflected in loss from discontinued operations for the year ended December 31, 2012. The impairment was caused by the impact of lower future natural gas prices. This impairment writedown is classified as Level 3 fair value.
Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.
|
| | | | | | | | | |
| Years ended December 31, (in thousands, except per share data) | 2013 | 2012 | 2011 |
| | | | |
| Oil and gas revenues | $ | 60,191 |
| $ | 76,350 |
| $ | 110,366 |
|
| Pretax income (loss) from discontinued operations | $ | 10,028 |
| $ | (2,373 | ) | $ | 54,698 |
|
| Income tax expense (benefit) | 2,215 |
| (715 | ) | 19,379 |
|
| Income (Loss) From Discontinued Operations | $ | 7,813 |
| $ | (1,658 | ) | $ | 35,319 |
|
| Gain on disposal of discontinued operations, net | $ | 5,605 |
| $ | — |
| $ | — |
|
| Income tax expense | 2,011 |
| — |
| — |
|
| Gain on Disposal of Discontinued Operations, net | $ | 3,594 |
| $ | — |
| $ | — |
|
| Total Income (Loss) From Discontinued Operations | $ | 11,407 |
| $ | (1,658 | ) | $ | 35,319 |
|
| Diluted Earnings Per Average Common Share | | | |
| Income (Loss) from Discontinued Operations | $ | 0.10 |
| $ | (0.02 | ) | $ | 0.49 |
|
| Gain on Disposal of Discontinued Operations, net | 0.05 |
| — |
| — |
|
| Total Income (Loss) From Discontinued Operations | $ | 0.15 |
| $ | (0.02 | ) | $ | 0.49 |
|
| Basic Earnings Per Average Common Share | | | |
| Income (Loss) from Discontinued Operations | $ | 0.11 |
| $ | (0.02 | ) | $ | 0.49 |
|
| Gain on Disposal of Discontinued Operations, net | 0.05 |
| — |
| — |
|
| Total Income (Loss) From Discontinued Operations | $ | 0.16 |
| $ | (0.02 | ) | $ | 0.49 |
|
14. REGULATORY ASSETS AND LIABILITIES
resolved. As of November 24, 2015, $369.7 remains available under this authorization. The following table details regulatory assetsamount, timing, and liabilities on the consolidated balance sheets:
|
| | | | | | | | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| | Current | Noncurrent | Current | Noncurrent |
| Regulatory assets: | | | | |
| Pension assets | $ | 325 |
| $ | 58,243 |
| $ | 170 |
| $ | 90,708 |
|
| Accretion and depreciation for asset retirement obligation | — |
| 18,046 |
| — |
| 16,536 |
|
| Risk management activities | — |
| — |
| 2,593 |
| — |
|
| Rate recovery of asset removal costs, net | — |
| 4,601 |
| — |
| 3,322 |
|
| Enhanced stability reserve | — |
| 4,000 |
| — |
| — |
|
| Gas supply adjustment | 2,406 |
| — |
| 42,726 |
| — |
|
| Other | 25 |
| — |
| 26 |
| — |
|
| Total regulatory assets | $ | 2,756 |
| $ | 84,890 |
| $ | 45,515 |
| $ | 110,566 |
|
| | | | | |
| Regulatory liabilities: | | | | |
| RSE adjustment | $ | 4,690 |
| $ | — |
| $ | 1,740 |
| $ | — |
|
| Unbilled service margin | 28,504 |
| — |
| 25,078 |
| — |
|
| Postretirement liabilities | — |
| 26,197 |
| — |
| 1,237 |
|
| Refundable negative salvage | 15,779 |
| 39,663 |
| 18,265 |
| 53,467 |
|
| Asset retirement obligation | — |
| 27,528 |
| — |
| 24,930 |
|
| Other | 33 |
| 737 |
| 33 |
| 770 |
|
| Total regulatory liabilities | $ | 49,006 |
| $ | 94,125 |
| $ | 45,116 |
| $ | 80,404 |
|
As described in Note 2, Regulatory Matters, Alagasco’s rates are established under the RSE rate-setting process and are based on average equity for the period. Alagasco’s rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.
15. TRANSACTIONS WITH RELATED PARTIES
The Company allocates certain corporate costs to Energen Resources and Alagasco based on the naturetype of the expenseadditional financing to be allocated using various factors including,issued will depend on cash requirements and market conditions.
At September 30, 2015 and 2014, Laclede Gas had authorized1,480,000 shares of preferred stock, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $4.7 millionnone were issued and $5.7 million at December 31, 2013 and 2012, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $18,000 in affiliated company interest revenue during the year ended December 31, 2013. Alagasco had $0.3 million and $0.4 million in affiliated company interest expense during the years ended December 31, 2012 and 2011, respectively.outstanding.
16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Comprehensive Income
The following table provides changes in the components of accumulated other comprehensive income (loss), net of income taxes, recognized in the related income tax effects.
balance sheets at September 30 were as follows:
|
| | | | | | | | | |
| (in thousands) | Cash Flow Hedges | Pension and Postretirement Plans | Total |
| Balance as of December 31, 2012 | $ | 44,196 |
| $ | (52,507 | ) | $ | (8,311 | ) |
| Other comprehensive income (loss) before reclassifications | (11,014 | ) | 11,582 |
| 568 |
|
| Amounts reclassified from accumulated other comprehensive income (loss) | (21,004 | ) | 8,680 |
| (12,324 | ) |
| Change in accumulated other comprehensive income (loss) | (32,018 | ) | 20,262 |
| (11,756 | ) |
| Balance as of December 31, 2013 | $ | 12,178 |
| $ | (32,245 | ) | $ | (20,067 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Net Unrealized Gains (Losses) on Cash Flow Hedges | | Defined Benefit Pension and Other Postretirement Benefit Plans | | Net Unrealized Losses on Available for Sale Securities | | Total |
| Laclede Group | | | | | | | | |
| Balance at September 30, 2013 | | $ | 1.4 |
| | $ | (2.2 | ) | | $ | — |
| | $ | (0.8 | ) |
| Other comprehensive (loss) income | | (1.2 | ) | | 0.3 |
| | — |
| | (0.9 | ) |
| Balance at September 30, 2014 | | 0.2 |
| | (1.9 | ) | | — |
| | (1.7 | ) |
| Other comprehensive (loss) income | | (0.6 | ) | | 0.4 |
| | (0.1 | ) | | (0.3 | ) |
| Balance at September 30, 2015 | | $ | (0.4 | ) | | $ | (1.5 | ) | | $ | (0.1 | ) | | $ | (2.0 | ) |
| Laclede Gas | | | | | | | | |
| Balance at September 30, 2013 | | $ | 0.1 |
| | $ | (2.2 | ) | | $ | — |
| | $ | (2.1 | ) |
| Other comprehensive (loss) income | | (0.1 | ) | | 0.3 |
| | — |
| | 0.2 |
|
| Balance at September 30, 2014 | | — |
| | (1.9 | ) | | — |
| | (1.9 | ) |
| Other comprehensive (loss) income | | (0.2 | ) | | 0.4 |
| | — |
| | 0.2 |
|
| Balance at September 30, 2015 | | $ | (0.2 | ) | | $ | (1.5 | ) | | $ | — |
| | $ | (1.7 | ) |
Income tax expense (benefit) recorded for items of other comprehensive income (loss) reported in the statements of comprehensive income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The following table provides detailstax rates applied to individual items of other comprehensive income are similar within each reporting period. For the reclassifications out ofperiods presented Alagasco had no accumulated other comprehensive income (loss) balances.
Composition of long-term debt for Laclede Group, Laclede Gas and Alagasco are shown in each registrant's statements of capitalization as part of the financial statements. Maturities of long-term debt for Laclede Group, Laclede Gas and Alagasco for the five fiscal years subsequent to September 30, 2015 are as follows: |
| | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| 2016 | $ | 80.0 |
| | $ | — |
| | $ | 80.0 |
|
| 2017 | 250.0 |
| | — |
| | — |
|
| 2018 | 100.0 |
| | 100.0 |
| | — |
|
| 2019 | 175.0 |
| | 50.0 |
| | — |
|
| 2020 | 40.0 |
| | — |
| | 40.0 |
|
Laclede Group
On August 19, 2014 Laclede Group issued $625.0 aggregate principal amount in long-term debt. Of this, $250.0 were floating rate senior notes with an interest rate of three-month LIBOR + 0.75% per annum maturing in August 2017, $125.0 were senior notes with an interest rate of 2.55% maturing in August 2019, and $250.0 were senior notes with an interest rate of 4.70% maturing in August 2044. The proceeds were used to fund a portion of the Alagasco acquisition.
At September 30, 2015, including the current portion but excluding unamortized discounts and net hedging gains, the Laclede Group had fixed-rate long-term debt totaling $1,603.8 and floating rate long-term debt totaling $250.0, of which $810.0 was issued by Laclede Gas and $250.0 was issued by Alagasco. With the exception of the $250.0 floating rate senior notes issued by Laclede Group, all long-term debt bears fixed rates and is subject to changes in fair value as market interest rates change.
However, increases and 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 Utilities' regulated operations, losses or gains on early redemption of long-term debt typically would be deferred as regulatory assets or liabilities and amortized over a future period.
Of the Company’s $1,710.0 senior long-term debt, $25.0 have no call options, $710.0 have make-whole call options, $725.0 are callable at par between one to six months prior to maturity and $250.0 are callable at par one year prior to maturity. The remainder of the Company's long-term debt is $143.8 of 2% Remarketable Junior Subordinated Notes due in 2022. None of the debt has put options.
Laclede Group has a shelf registration statement on Form S-3 on file with the SEC for the issuance and sale of up to 168,698 shares on common stock under its Dividend Reinvestment and Direct Stock Purchase Plan. There were 129,413 and 123,889 at September 30, 2015 and November 20, 2015, respectively, remaining available for issuance under this Form S-3. Laclede Group also has a shelf registration statement on Form S-3 on file with the SEC for the issuance of equity and debt securities.
The Company's capitalization at September 30, 2015 consisted of 47.0% of Laclede Group common stock equity and 53.0% long-term debt, compared to 44.9% of Laclede Group common stock equity and 55.1% of long-term debt at September 30, 2014. The decline in the proportion of long-term debt is due primarily to the reclassification of $80.0 of Alagasco long-term debt to "current".
Laclede Gas
On December 6, 2013, Laclede Gas provided a notice of redemption to holders for the entire $80.0 aggregate principal amount outstanding of its previously issued 6.35% Series first mortgage bonds due in 2038. The redemption, which was for cash and included accrued interest, was completed on January 6, 2014.
At September 30, 2015, Laclede Gas had fixed-rate long-term debt, including the current portion, totaling $810.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of Laclede Gas' $810.0 in long-term debt, $25.0 have no call options, $435.0 have make-whole call options and $350.0 are callable at par three to six months prior to maturity. None of the debt has any put options.
Laclede Gas has authority from the MoPSC 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 $518.0. This authorization was effective through June 30, 2015. On April 15, 2015, Laclede Gas filed with the MoPSC for a new financing authorization. On June 24, 2015, the MoPSC granted an extension of the current authorization until the pending application is resolved. During the year ended September 30, 2015, Laclede Gas issued no securities under this authorization. As of November 20, 2015, $369.7 remains available under this authorization. Laclede Gas has a shelf registration on Form S-3 on file with the SEC for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires on August 6, 2016. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations. This authorization is more fully described in Note 5, Shareholder's Equity. Laclede Gas' capitalization at September 30, 2015 consisted of 56.2% of Laclede Gas common stock equity and 43.8% long-term debt compared to 55.5% of Laclede Gas common stock equity and 44.5% of long-term debt at September 30, 2014.
Substantially all of Laclede Gas' plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas' ability to pay cash dividends on its common stock, which are described more fully in Note 5, Stockholders’ Equity. Alagasco
Because Alagasco has no standing authority to issue long-term debt, it must petition the APSC for each planned issuance. On November 3, 2014, Alagasco received authorization and approval from the APSC to borrow $35.0 for the purpose of redeeming, without penalty, $34.8 in existing long-term, callable debt financed at 5.7%. Pursuant to a call notice issued on December 15, 2014, Alagasco redeemed $34.8 of debt effective January 15, 2015. On February 3, 2015, Alagasco received authorization and approval from the APSC to borrow $80.0 for the purpose of refinancing the scheduled maturity on December 1, 2015 of $80.0 of existing debt. Pursuant to these authorizations, Alagasco committed to issue $115.0 unsecured notes in the private placement market:$35.0 at a rate of 3.21% for 10 years issued on September 15, 2015, and $80.0 at a rate of 4.31% for 30 years settling December 1, 2015. As of September 30, 2015, the current portion of long-term debt for Alagasco consisted of this $80.0 fixed-rate note maturing December 1, 2015. The Notes are senior unsecured obligations of Alagasco and rank equal in right to payment with all other senior unsecured indebtedness. Alagasco will use the proceeds from the sale of the Notes to refinance existing indebtedness and for general corporate purposes.
At September 30, 2015, Alagasco had fixed-rate long-term debt, including the current portion, totaling $250.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. All of Alagasco's $250.0 in long-term debt has make-whole call options.
Alagasco's capitalization at September 30, 2015 consisted of 83.7% of Alagasco common stock equity and 16.3% long-term debt compared to 77.3% of Alagasco common stock equity and 22.7% of long-term debt at September 30, 2014. The decline in the proportion of long-term debt is due primarily to the reclassification of $80.0 of Alagasco long-term to "current".
Other
Laclede Group's, Laclede Gas' and Alagasco's short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of September 30, 2015, there were no events of default under these covenants.
The Company’s, Laclede Gas’, and Alagasco'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, Laclede Gas and Alagasco remain at investment grade, but are subject to review and change by the rating agencies.
It is management’s view that the Company, Laclede Gas and Alagasco have 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, interest payments on long-term debt, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.
7. NOTES PAYABLE AND CREDIT AGREEMENTS
Short-term cash requirements outside of the Utilities have generally been funded by Laclede Group or met with internally generated funds. At September 30, 2015, Laclede Group had a $150.0 syndicated line of credit from nine banks maturing on September 3, 2019, with the largest portion provided by a single bank being 15.6%. 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 was 58% on September 30, 2015. Laclede Group's line may be used to provide for the funding needs of various subsidiaries. Borrowing under Laclede's Group's line during fiscal year 2015 ranged from $32.5 to $80.0, with the balance at September 30, 2015 of $74.0. Borrowings under Laclede Group's line during fiscal year 2014 ranged from $0 to $40.0, with the balance at September 30, 2014 of $32.5. The maturity date of the loan agreement is September 3, 2019.
The Utilities’ short-term borrowing requirements typically peak during the colder months while the Company's needs are less seasonal. 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, 2015, Laclede Gas had a syndicated line of credit of $450.0 in place from nine banks. The largest portion provided by a single bank is 15.6%. Laclede Gas' 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, on September 30, 2015 total debt was 50% of total capitalization. Borrowing under Laclede Gas' commercial paper program during fiscal year 2015 ranged from $102.1 - $341.0, with the balance at September 30, 2015 at $233.0. Borrowing under Laclede Gas' commercial paper program during fiscal 2014 ranged from $0.0 to $244.5, with the balance at September 30, 2014 of $238.6. Laclede Gas' commercial paper program is backed by the line of credit. The maturity date of the line of credit is September 3, 2019.
On September 2, 2014, Alagasco entered into a new $150.0 syndicated line of credit with twelve banks and extinguished the line that was in place prior to its acquisition by Laclede Group. The largest portion provided by a single bank is 10%. The line of credit, which matures on September 2, 2019, has a covenant limiting total debt to no more than 70% of Alagasco's total capitalization. As defined in the line of credit, this ratio stood at 24% on September 30, 2015. Borrowing under Alagasco's line during fiscal year 2015 ranged from $0.0 to $69.5, with the balance at September 30, 2015 of $31.0. Borrowings under Alagasco's line for the month of September of fiscal 2014 ranged from $9.0 to $16.0, with the balance at September 30, 2014 of $16.0.
Laclede Group
Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the twelve months ended September 30, and as of September 30, is presented below for 2015 and 2014:
|
| | | | |
| | Year ended | |
| | December 31, 2013 | |
| (in thousands) | Amounts Reclassified | Line Item Where Presented |
| Gains and (losses) on cash flow hedges: | | |
| Commodity contracts | $ | 35,684 |
| Operating revenues |
| Interest rate swap | (1,723 | ) | Interest expense |
| Total cash flow hedges | 33,961 |
| |
| Income tax expense | (12,957 | ) | |
| Net of tax | 21,004 |
| |
| Pension and postretirement plans: | | |
| Transition obligation | (319 | ) | Operations and maintenance |
| Prior service cost | (257 | ) | Operations and maintenance |
| Actuarial losses* | (12,357 | ) | Operations and maintenance |
| Actuarial losses on settlement charges* | (421 | ) | Regulatory asset |
| Total pension and postretirement plans | (13,354 | ) | |
| Income tax expense | 4,674 |
| |
| Net of tax | (8,680 | ) | |
| Total reclassifications for the period | $ | 12,324 |
| |
|
| | | | |
| | Laclede Gas Commercial Paper Borrowings | Laclede Group Bank Line Borrowings*** | Alagasco Bank Line Borrowings * | Total Short-Term Borrowings ** |
| Year Ended September 30, 2015 | | | | |
| Weighted average borrowings outstanding | $212.7 | $65.6 | $22.3 | $300.6 |
| Weighted average interest rate | 0.4% | 1.4% | 1.1% | 0.7% |
| Range of borrowings outstanding | $ 102.1 - $341.0 | $32.5 - $80.0 | $0 - $69.5 | $180.1 - $488.5 |
| As of September 30, 2015 | | | | |
| Borrowings outstanding at end of period | $233.0 | $74.0 | $31.0 | $338.0 |
| Weighted average interest rate | 0.5% | 1.5% | 1.2% | 0.8% |
| Year Ended September 30, 2014 | | | | |
| Weighted average borrowings outstanding | $77.6 | $3.6 | $13.2 | $82.3 |
| Weighted average interest rate | 0.3% | 1.4% | 1.2% | 0.5% |
| Range of borrowings outstanding | $0 – $244.5 | $0 – $40.0 | $9.0 – $16.0 | $0 – $300.5 |
| As of September 30, 2014 | | | | |
| Borrowings outstanding at end of period | $238.6 | $32.5 | $16.0 | $287.1 |
| Weighted average interest rate | 0.3% | 1.4% | 1.2% | 0.5% |
* InWeighted average borrowings for Alagasco represents Laclede Group's ownership period of one month. The one month average approximates the first quarter of 2013, the Company incurred a settlement charge of $0.5 millionAlagasco daily outstanding balance for the paymentfiscal year ended September 30, 2014.
** Represents twelve month weighted average for Laclede Group***, Laclede Gas, and Alagasco.
*** The Laclede Group, Inc., excluding its wholly owned subsidiaries.
Based on average short-term borrowings for the twelve months ended September 30, 2015, an increase in the average interest rate of lump sums from the nonqualified supplemental retirement plans,100 basis points would decrease Laclede Group's pre-tax earnings and cash flows by approximately $3.0 on an annual basis, portions of which $0.1 millionmay be offset through the application of PGA or GSA carrying costs.
Laclede Gas
Information about Laclede Gas' short-term borrowings during the twelve months ended September 30, and as of September 30, is recognized in actuarial losses abovepresented below for 2015 and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses2014:
|
| | | |
| | Commercial Paper Borrowings | Borrowings from Laclede Group | Total Short-Term Borrowings |
| | | | |
| Year Ended September 30, 2015 | | | |
| Weighted average borrowings outstanding | $212.7 | $0.3 | $213.0 |
| Weighted average interest rate | 0.4% | 0.5% | 0.4% |
| Range of borrowings outstanding | $102.1 - $341.0 | $0 - $10.4 | $104.2 - $ 341.0 |
| As of September 30, 2015 | | | |
| Borrowings outstanding at end of period | $233.0 | $— | $233.0 |
| Weighted average interest rate | 0.5% | —% | 0.5% |
| Year Ended September 30, 2014 | | | |
| Weighted average borrowings outstanding | $77.6 | $63.4 | $141.0 |
| Weighted average interest rate | 0.3% | 0.3% | 0.3% |
| Range of borrowings outstanding | $0 – $244.5 | $0 – $189.0 | $45.5 – $272.1 |
| As of September 30, 2014 | | | |
| Borrowings outstanding at end of period | $238.6 | $— | $238.6 |
| Weighted average interest rate | 0.3% | —% | 0.3% |
Based on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000average short-term borrowings for the paymenttwelve months ended September 30, 2015, an increase in the average interest rate of lump sums from the nonqualified supplemental retirement plans,100 basis points would decrease Laclede Gas' pre-tax earnings and cash flows by approximately $2.1 on an annual basis, portions of which $18,000may be offset through the application of PGA carrying costs.
Alagasco
Information about Alagasco's short-term borrowings during the twelve months ended September 30, and as of September 30, is recognized in actuarial losses abovepresented below for 2015 and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.
17. RECENTLY ISSUED ACCOUNTING STANDARDS2014:
|
| |
| | Bank Line Borrowings |
| |
| Year Ended September 30, 2015 | |
| Weighted average borrowings outstanding | $22.3 |
| Weighted average interest rate | 1.1% |
| Range of borrowings outstanding | $0 - $69.5 |
| As of September 30, 2015 | |
| Borrowings outstanding at end of period | $31.0 |
| Weighted average interest rate | 1.2% |
| 9/30/2014 | |
| Weighted average borrowings outstanding | $13.7 |
| Weighted average interest rate | 1.3% |
| Range of borrowings outstanding | $0.0 - $55.0 |
| As of September 30, 2014 | |
| Borrowings outstanding at end of period | $16.0 |
| Weighted average interest rate | 1.2% |
Based on average short-term borrowings for the twelve months ended September 30, 2015, an increase in the average interest rate of 100 basis points would decrease Alagasco's Gas' pre-tax earnings and cash flows by approximately $0.2 on an annual basis, portions of which may be offset through the application of GSA carrying costs.
| |
| 8. | FAIR VALUE OF FINANCIAL INSTRUMENTS |
Laclede Group
The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for the Company are as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | Classification of Estimated Fair Value |
| | 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, 2015 | | | | | | | | | |
| Cash and cash equivalents | $ | 13.8 |
| | $ | 13.8 |
| | $ | 13.8 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 338.0 |
| | 338.0 |
| | — |
| | 338.0 |
| | — |
|
| Long-term debt, including current portion | 1,851.5 |
| | 1,944.2 |
| | — |
| | 1,944.2 |
| | — |
|
| | | | | | | | | | |
| As of September 30, 2014 | | | | | | | | | |
| Cash and cash equivalents | $ | 16.1 |
| | $ | 16.1 |
| | $ | 16.1 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 287.1 |
| | 287.1 |
| | — |
| | 287.1 |
| | — |
|
| Long-term debt, including current portion | 1,851.0 |
| | 1,937.3 |
| | — |
| | 1,937.3 |
| | — |
|
Laclede Gas
The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Laclede Gas are as follows: |
| | | | | | | | | | | | | | | | | | | |
| | | | | | Classification of Estimated Fair Value |
| | 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, 2015 | | | | | | | | | |
| Cash and cash equivalents | $ | 1.7 |
| | $ | 1.7 |
| | $ | 1.7 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 233.0 |
| | 233.0 |
| | — |
| | 233.0 |
| | — |
|
| Long-term debt | 808.1 |
| | 880.2 |
| | — |
| | 880.2 |
| | — |
|
| | | | | | | | | | |
| As of September 30, 2014 | | | | | | | | | |
| Cash and cash equivalents | $ | 3.7 |
| | $ | 3.7 |
| | $ | 3.7 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 238.6 |
| | 238.6 |
| | — |
| | 238.6 |
| | — |
|
| Long-term debt | 807.9 |
| | 876.2 |
| | — |
| | 876.2 |
| | — |
|
Alagasco
The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Alagasco are as follows: |
| | | | | | | | | | | | | | | | | | | |
| | | | | | Classification of Estimated Fair Value |
| | 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, 2015 | | | | | | | | | |
| Cash and cash equivalents | $ | 7.2 |
| | $ | 7.2 |
| | $ | 7.2 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 31.0 |
| | 31.0 |
| | — |
| | 31.0 |
| | — |
|
| Long-term debt, including current portion | 250.0 |
| | 263.2 |
| | — |
| | 263.2 |
| | — |
|
| | | | | | | | | | |
| As of September 30, 2014 | | | | | | | | | |
| Cash and cash equivalents | $ | 5.6 |
| | $ | 5.6 |
| | $ | 5.6 |
| | $ | — |
| | $ | — |
|
| Short-term debt | 16.0 |
| | 16.0 |
| | — |
| | 16.0 |
| | — |
|
| Long-term debt | 249.8 |
| | 266.4 |
| | — |
| | 266.4 |
| | — |
|
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 9, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis. 9. FAIR VALUE MEASUREMENTS
Laclede Group
The following tables for Laclede Group and Laclede Gas categorizes the assets and liabilities in the balance sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition. Alagasco had no such assets or liabilities as of September 30, 2015 or 2014.
The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual securities. The mutual funds included in Level 2 are valued based on the closing net asset value per unit.
Derivative instruments included in Level 1 are valued using quoted market prices on the New York Mercantile Exchange (NYMEX). Derivative instruments classified as 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. There were no material Level 3 balances as of September 30, 2015 or 2014. The Company's and the Utilities' 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 mutual funds are included in the "Other investments" line of the balance sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the balance sheets when a legally enforceable netting agreement exist between the Company or Laclede Gas and the counterparty to the derivative contract. For additional information on derivative instruments, see Note 10, Derivative Instruments and Hedging Activities.
|
| | | | | | | | | | | | | | | | | | | |
| | 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, 2015 | | | | | | | | | |
| ASSETS | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| U. S. Stock/Bond Mutual Funds | $ | 15.5 |
| | $ | 4.0 |
| | $ | — |
| | $ | — |
| | $ | 19.5 |
|
| NYMEX/ICE natural gas contracts | 1.3 |
| | — |
| | — |
| | (1.3 | ) | | — |
|
| Subtotal | 16.8 |
| | 4.0 |
| | — |
| | (1.3 | ) | | 19.5 |
|
| Gas Marketing | | | | | | | | | |
| NYMEX/ICE natural gas contracts | 6.3 |
| | 4.3 |
| | — |
| | (6.6 | ) | | 4.0 |
|
| Natural gas commodity contracts | — |
| | 1.5 |
| | 0.2 |
| | (0.5 | ) | | 1.2 |
|
| Total | $ | 23.1 |
| | $ | 9.8 |
| | $ | 0.2 |
| | $ | (8.4 | ) | | $ | 24.7 |
|
| LIABILITIES | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| NYMEX/ICE natural gas contracts | $ | 16.4 |
| | $ | — |
| | $ | — |
| | $ | (16.4 | ) | | $ | — |
|
| OTCBB natural gas contracts | — |
| | 5.9 |
| | — |
| | — |
| | 5.9 |
|
| NYMEX gasoline and heating oil contracts | 0.3 |
| | — |
| | — |
| | (0.3 | ) | | — |
|
| Subtotal | 16.7 |
| | 5.9 |
| | — |
| | (16.7 | ) | | 5.9 |
|
| Gas Marketing | | | | | | | | | |
| NYMEX/ICE natural gas contracts | 1.2 |
| | 3.9 |
| | — |
| | (5.1 | ) | | — |
|
| Natural gas commodity contracts | — |
| | 2.2 |
| | — |
| | (0.5 | ) | | 1.7 |
|
| Total | $ | 17.9 |
| | $ | 12.0 |
| | $ | — |
| | $ | (22.3 | ) | | $ | 7.6 |
|
| | | | | | | | | | |
| As of September 30, 2014 | | | | | | | | | |
| ASSETS | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| U. S. Stock/Bond Mutual Funds | $ | 15.7 |
| | $ | 3.9 |
| | $ | — |
| | $ | — |
| | $ | 19.6 |
|
| NYMEX/ICE natural gas contracts | 2.4 |
| | — |
| | — |
| | (2.4 | ) | | — |
|
| OTCBB natural gas contracts | — |
| | 0.1 |
| | — |
| | (0.1 | ) | | — |
|
| Subtotal | 18.1 |
| | 4.0 |
| | — |
| | (2.5 | ) | | 19.6 |
|
| Gas Marketing | | | | | | | | | |
| NYMEX natural gas contracts | 1.0 |
| | 1.2 |
| | — |
| | (1.8 | ) | | 0.4 |
|
| Natural gas commodity contracts | — |
| | 2.7 |
| | 0.2 |
| | (0.2 | ) | | 2.7 |
|
| Total | $ | 19.1 |
| | $ | 7.9 |
| | $ | 0.2 |
| | $ | (4.5 | ) | | $ | 22.7 |
|
| LIABILITIES |
| |
| |
| |
| |
|
| Gas Utility | | | | | | | | | |
| NYMEX/ICE natural gas contracts | $ | 5.2 |
| | $ | — |
| | $ | — |
| | $ | (5.2 | ) | | $ | — |
|
| OTCBB natural gas contracts | — |
| | 4.1 |
| | — |
| | (0.1 | ) | | 4.0 |
|
| NYMEX gasoline and heating oil contracts | 0.2 |
| | — |
| | — |
| | (0.2 | ) | | — |
|
| Subtotal | 5.4 |
| | 4.1 |
| | — |
| | (5.5 | ) | | 4.0 |
|
| Gas Marketing | | | | | | | | | |
| NYMEX/ICE natural gas contracts | 1.1 |
| | 0.7 |
| | — |
| | (1.8 | ) | | — |
|
| Natural gas commodity contracts | — |
| | 0.7 |
| | — |
| | (0.2 | ) | | 0.5 |
|
| Total | $ | 6.5 |
| | $ | 5.5 |
| | $ | — |
| | $ | (7.5 | ) | | $ | 4.5 |
|
Laclede Gas
|
| | | | | | | | | | | | | | | | | | | |
| | 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, 2015 | | | | | | | | | |
| ASSETS | | | | | | | | | |
| U. S. Stock/Bond Mutual Funds | $ | 15.5 |
| | $ | 4.0 |
| | $ | — |
| | $ | — |
| | $ | 19.5 |
|
| NYMEX/ICE natural gas contracts | 1.3 |
| | — |
| | — |
| | (1.3 | ) | | — |
|
| Total | $ | 16.8 |
| | $ | 4.0 |
| | $ | — |
| | $ | (1.3 | ) | | $ | 19.5 |
|
| LIABILITIES | | | | | | | | | |
| NYMEX/ICE natural gas contracts | $ | 16.4 |
| | $ | — |
| | $ | — |
| | $ | (16.4 | ) | | $ | — |
|
| OTCBB natural gas contracts | — |
| | 5.9 |
| | — |
| | — |
| | 5.9 |
|
| Gasoline and heating oil contracts | 0.3 |
| | — |
| | — |
| | (0.3 | ) | | — |
|
| Total | $ | 16.7 |
| | $ | 5.9 |
| | $ | — |
| | $ | (16.7 | ) | | $ | 5.9 |
|
| | | | | | | | | | |
| As of September 30, 2014 | | | | | | | | | |
| ASSETS | | | | | | | | | |
| U. S. Stock/Bond Mutual Funds | $ | 15.7 |
| | $ | 3.9 |
| | $ | — |
| | $ | — |
| | $ | 19.6 |
|
| NYMEX/ICE natural gas contracts | 2.4 |
| | — |
| | — |
| | (2.4 | ) | | — |
|
| OTCBB natural gas contracts | — |
| | 0.1 |
| | — |
| | (0.1 | ) | | — |
|
| Total | $ | 18.1 |
| | $ | 4.0 |
| | $ | — |
| | $ | (2.5 | ) | | $ | 19.6 |
|
| LIABILITIES | | | | | | | | | |
| NYMEX/ICE natural gas contracts | $ | 5.2 |
| | $ | — |
| | $ | — |
| | $ | (5.2 | ) | | $ | — |
|
| OTCBB natural gas contracts | — |
| | 4.1 |
| | — |
| | (0.1 | ) | | 4.0 |
|
| NYMEX gasoline and heating oil contracts | 0.2 |
| | — |
| | — |
| | (0.2 | ) | | — |
|
| Total | $ | 5.4 |
| | $ | 4.1 |
| | $ | — |
| | $ | (5.5 | ) | | $ | 4.0 |
|
| |
| 10. | DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES |
Laclede Group
Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments, for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit the Missouri Utilities' exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. This policy strictly prohibits speculation and permits the Missouri Utilities to hedge current physical natural gas purchase commitments or forecasted or anticipated future peak (maximum) physical need for natural gas delivered. Costs and cost reductions, including carrying costs, associated with the Missouri Utilities' use of natural gas derivative instruments are allowed to be passed on to the Missouri Utilities’ customers through the operation of their PGA clauses, through which the MoPSC allows the Missouri Utilities to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Missouri Utilities do not expect any adverse earnings impact as a result of the use of these derivative instruments. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff. At September 30, 2015, Alagasco had no open derivative positions. The Utilities do 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 income. The timing of the operation of the PGA clause and GSA rider may cause interim variations in short-term cash flows, because the Utilities are 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 clauses and GSA rider.
From time to time, Laclede Gas 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, 2015, Laclede Gas held 1.8 million gallons of gasoline futures contracts at an average price of $1.63 per gallon. Most of these contracts, the longest of which extends to December 2016, 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 Laclede Gas’ PGA clause.
In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable userscourse of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its 100% 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, 2015, the fair values of 104.7 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 88.0 million MMBtu will settle during fiscal year 2016, and 14.9 million MMBtu, 1.7 million MMBtu, and 0.1 million MMBtu will settle during 2017, 2018, and 2019, respectively. 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 Clear Europe (ICE) futures, swap, and option contracts to lock in margins.
At September 30, 2015, 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.
On April 14, 2014, as amended on July 8, 2014, Laclede Group entered into certain interest rate swap agreements, with a notional amount $375.0, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Alagasco.
These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved 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, 2014, the interest rate swap agreements were terminated and the settlement resulted in a $19.0 loss by Laclede Group, which assigned the loss as a regulatory asset since the interest rate swaps were entered into to hedge the interest payments on the $625.0 of long-term debt issued on August 19, 2014 by Laclede Group.
During the second quarter of fiscal year 2015, Alagasco entered into certain interest rate swap transactions to protect itself against adverse movement in interest rates in anticipation of its issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved 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 May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability. Of the total anticipated issuance of long-term debt, $35.0 was issued on September 15, 2015 and the remaining $80.0 will be issued on December 1, 2015.
The Company’s and Laclede Gas' exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB 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, 2015 were as follows:
|
| | | | | | | | | | | | | |
| | Gas Utility | | Gas Marketing |
| | MMBtu (millions) | | Avg. Price Per MMBtu | | MMBtu (millions) | | Avg. Price Per MMBtu |
| NYMEX/ICE Open short futures positions | | | | | | | |
| Fiscal 2016 | — |
| | $ | — |
| | 13.34 |
| | $ | 3.26 |
|
| Fiscal 2017 | — |
| | — |
| | 2.13 |
| | 3.42 |
|
| NYMEX/ICE Open long futures/swap positions | |
| | |
| | |
| | |
|
| Fiscal 2016 | 29.02 |
| | 3.19 |
| | 7.06 |
| | 3.17 |
|
| Fiscal 2017 | 1.57 |
| | 3.04 |
| | 2.77 |
| | 3.43 |
|
| Fiscal 2018 | — |
| | — |
| | 0.12 |
| | 3.37 |
|
| ICE Open long basis swap positions | | | | | | | |
| Fiscal 2016 | — |
| | — |
| | 23.29 |
| | 0.27 |
|
| Fiscal 2017 | — |
| | — |
| | 9.04 |
| | 0.45 |
|
| Fiscal 2018 | — |
| | — |
| | 1.09 |
| | 0.50 |
|
| ICE Open short basis swap positions | | | | | | | |
| Fiscal 2016 | — |
| | — |
| | 10.62 |
| | 0.17 |
|
| Fiscal 2017 | — |
| | — |
| | 1.40 |
| | 0.20 |
|
| OTC Open long futures/swap positions | | | | | | | |
| Fiscal 2016 | 4.43 |
| | 3.99 |
| | — |
| | — |
|
| Fiscal 2017 | 0.32 |
| | 3.64 |
| | — |
| | — |
|
At September 30, 2015, Laclede Gas also had 20.3 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.
Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the balance sheets of the Company 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, 2015, it is expected that an immaterial amount of unrealized gains will be reclassified into the Consolidated Statements of Income of the Company during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Consolidated Statements of Cash Flows.
|
| | | | | | | | | | | | |
| Effect of Derivative Instruments on the Consolidated Statements of Income and Consolidated Statements of Comprehensive Income |
| | Location of Gain (Loss) | | | | | |
| | Recorded in Income | 2015 | | 2014 | | 2013 |
| Derivatives in Cash Flow Hedging Relationships | | | | | |
| Effective portion of gain (loss) recognized in OCI on derivatives: | | | | | |
| Gas Marketing natural gas contracts | | $ | (4.3 | ) | | $ | (4.6 | ) | | $ | 4.9 |
|
| Gas Utility gasoline and heating oil contracts | | (1.2 | ) | | 0.1 |
| | 0.1 |
|
| Total | | $ | (5.5 | ) | | $ | (4.5 | ) | | $ | 5.0 |
|
| Effective portion of gain (loss) reclassified from AOCI to income: | | | | | |
| Natural gas contracts | Gas Marketing Operating Revenues | $ | 1.7 |
| | $ | 4.2 |
| | $ | — |
|
| | Gas Marketing Operating Expenses | (5.2 | ) | | (1.5 | ) | | (0.5 | ) |
| Subtotal | | (3.5 | ) | | 2.7 |
|
| (0.5 | ) |
| Gasoline and heating oil contracts | Gas Utility Other Operating Expenses | (0.9 | ) | | (0.2 | ) | | 0.2 |
|
| Total | | $ | (4.4 | ) | | $ | 2.5 |
| | $ | (0.3 | ) |
Ineffective portion of gain (loss) on derivatives recognized in income: | | | | | | |
| Natural gas contracts | Gas Marketing Operating Revenues | $ | — |
| | $ | (0.1 | ) | | $ | (0.4 | ) |
| | Gas Marketing Operating Expenses | (0.5 | ) | | 0.1 |
| | (0.3 | ) |
| Subtotal | | (0.5 | ) | | — |
| | (0.7 | ) |
| Gasoline and heating oil contracts | Gas Utility Other Operating Expenses | 0.1 |
| | (0.2 | ) | | (0.1 | ) |
| Total | | $ | (0.4 | ) | | $ | (0.2 | ) | | $ | (0.8 | ) |
| Derivatives Not Designated as Hedging Instruments* | | | | | |
| Gain (loss) recognized in income on derivatives: | | | | | | |
| Natural gas commodity contracts | Gas Marketing Operating Revenues | $ | (1.3 | ) | | $ | (8.7 | ) | | $ | (0.9 | ) |
| NYMEX / ICE natural gas contracts | Gas Marketing Operating Revenues | (9.6 | ) | | 3.0 |
| | — |
|
| Gasoline and heating oil contracts | Other Income and (Income Deductions) - Net | (0.2 | ) | | — |
| | 0.1 |
|
| Total | | $ | (11.1 | ) | | $ | (5.7 | ) | | $ | (0.8 | ) |
| |
| * | Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Missouri Utilities' PGA clauses 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 income. Such amounts are recognized in the statements of 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. |
|
| | | | | | | | | |
| Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2015 |
| | Asset Derivatives* | | Liability Derivatives* |
| | Balance Sheet Location | Fair Value | | Balance Sheet Location | Fair Value |
| Derivatives designated as hedging instruments | | | | |
| Gas Utility: | | | | | |
| Gasoline and heating oil contracts | Accounts Receivable – Other | $ | — |
| | Accounts Receivable – Other | $ | 0.3 |
|
| Gas Marketing: | | | |
| |
| Natural gas contracts | Derivative Instrument Assets | 4.1 |
| | Derivative Instrument Assets | 3.2 |
|
| | Deferred Charges – Other | 1.1 |
| | Deferred Charges – Other | 0.5 |
|
| Subtotal | | 5.2 |
| | | 4.0 |
|
| Derivatives not designated as hedging instruments | | | | |
| Gas Utility: | | | | | |
| Natural gas contracts | Accounts Receivable – Other | 1.2 |
| | Accounts Receivable – Other | 16.4 |
|
| | Derivative Instrument Assets | — |
| | Derivative Instrument Assets | 5.7 |
|
| | Deferred Charges – Other | — |
| | Deferred Charges – Other | 0.2 |
|
| Subtotal | | 1.2 |
| | | 22.3 |
|
| Gas Marketing: | | | | | |
| NYMEX / ICE natural gas contracts | Derivative Instrument Assets | 4.7 |
| | Derivative Instrument Assets | 0.6 |
|
| | Deferred Charges – Other | 0.7 |
| | Deferred Charges – Other | 0.7 |
|
| Natural gas commodity | Derivative Instrument Assets | 1.4 |
| | Derivative Instrument Assets | 0.1 |
|
| | Current Liabilities – Other | 0.2 |
| | Current Liabilities – Other | 1.4 |
|
| | Deferred Credits – Other | 0.1 |
| | Deferred Credits – Other | 0.7 |
|
| Subtotal | | 7.1 |
| | | 3.5 |
|
| Total derivatives | | $ | 13.5 |
| | | $ | 29.8 |
|
| | | | | | |
| Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2014 |
| | Asset Derivatives* | | Liability Derivatives* |
| | Balance Sheet Location | Fair Value | | Balance Sheet Location | Fair Value |
| Derivatives designated as hedging instruments | | | | |
| Gas Utility: | | | | | |
| Gasoline and heating oil contracts | Accounts Receivable – Other | $ | — |
| | Accounts Receivable – Other | $ | 0.2 |
|
| Gas Marketing: | | | | | |
| Natural gas contracts | Derivative Instrument Assets | 0.7 |
| | Derivative Instrument Assets | 0.4 |
|
| | Deferred Charges – Other | 0.7 |
| | Deferred Charges – Other | 0.2 |
|
| Subtotal | | 1.4 |
| | | 0.8 |
|
| Derivatives not designated as hedging instruments | | | | |
| Gas Utility: | | | |
| |
| Natural gas contacts | Accounts Receivable – Other | 2.4 |
| | Accounts Receivable – Other | 5.2 |
|
| | Derivative Instrument Assets | 0.1 |
| | Derivative Instrument Assets | 3.7 |
|
| | Deferred Charges – Other | — |
| | Deferred Charges – Other | 0.4 |
|
| Subtotal | | 2.5 |
| | | 9.3 |
|
| Gas Marketing: | | | | | |
| Natural gas contacts | Derivative Instrument Assets | 3.5 |
| | Derivative Instrument Assets | 1.4 |
|
| | Deferred Charges – Other | 0.3 |
| | Deferred Charges – Other | — |
|
| | Current Liabilities – Other | — |
| | Current Liabilities – Other | 0.5 |
|
| Subtotal | | 3.8 |
| | | 1.9 |
|
| Total derivatives | | $ | 7.7 |
| | | $ | 12.0 |
|
| |
| * | 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 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 9, Fair Value Measurements, for information on the valuation of derivative instruments. |
Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:
|
| | | | | | | |
| | 2015 | | 2014 |
| Fair value of asset derivatives presented above | $ | 13.5 |
| | $ | 7.7 |
|
| Fair value of cash margin receivables offset with derivatives | 13.9 |
| | 3.0 |
|
| Netting of assets and liabilities with the same counterparty | (22.2 | ) | | (7.9 | ) |
| Total | $ | 5.2 |
| | $ | 2.8 |
|
| Derivative Instrument Assets, per Consolidated Balance Sheets: | | | |
| Derivative instrument assets | $ | 4.6 |
| | $ | 3.2 |
|
| Deferred Charges – Other | 0.6 |
| | (0.4 | ) |
| Total | $ | 5.2 |
| | $ | 2.8 |
|
| | | | |
| Fair value of liability derivatives presented above | $ | 29.8 |
| | $ | 12.0 |
|
| Netting of assets and liabilities with the same counterparty | (22.2 | ) | | (7.9 | ) |
| Total | $ | 7.6 |
| | $ | 4.1 |
|
| Derivative Instrument Liabilities, per Consolidated Balance Sheets: | | | |
| Current Liabilities – Other | $ | 6.8 |
| | $ | — |
|
| Deferred Credits – Other | 0.8 |
| | 4.1 |
|
| Total | $ | 7.6 |
| | $ | 4.1 |
|
Additionally, at September 30, 2015 and 2014, the Company had $5.9 and $4.4, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.
Laclede Gas
Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit Laclede Gas' exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. This policy strictly prohibits speculation and permits Laclede Gas to hedge current physical natural gas purchase commitments or forecasted or anticipated future peak (maximum) physical need for natural gas delivered. Costs and cost reductions, including carrying costs, associated with Laclede Gas’ use of natural gas derivative instruments are allowed to be passed on to Laclede Gas customers through the operation of its PGA clause, through which the MoPSC allows Laclede Gas to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments.
Laclede Gas 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 income.
The timing of the operation of the PGA clause may cause interim variations in short-term cash flows, because Laclede Gas 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, Laclede Gas 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, 2015, Laclede Gas held 1.8 million gallons of gasoline futures contracts at an average price of $1.63 per gallon. Most of these contracts, the longest of which extends to December 2016, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to Laclede Gas’ PGA clause.
Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the 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, 2015, it is expected that an immaterial amount of pre-tax gains will be reclassified into the statements of income during fiscal year 2016. 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 cash flows.
Laclede Gas’ derivative instruments consist primarily of NYMEX and OTCBB positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX and OTCBB natural gas futures positions at September 30, 2015 were as follows:
|
| | | | | | |
| | MMBtu (millions) | | Avg. Price Per MMBtu |
| NYMEX/ICE Open long futures/swap positions | |
| | |
|
| Fiscal 2016 | 29.02 |
| | $ | 3.19 |
|
| Fiscal 2017 | 1.57 |
| | 3.04 |
|
| OTC Open long futures/swap positions | | | |
| Fiscal 2016 | 4.43 |
| | $ | 3.99 |
|
| Fiscal 2017 | 0.32 |
| | 3.64 |
|
At September 30, 2015, Laclede Gas also had 20.3 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.
|
| | | | | | | | | | | | |
| Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income |
| | Location of Gain (Loss) | | | | | |
| | Recorded in Income | 2015 | | 2014 | | 2013 |
| Derivatives in Cash Flow Hedging Relationships | | | | | |
| Effective portion of gain (loss) recognized in OCI on derivatives: | | | | | |
| Gasoline and heating oil contracts | | $ | (1.2 | ) | | $ | 0.1 |
| | $ | 0.1 |
|
| Effective portion of gain (loss) reclassified from AOCI to income: | | | | | |
| Gasoline and heating oil contracts | Gas Utility Other Operating Expenses | $ | (0.9 | ) | | $ | (0.2 | ) | | $ | 0.2 |
|
Ineffective portion of gain (loss) on derivatives recognized in income: | | | | | | |
| Gasoline and heating oil contracts | Gas Utility Other Operating Expenses | $ | 0.1 |
| | $ | (0.2 | ) | | $ | (0.1 | ) |
| Derivatives Not Designated as Hedging Instruments* | | | | | |
| Gain (loss) recognized in income on derivatives: | | | | | | |
| Gasoline and heating oil contracts | Other Income and (Income Deductions) - Net | $ | (0.2 | ) | | $ | — |
| | $ | 0.1 |
|
| |
| * | Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Laclede Gas’ PGA clauses 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 Income. Such amounts are recognized in the Statements of 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. |
|
| | | | | | | | | |
| Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2015 |
| | Asset Derivatives* | | Liability Derivatives* |
| | Balance Sheet Location | Fair Value | | Balance Sheet Location | Fair Value |
| Derivatives designated as hedging instruments | | | | |
| Gasoline and heating oil contracts | Accounts Receivable – Other | $ | — |
| | Accounts Receivable – Other | $ | 0.3 |
|
| Subtotal | | — |
| | | 0.3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Natural gas contracts | Accounts Receivable – Other | 1.2 |
| | Accounts Receivable – Other | 16.4 |
|
| OTCBB natural gas contracts | Derivative Instrument Assets | — |
| | Derivative Instrument Assets | 5.7 |
|
| | Deferred Charges – Other | — |
| | Deferred Charges – Other | 0.2 |
|
| Subtotal | | 1.2 |
| | | 22.3 |
|
| Total derivatives | | $ | 1.2 |
| | | $ | 22.6 |
|
| | | | | | |
| Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2014 |
| | Asset Derivatives | | Liability Derivatives* |
| | Balance Sheet Location | Fair Value | * | Balance Sheet Location | Fair Value |
| Derivatives designated as hedging instruments | | | | |
| Gasoline and heating oil contracts | Accounts Receivable – Other | $ | — |
| | Accounts Receivable – Other | $ | 0.2 |
|
| Subtotal | | — |
| | | 0.2 |
|
| Derivatives not designated as hedging instruments | | | | |
| Natural gas contacts | Accounts Receivable – Other | 2.4 |
| | Accounts Receivable – Other | 5.2 |
|
| | Derivative Instrument Assets | 0.1 |
| | Derivative Instrument Assets | 3.7 |
|
| Gasoline and heating oil contracts | Accounts Receivable – Other | — |
| | Accounts Receivable – Other | 0.4 |
|
| Subtotal | | 2.5 |
| | | 9.3 |
|
| Total derivatives | | $ | 2.5 |
| | | $ | 9.5 |
|
| |
| * | 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 Balance Sheets. As such, the gross balances presented in the table above are not indicative of Laclede Gas' net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments. |
Following is a reconciliation of the amounts in the tables above to the amounts presented in Laclede Gas' Balance Sheets:
|
| | | | | | | |
| | 2015 | | 2014 |
| Fair value of asset derivatives presented above | $ | 1.2 |
| | $ | 2.5 |
|
| Fair value of cash margin receivables offset with derivatives | 15.5 |
| | 3.0 |
|
| Netting of assets and liabilities with the same counterparty | (16.7 | ) | | (5.9 | ) |
| Total | $ | — |
| | $ | (0.4 | ) |
| Derivative Instrument Assets, per Balance Sheets: | | | |
| Derivative instrument assets | $ | — |
| | $ | (0.4 | ) |
| Total | $ | — |
| | $ | (0.4 | ) |
| | | | |
| Fair value of liability derivatives presented above | $ | 22.6 |
| | $ | 9.5 |
|
| Netting of assets and liabilities with the same counterparty | (16.7 | ) | | (5.9 | ) |
| Total | $ | 5.9 |
| | $ | 3.6 |
|
| Derivative Instrument Liabilities, per Balance Sheets: | | | |
| Current Liabilities – Other | $ | 5.7 |
| | $ | — |
|
| Deferred Credits – Other | 0.2 |
| | 3.6 |
|
| Total | $ | 5.9 |
| | $ | 3.6 |
|
Additionally, at September 30, 2015 and 2014, Laclede Gas had $5.9 and $4.4, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.
Alagasco
During the second quarter of fiscal 2015, Alagasco entered into certain interest rate swap transactions to protect against adverse movement in interest rates in anticipation of the issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved 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 May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability since the interest rate swaps were entered into to hedge the interest payments on the $115.0 of long-term debt, of which $35.0 was issued on September 15, 2015, with the remaining $80.0 to be issued on December 1, 2015.
| |
| 11. | CONCENTRATION OF CREDIT RISK |
Other than in LER (the Gas Marketing segment), Laclede Group has no significant 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 understandassess 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. 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 $15.7 at September 30, 2015. Net receivable amounts from these customers on that same date, reflecting netting arrangements, were $13.4. LER'S accounts receivable attributable to utility companies and their
marketing affiliates comprised $21.6 of total accounts receivable at September 30, 2015, while net receivable amounts from these customers, reflecting netting arrangements, were $20.5.
LER also has concentrations of credit risk with certain individually significant counterparties and with pipeline companies associated with its natural gas receivable amount. At September 30, 2015, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $13.7. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these five customers on the same date, reflecting netting arrangements, were $12.5.
Laclede Group
The Company's provision for income taxes charged during the fiscal years ended September 30, 2015, 2014, and 2013 are as follows:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Federal | | | | | |
| Current | $ | (3.3 | ) | | $ | 0.3 |
| | $ | (4.2 | ) |
| Deferred | 58.8 |
| | 30.6 |
| | 19.9 |
|
| Investment tax credits | (0.2 | ) | | (0.2 | ) | | (0.2 | ) |
| State and local | | | | | |
| Current | — |
| | 0.6 |
| | (0.3 | ) |
| Deferred | 6.9 |
| | 1.0 |
| | 2.4 |
|
| Total income tax expense | $ | 62.2 |
| | $ | 32.3 |
| | $ | 17.6 |
|
The Company's effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
|
| | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Federal income tax statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
| State and local income taxes, net of federal income tax benefits | 3.0 |
| | 1.8 |
| | 3.5 |
|
| Certain expenses capitalized on books and deducted on tax return | (3.7 | ) | | (4.9 | ) | | (9.7 | ) |
| Taxes related to prior years | (0.6 | ) | | (0.7 | ) | | (1.6 | ) |
| Other items – net * | (2.5 | ) | | (3.6 | ) | | (2.2 | ) |
| Effective income tax rate | 31.2 | % | | 27.6 | % | | 25.0 | % |
* Other consists primarily of property adjustments.
The Company's significant items comprising the net deferred tax liability recorded in the Consolidated Balance Sheets as of September 30 are as follows:
|
| | | | | | | |
| | 2015 | | 2014 |
| Deferred tax assets: | | | |
| Reserves not currently deductible | $ | 14.8 |
| | $ | 16.0 |
|
| Pension and other postretirement benefits | 62.5 |
| | 67.3 |
|
| Operating losses | 47.3 |
| | 8.0 |
|
| Unamortized investment tax credits | 1.5 |
| | 1.6 |
|
| Other | — |
| | 28.9 |
|
| Total deferred tax assets | $ | 126.1 |
| | $ | 121.8 |
|
| Deferred tax liabilities: | | | |
| Relating to property | 472.1 |
| | 366.9 |
|
| Regulatory pension and other postretirement benefits | 110.6 |
| | 108.5 |
|
| Deferred gas costs | 8.1 |
| | 20.4 |
|
| Other | 11.6 |
| | 19.7 |
|
| Total deferred tax liabilities | $ | 602.4 |
| | $ | 515.5 |
|
| Net deferred tax liability | 476.3 |
| | 393.7 |
|
| Net deferred tax asset (liability) – current | 5.8 |
| | (9.9 | ) |
| Net deferred tax liability – noncurrent | $ | 482.1 |
| | $ | 383.8 |
|
In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not the Company will realize the benefits of these deferred tax assets.
The Company has federal and state loss carryforwards of approximately $123.9 at September 30, 2015. The Company also has contribution carryforwards of approximately $11.0 at September 30, 2015. The loss carryforwards begin to expire in the fiscal year ending 2030 for certain state purposes and 2035 for federal and other states purposes. The contribution carryforwards begin to expire in fiscal year 2018. The Company also has various tax credit carryforwards of approximately $2.8 that begin to expire in 2018.
The Company recognizes 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.
The following table presents a reconciliation of the beginning and ending balances of the Company's unrecognized tax benefits:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Unrecognized tax benefits, beginning of year | $ | 4.6 |
| | $ | 2.4 |
| | $ | 5.8 |
|
| Increases related to prior year tax positions | — |
| | — |
| | 0.1 |
|
| Increases related to tax positions taken in current year | 2.9 |
| | 2.6 |
| | 1.5 |
|
| Reductions due to lapse of applicable statute of limitations | (0.4 | ) | | (0.4 | ) | | (5.0 | ) |
| Unrecognized tax benefits, end of year | $ | 7.1 |
| | $ | 4.6 |
| | $ | 2.4 |
|
The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $3.1 and $2.5 as of September 30, 2015 and 2014, 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.
As of September 30, 2015 and 2014, interest accrued associated with the Company’s uncertain tax positions was de minimis, and no penalties were accrued as of September 30, 2015.
The Company is subject to US federal income tax as well as income tax in various state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2012.
Laclede Group completed the acquisition of 100% of the common shares of Alagasco from Energen on August 31, 2014. The Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco acquisition as a deemed purchase and sale of assets for tax purposes.
Laclede Gas
Laclede Gas' provision for income taxes charged during the fiscal years ended September 30, 2015, 2014, and 2013 are as follows:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Federal | | | | | |
| Current | $ | (2.1 | ) | | $ | (0.1 | ) | | $ | (6.6 | ) |
| Deferred | 40.9 |
| | 34.3 |
| | 20.1 |
|
| Investment tax credits | (0.2 | ) | | (0.2 | ) | | (0.2 | ) |
| State and local | | | | | |
| Current | (0.1 | ) | | — |
| | (1.0 | ) |
| Deferred | 4.7 |
| | 1.5 |
| | 2.3 |
|
| Total income tax expense | $ | 43.2 |
| | $ | 35.5 |
| | $ | 14.6 |
|
Laclede Gas' effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
|
| | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Federal income tax statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
| State and local income taxes, net of federal income tax benefits | 2.8 |
| | 1.8 |
| | 3.3 |
|
| Certain expenses capitalized on books and deducted on tax return | (4.9 | ) | | (4.5 | ) | | (10.8 | ) |
| Taxes related to prior years | (0.8 | ) | | (0.7 | ) | | (1.6 | ) |
| Other items – net * | (3.0 | ) | | (3.3 | ) | | (2.8 | ) |
| Effective income tax rate | 29.1 | % | | 28.3 | % | | 23.1 | % |
* Other consists primarily of property adjustments.
Laclede Gas' significant items comprising the net deferred tax liability reported in the Balance Sheets as of September 30 are as follows: |
| | | | | | | |
| | 2015 | | 2014 |
| Deferred tax assets: | | | |
| Reserves not currently deductible | $ | 15.4 |
| | $ | 16.0 |
|
| Pension and other postretirement benefits | 62.5 |
| | 67.3 |
|
| Operating losses | 3.7 |
| | 2.9 |
|
| Unamortized investment tax credits | 1.5 |
| | 1.6 |
|
| Other | — |
| | 17.8 |
|
| Total deferred tax assets | $ | 83.1 |
| | $ | 105.6 |
|
| Deferred tax liabilities: | | | |
| Relating to utility property | 425.0 |
| | 361.2 |
|
| Regulatory pension and other postretirement benefits | 120.2 |
| | 119.2 |
|
| Deferred gas costs | 8.2 |
| | 20.4 |
|
| Other | 14.5 |
| | 15.9 |
|
| Total deferred tax liabilities | $ | 567.9 |
| | $ | 516.7 |
|
| Net deferred tax liability | 484.8 |
| | 411.1 |
|
| Net deferred tax asset (liability) – current | 0.4 |
| | (11.3 | ) |
| Net deferred tax liability – noncurrent | $ | 485.2 |
| | $ | 399.8 |
|
Laclede Group files a consolidated federal return and various state income tax returns and allocates income taxes to Laclede Gas and its other subsidiaries as if each entity were a separate taxpayer.
In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Laclede Gas will realize the benefits of these deferred tax assets.
Laclede Gas has state and federal loss carryforwards of approximately $10.0, at September 30, 2015 based on separate company basis. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group. Laclede Gas also has contribution carryforwards of approximately $10.9 at September 30, 2015. The loss carryforwards begin to expire in the fiscal year ending 2035 for federal and state purposes. The contribution carryforwards begin to expire in fiscal year ending 2018. Laclede Gas also has approximately $1.5 of various tax credit carryforwards with expiration dates which begin to expire in 2024.
Laclede Gas recognizes 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. Laclede Gas 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 Balance Sheets.
The following table presents a reconciliation of the beginning and ending balances of Laclede Gas unrecognized tax benefits: |
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Unrecognized tax benefits, beginning of year | $ | 4.2 |
| | $ | 2.0 |
| | $ | 5.6 |
|
| Increases related to tax positions taken in current year | 2.9 |
| | 2.5 |
| | 1.4 |
|
| Reductions due to lapse of applicable statute of limitations | (0.2 | ) | | (0.3 | ) | | (5.0 | ) |
| Unrecognized tax benefits, end of year | $ | 6.9 |
| | $ | 4.2 |
| | $ | 2.0 |
|
The amount of unrecognized tax benefits, which, if recognized, would affect Laclede Gas' effective tax rate were $2.9 and $2.1 as of September 30, 2015 and 2014, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of Laclede Gas' unrecognized tax benefits. Laclede Gas does not expect that any such change will be significant to Laclede Gas' Balance Sheets.
As of September 30, 2015 and 2014, interest accrued associated with Laclede Gas' uncertain tax positions was de minimis, and no penalties were accrued.
Laclede Gas is subject to US federal income tax as well as income tax in various state and local jurisdictions, and is no longer subject to examination for fiscal year prior to 2012.
Alagasco
Alagasco's provision for income taxes charged during the fiscal year ended September 30, 2015, the nine months ended September 30, 2014, and the year ended December 31, 2013 are as follows:
|
| | | | | | | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, | | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Federal | | | | | |
| Current | $ | — |
| | $ | 14.1 |
| | $ | 17.5 |
|
| Deferred | 25.9 |
| | 3.5 |
| | 13.3 |
|
| State and local | | | | | |
| Current | 0.1 |
| | 1.8 |
| | 2.2 |
|
| Deferred | 3.3 |
| | 0.5 |
| | 1.7 |
|
| Total income tax expense | $ | 29.3 |
| | $ | 19.9 |
| | $ | 34.7 |
|
Alagasco's effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
|
| | | | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, | | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Federal income tax statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
| State and local income taxes, net of federal income tax benefits | 2.8 |
| | 2.8 |
| | 2.8 |
|
| Other items – net | 0.1 |
| | (0.2 | ) | | (0.1 | ) |
| Effective income tax rate | 37.9 | % | | 37.6 | % | | 37.7 | % |
Alagasco's significant items comprising the net deferred tax asset reported in the Balance Sheets as of September 30 are as follows: |
| | | | | | | |
| | 2015 | | 2014 |
| Deferred tax assets: | | | |
| Reserves not currently deductible | $ | 7.0 |
| | $ | 2.5 |
|
| Pension and other postretirement benefits | 9.6 |
| | 10.6 |
|
| Goodwill | 251.5 |
| | 266.1 |
|
| Operating losses | 32.4 |
| | 5.1 |
|
| Other | 1.4 |
| | 0.2 |
|
| Total deferred tax assets | $ | 301.9 |
| | $ | 284.5 |
|
| Deferred tax liabilities: | | | |
| Relating to utility property | 45.1 |
| | 4.0 |
|
| Other | 2.2 |
| | 0.4 |
|
| Total deferred tax liabilities | $ | 47.3 |
| | $ | 4.4 |
|
| Net deferred tax asset | 254.6 |
| | 280.1 |
|
| Net deferred tax asset – current | 6.2 |
| | 2.3 |
|
| Net deferred tax asset – noncurrent | $ | 248.4 |
| | $ | 277.8 |
|
Laclede Group files a consolidated federal return and various state income tax returns and allocates income taxes to Alagasco and its other subsidiaries as if each entity were a separate taxpayer.
In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Alagasco will realize the benefits of these deferred tax assets.
On a separate company basis, Alagasco has state and federal loss carryforwards of approximately $85.0, at September 30, 2015 generated since the acquisition. The loss carryforwards begin to expire in the fiscal year ending 2030 for state purposes and 2035 for federal purposes. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group.
Laclede Group completed the acquisition of 100% of the common shares of Alagasco from Energen on August 31, 2014. The Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco acquisition as a deemed purchase and sale of assets for tax purposes.
Alagasco recognizes 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. Alagasco 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 Balance Sheets.
The following table presents a reconciliation of the beginning and ending balances of Alagasco's unrecognized tax benefits:
|
| | | | | | | | | | | |
| | Year Ended September 30, | | Nine Months Ended September 30, | | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Unrecognized tax benefits, beginning of period | $ | — |
| | $ | 0.3 |
| | $ | 0.3 |
|
| Reduction for transfer of balance to Energen | — |
| | (0.3 | ) | | — |
|
| Unrecognized tax benefits, end of period | $ | — |
| | $ | — |
| | $ | 0.3 |
|
Alagasco is subject to US federal income tax as well as income tax in various state and local jurisdictions. Alagasco's tax returns for the calendar years 2010-2013 remain open and subject to examination by the Internal Revenue Service and state taxing jurisdictions. These returns cover periods during which Alagasco was owned by Energen. The impact of any adjustments made to these returns by the relevant taxing authorities would be addressed by the indemnification provisions of the agreement.
13. 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 or those acquired in the Alagasco Transaction effective August 31, 2014. The net pension and postretirement obligations were re-measured at the applicable acquisition dates as well as at the fiscal year end.
Pension Plans
The pension plans of Laclede Group consist of plans for employees at the Missouri Utilities and plans covering the employees of Alagasco.
The Missouri Utilities have non-contributory, defined benefit, trusteed forms of pension plans covering the majority of their employees. Plan assets consist primarily of corporate and US 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.
Alagasco has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Qualified plan assets are comprised of United States equities consisting of mutual and commingled funds with varying strategies, global equities consisting of mutual funds, alternative investments of limited partnerships and commingled and mutual funds, and fixed income investments.
The net periodic pension costs include the following components:
|
| | | | | | | | | | | |
| | 2015 | | 2014* | | 2013 |
| Laclede Group | | | | | |
| Service cost – benefits earned during the period | $ | 17.3 |
| | $ | 10.2 |
| | $ | 9.2 |
|
| Interest cost on projected benefit obligation | 29.5 |
| | 24.5 |
| | 17.0 |
|
| Expected return on plan assets | (37.4 | ) | | (27.2 | ) | | (19.4 | ) |
| Amortization of prior other comprehensive income | — |
| | 0.4 |
| | — |
|
| Amortization of prior service cost | 0.5 |
| | 0.5 |
| | 0.5 |
|
| Amortization of actuarial loss | 7.5 |
| | 7.1 |
| | 10.7 |
|
| Loss on lump-sum settlements | 19.6 |
| | 1.5 |
| | 27.0 |
|
| Subtotal | 37.0 |
| | 17.0 |
| | 45.0 |
|
| Regulatory adjustment | (2.1 | ) | | 10.4 |
| | (27.5 | ) |
| Net pension cost | $ | 34.9 |
| | $ | 27.4 |
| | $ | 17.5 |
|
| | * Includes Alagasco. | | |
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Laclede Gas | | | | | |
| Service cost – benefits earned during the period | $ | 11.5 |
| | $ | 9.7 |
| | $ | 9.2 |
|
| Interest cost on projected benefit obligation | 23.3 |
| | 24.0 |
| | 17.0 |
|
| Expected return on plan assets | (29.2 | ) | | (26.5 | ) | | (19.4 | ) |
| Amortization of prior service cost | 0.5 |
| | 0.5 |
| | 0.5 |
|
| Amortization of actuarial loss | 7.5 |
| | 7.1 |
| | 10.7 |
|
| Loss on lump-sum settlements | 18.0 |
| | 1.5 |
| | 27.0 |
|
| Subtotal | 31.6 |
| | 16.3 |
| | 45.0 |
|
| Regulatory adjustment | (5.2 | ) | | 10.4 |
| | (27.5 | ) |
| Net pension cost | $ | 26.4 |
| | $ | 26.7 |
| | $ | 17.5 |
|
|
| | | | | | | | | | | |
| | 2015 | | 2014* | | 2013** |
| Alagasco | | | | | |
| Service cost – benefits earned during the period | $ | 5.8 |
| | $ | 5.1 |
| | $ | 14.2 |
|
| Interest cost on projected benefit obligation | 6.2 |
| | 4.1 |
| | 11.2 |
|
| Expected return on plan assets | (8.2 | ) | | (5.2 | ) | | (14.7 | ) |
| Amortization of prior service cost | — |
| | 0.1 |
| | 0.5 |
|
| Amortization of actuarial loss | — |
| | 2.2 |
| | 14.0 |
|
| Loss on lump-sum settlements | 1.6 |
| | 10.1 |
| | 1.4 |
|
| Subtotal | 5.4 |
| | 16.4 |
| | 26.6 |
|
| Regulatory adjustment | 3.1 |
| | 0.4 |
| | — |
|
| Net pension cost | $ | 8.5 |
| | $ | 16.8 |
| | $ | 26.6 |
|
| | * Nine months ended September 30, |
| | ** Year ended December 31, 2013 |
Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Laclede Group | | | | | |
| Current year actuarial loss | $ | 48.3 |
| | $ | 15.7 |
| | $ | 17.0 |
|
| Amortization of actuarial loss | (7.5 | ) | | (7.1 | ) | | (10.7 | ) |
| Acceleration of loss recognized due to settlement | (19.6 | ) | | (1.5 | ) | | (27.0 | ) |
| Amortization of prior service cost | (0.5 | ) | | (0.5 | ) | | (0.5 | ) |
| Subtotal | 20.7 |
| | 6.6 |
| | (21.2 | ) |
| Regulatory adjustment | (21.2 | ) | | (6.1 | ) | | 21.1 |
|
| Total recognized in other comprehensive income | $ | (0.5 | ) | | $ | 0.5 |
| | $ | (0.1 | ) |
| | * Includes Alagasco. | | |
| | | | | | |
| Laclede Gas | 2015 | | 2014 | | 2013 |
| Current year actuarial loss | $ | 26.0 |
| | $ | 14.2 |
| | $ | 17.0 |
|
| Amortization of actuarial loss | (7.5 | ) | | (7.1 | ) | | (10.7 | ) |
| Acceleration of loss recognized due to settlement | (18.0 | ) | | (1.5 | ) | | (27.0 | ) |
| Amortization of prior service cost | (0.5 | ) | | (0.5 | ) | | (0.5 | ) |
| Subtotal | — |
| | 5.1 |
| | (21.2 | ) |
| Regulatory adjustment | (0.5 | ) | | (4.7 | ) | | 21.1 |
|
| Total recognized in other comprehensive income | $ | (0.5 | ) | | $ | 0.4 |
| | $ | (0.1 | ) |
| | | | | | |
| | | | | | |
| Alagasco | 2015 | | 2014* | | 2013** |
| Current year actuarial loss | $ | 22.3 |
| | $ | 1.5 |
| | $ | (14.1 | ) |
| Amortization of actuarial loss | — |
| | — |
| | (8.9 | ) |
| Acceleration of loss recognized due to settlement | (1.6 | ) | | — |
| | — |
|
| Amortization of prior service cost | — |
| | — |
| | (0.3 | ) |
| Subtotal | 20.7 |
| | 1.5 |
| | (23.3 | ) |
| Regulatory adjustment | (20.7 | ) | | (1.5 | ) | | — |
|
| Total recognized in other comprehensive income | $ | — |
| | $ | — |
| | $ | (23.3 | ) |
| | * Nine months ended September 30 |
| | ** Year ended December 31 |
Laclede Group pension obligations are driven by separate plan and regulatory provisions governing Laclede Gas and Alagasco pension plans.
Pursuant to the provisions of the Missouri Utilities' and Alagasco's pension plans, pension obligations may be satisfied by lump-sum cash payments. 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 in a specific year. Two Laclede Gas plans and one Alagasco plan met the criteria for settlement recognition in the fiscal year ended September 30, 2015, requiring re-measurement of the obligation under those plans using updated census data and assumptions for discount rate and mortality. Lump-sum payments recognized as settlements during fiscal year 2015, 2014, and 2013 were $71.1 ($58.2 attributable to Laclede Gas and $12.9 attributable to Alagasco), $22.1, and $79.5, 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' eastern Missouri qualified pension plan is based on an annual allowance of $15.5 effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 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 income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.
The following table shows the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014** | | 2015 | | 2014 | | 2015 | | 2014*** |
| Benefit obligation, beginning of year | $ | 692.4 |
| | $ | 503.8 |
| | $ | 543.6 |
| | $ | 503.8 |
| | $ | 148.8 |
| | $ | 293.4 |
|
| Service cost | 17.3 |
| | 10.2 |
| | 11.5 |
| | 9.7 |
| | 5.8 |
| | 5.1 |
|
| Interest cost | 29.5 |
| | 24.5 |
| | 23.3 |
| | 24.0 |
| | 6.2 |
| | 4.1 |
|
| Actuarial (gain) loss | (12.8 | ) | | 39.4 |
| | (20.7 | ) | | 41.5 |
| | 7.9 |
| | 7.8 |
|
| Energen divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | (127.8 | ) |
| Alagasco acquisition | — |
| | 150.2 |
| | — |
| | — |
| | — |
| | — |
|
| Settlement loss | 16.5 |
| | 1.2 |
| | 14.5 |
| | 1.2 |
| | 2.0 |
| | — |
|
| Gross benefits paid * | (90.6 | ) | | (36.9 | ) | | (74.6 | ) | | (36.6 | ) | | (16.0 | ) | | (33.8 | ) |
| Benefit obligation, end of year | $ | 652.3 |
| | $ | 692.4 |
| | $ | 497.6 |
| | $ | 543.6 |
| | $ | 154.7 |
| | $ | 148.8 |
|
| Accumulated benefit obligation, end of year | 591.4 |
| | $ | 613.7 |
| | 456.9 |
| | $ | 484.1 |
| | 134.5 |
| | $ | 129.6 |
|
| |
| * | Includes $71.1 ($58.2 attributable to Laclede Gas and $12.9 to Alagasco) and $22.1 lump-sum payments recognized as settlements in fiscal years 2015 and 2014, respectively. |
** Includes Alagasco.
*** Nine-month transition period ended September 30.
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014** |
| Fair value of plan assets, beginning of year | $ | 506.6 |
| | $ | 345.4 |
| | $ | 387.4 |
| | $ | 345.4 |
| | $ | 119.2 |
| | $ | 219.5 |
|
| Actual return on plan assets | (7.2 | ) | | 52.1 |
| | (3.0 | ) | | 55.0 |
| | (4.2 | ) | | 7.8 |
|
| Employer contributions | 40.1 |
| | 23.6 |
| | 30.1 |
| | 23.6 |
| | 10.0 |
| | 1.6 |
|
| Settlements | (71.1 | ) | | — |
| | (58.2 | ) | | — |
| | (12.9 | ) | | — |
|
| Energen divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | (75.9 | ) |
| Alagasco acquisition | — |
| | 122.4 |
| | — |
| | — |
| | — |
| | — |
|
| Gross benefits paid | (19.5 | ) | | (36.9 | ) | | (16.4 | ) | | (36.6 | ) | | (3.1 | ) | | (33.8 | ) |
| Fair value of plan assets, end of year | $ | 448.9 |
| | $ | 506.6 |
| | $ | 339.9 |
| | $ | 387.4 |
| | $ | 109.0 |
| | $ | 119.2 |
|
| Funded status of plans, end of year | $ | (203.4 | ) | | $ | (185.8 | ) | | $ | (157.7 | ) | | $ | (156.2 | ) | | $ | (45.7 | ) | | $ | (29.6 | ) |
* Includes Alagasco.
** Nine-month transition period ended September 30.
The following table sets forth the amounts recognized in the balance sheets at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014** |
| Current liabilities | $ | (0.5 | ) | | $ | (0.5 | ) | | $ | (0.5 | ) | | $ | (0.5 | ) | | $ | — |
| | $ | — |
|
| Noncurrent liabilities | (202.9 | ) | | (185.4 | ) | | (157.2 | ) | | (155.7 | ) | | (45.7 | ) | | (29.6 | ) |
| Total | $ | (203.4 | ) | | $ | (185.9 | ) | | $ | (157.7 | ) | | $ | (156.2 | ) | | $ | (45.7 | ) | | $ | (29.6 | ) |
* Includes Alagasco.
** Nine-month transition period ended September 30.
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014** |
| Net actuarial loss | $ | 143.9 |
| | $ | 7.7 |
| | $ | 121.9 |
| | $ | 7.7 |
| | $ | 22.0 |
| | $ | 1.5 |
|
| Prior service costs | 3.5 |
| | 0.5 |
| | 3.5 |
| | 0.5 |
| | — |
| | — |
|
| Subtotal | 147.4 |
| | 8.2 |
| | 125.4 |
| | 8.2 |
| | 22.0 |
| | 1.5 |
|
| Adjustments for amounts included in Regulatory Assets | (144.9 | ) | | (7.9 | ) | | (122.9 | ) | | (7.9 | ) | | (22.0 | ) | | (1.5 | ) |
| Total | $ | 2.5 |
| | $ | 0.3 |
| | $ | 2.5 |
| | $ | 0.3 |
| | $ | — |
| | $ | — |
|
* Includes Alagasco.
** Nine-month transition period ended September 30.
At September 30, 2015, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2016:
|
| | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| Amortization of net actuarial loss | $ | 7.8 |
| | $ | 7.8 |
| | $ | — |
|
| Amortization of prior service cost | 0.4 |
| | 0.4 |
| | — |
|
| Subtotal | 8.2 |
| | 8.2 |
| | — |
|
| Regulatory adjustment | (7.9 | ) | | (7.9 | ) | | — |
|
| Total | $ | 0.3 |
| | $ | 0.3 |
| | $ | — |
|
Alagasco has no amounts to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal 2016.
The assumptions used to calculate net periodic pension costs for Laclede Gas are as follows:
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| Weighted average discount rate - Laclede Gas plans | 4.30% | | 4.70% | | 3.95% |
| Weighted average discount rate - MGE plans | 4.45% | | 5.00% | | 5.05% |
| 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% | | 7.75% |
| |
* | Assumptions for weighted average rate of future compensation increase and expected long-term rate of return on plan assets are the same for both Laclede Gas and MGE plans. |
The assumptions used to calculate net periodic pension costs for Alagasco are as follows:
|
| | | | | |
| | 2015 | | 2014 * | | 2013 ** |
| Weighted average discount rate | 4.15% /4.25% | | 4.00% / 4.05% | | 3.63% |
| Weighted average rate of future compensation increase | 2.92% | | 2.92% | | 3.71% |
| Expected long-term rate of return on plan assets | 7.00% / 7.25% | | 7.00% / 7.25% | | 7.00% |
* Nine-month transition period ended September 30.
** Year Ended December 31.
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:
|
| | | |
| | 2015 | | 2014 |
| Weighted average discount rate - Laclede Gas | 4.40% | | 4.30% |
| Weighted average discount rate - MGE | 4.50% | | 4.45% |
| Weighted average discount rate - Alagasco | 4.25%/4.30% | | 4.15% / 4.25% |
| Weighted average rate of future compensation increase (Laclede Gas and MGE) | 3.00% | | 3.00% |
| Weighted average rate of future compensation increase (Alagasco) | 3.00% | | 2.92% |
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:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2015 | | 2014 |
| Projected benefit obligation | $ | 652.3 |
| | $ | 692.4 |
| | $ | 497.6 |
| | $ | 543.6 |
| | $ | 154.7 |
| | $ | 148.8 |
|
| Accumulated benefit obligation | 591.4 |
| | 613.7 |
| | 456.9 |
| | 484.1 |
| | 134.5 |
| | 129.6 |
|
| Fair value of plan assets | 448.9 |
| | 506.6 |
| | 339.9 |
| | 387.4 |
| | 109.0 |
| | 119.2 |
|
Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas:
|
| | | | | | | | | | |
| | 2015 Target | | 2015 Actual | 2014 Target | | 2014 Actual |
| Growth Strategy | | | | | | |
| Equity markets | 52.0 | % | | 48.4 | % | 50.0 | % | | 51.2 | % |
| Debt securities | 48.0 | % | | 50.1 | % | 50.0 | % | | 48.7 | % |
| Other* | — | % | | 1.5 | % | — | % | | 0.1 | % |
| Total | 100.0 | % | | 100.0 | % | 100.0 | % | | 100.0 | % |
* Other investments in 2015 and 2014 consist of cash equivalents.
Laclede Gas' investment policies are 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 Laclede Gas' 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, US 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. During 2015, the target portfolio was rebalanced to include a higher weighting for the growth (equity) component and a lower weighting to the liability-driven (debt) component. 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 the targeted and actual plan assets by category as of September 30 of each year for Alagasco:
|
| | | | | | | | | | | |
| | 2015 Target | | 2015 Actual | | 2014 Target | | 2014 Actual |
| Equity markets | 60.0 | % | | 52.9 | % | | 46.0 | % | | 46.0 | % |
| Debt securities | 29.0 | % | | 27.9 | % | | 33.0 | % | | 29.0 | % |
| Other* | 11.0 | % | | 19.2 | % | | 21.0 | % | | 25.0 | % |
| Total | 100.0 | % | | 100.0 | % | | 100.0 | % | | 100.0 | % |
* Other investments in 2015 and 2014 include cash and cash equivalents, hedge funds, real estate, and all asset funds, which can invest in equities or fixed income.
Alagasco employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions. Alagasco has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained Alagasco to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily. Alagasco seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. During 2015, the target portfolio was rebalanced to include a higher weighting for the growth (equity) component and a lower weighting to the liability-driven (debt) component and the inflation hedging / cash (other) component.
Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter for Laclede Group, Laclede Gas, and Alagasco:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Laclede Group | | Laclede Gas | | Alagasco |
| | | Pensions from Qualified Trust | | Pensions from Company Funds | | Pensions from Qualified Trust | | Pensions from Laclede Gas Funds | | Pensions from Qualified Trust |
| 2016 | | $ | 45.9 |
| | $ | 0.5 |
| | $ | 36.4 |
| | $ | 0.5 |
| | $ | 9.5 |
|
| 2017 | | 45.7 |
| | 0.6 |
| | 35.7 |
| | 0.6 |
| | 10.0 |
|
| 2018 | | 43.5 |
| | 0.5 |
| | 33.9 |
| | 0.5 |
| | 9.6 |
|
| 2019 | | 44.9 |
| | 0.4 |
| | 35.0 |
| | 0.4 |
| | 9.9 |
|
| 2020 | | 46.4 |
| | 0.5 |
| | 35.4 |
| | 0.5 |
| | 11.0 |
|
| 2021 – 2025 | | 235.0 |
| | 2.1 |
| | 177.3 |
| | 2.1 |
| | 57.7 |
|
The funding policy of Laclede Gas 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 2016 are anticipated to be $26.0 into the qualified trusts, and $0.5 into the non-qualified plans.
The funding policy of Alagasco 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. There are no required contributions to the qualified pension plans during 2016. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. During fiscal 2016 the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions.
Postretirement Benefits
The Utilities provide certain life insurance benefits at retirement. Laclede Gas plans provide for medical insurance after early retirement until age 65. For retirements prior to January 1, 2015, the MGE plans provided medical insurance after retirement until death. For retirements after January 1, 2015, the MGE plans provide medical insurance after early retirement until age 65. The transition obligation not yet included in postretirement benefit cost is being amortized over 20 years. Under the Alagasco plans, medical insurance is currently available upon retirement until death for certain retirees depending on the type of employee and the date the employee was originally hired.
Net periodic postretirement benefit costs consist of the following components:
|
| | | | | | | | | | | |
| Laclede Group | 2015 | | 2014* | | 2013 |
| Service cost – benefits earned during the period | $ | 12.8 |
| | $ | 11.3 |
| | $ | 10.2 |
|
| Interest cost on accumulated postretirement benefit obligation | 11.2 |
| | 8.9 |
| | 5.2 |
|
| Expected return on plan assets | (13.2 | ) | | (7.3 | ) | | (4.5 | ) |
| Amortization of prior other comprehensive loss | — |
| | (0.2 | ) | | — |
|
| Amortization of transition obligation | — |
| | — |
| | 0.1 |
|
| Amortization of prior service credit | 0.8 |
| | — |
| | — |
|
| Amortization of actuarial loss | 5.1 |
| | 6.0 |
| | 5.3 |
|
| Subtotal | 16.7 |
| | 18.7 |
| | 16.3 |
|
| Regulatory adjustment | (11.0 | ) | | (9.6 | ) | | (6.8 | ) |
| Net postretirement benefit cost | $ | 5.7 |
| | $ | 9.1 |
| | $ | 9.5 |
|
| | * Includes Alagasco. | | |
| | | | | | |
| Laclede Gas | 2015 | | 2014 | | 2013 |
| Service cost – benefits earned during the period | $ | 12.3 |
| | $ | 11.2 |
| | $ | 10.2 |
|
| Interest cost on accumulated postretirement benefit obligation | 8.6 |
| | 8.7 |
| | 5.2 |
|
| Expected return on plan assets | (8.1 | ) | | (6.8 | ) | | (4.5 | ) |
| Amortization of transition obligation | — |
| | — |
| | 0.1 |
|
| Amortization of prior service credit | 0.8 |
| | — |
| | — |
|
| Amortization of actuarial loss | 5.1 |
| | 6.0 |
| | 5.3 |
|
| Subtotal | 18.7 |
| | 19.1 |
| | 16.3 |
|
| Regulatory adjustment | (9.2 | ) | | (9.6 | ) | | (6.8 | ) |
| Net postretirement benefit cost | $ | 9.5 |
| | $ | 9.5 |
| | $ | 9.5 |
|
| | | | | | |
| Alagasco | 2015 | | 2014 * | | 2013 ** |
| Service cost – benefits earned during the period | $ | 0.5 |
| | $ | 0.4 |
| | $ | 1.7 |
|
| Interest cost on accumulated postretirement benefit obligation | 2.6 |
| | 1.9 |
| | 3.5 |
|
| Expected return on plan assets | (5.1 | ) | | (3.6 | ) | | (5.0 | ) |
| Amortization of transition obligation | — |
| | — |
| | 1.3 |
|
| Amortization of actuarial loss | — |
| | (1.0 | ) | | (0.1 | ) |
| Curtailment gain | — |
| | — |
| | (1.2 | ) |
| Subtotal | (2.0 | ) | | (2.3 | ) | | 0.2 |
|
| Regulatory adjustment | (1.8 | ) | | (0.2 | ) | | — |
|
| Net postretirement benefit cost | $ | (3.8 | ) | | $ | (2.5 | ) | | $ | 0.2 |
|
| | * Nine months ended September 30 |
| | ** Year ended December 31 |
Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:
|
| | | | | | | | | | | |
| Laclede Group | 2015 | | 2014* | | 2013 |
| Current year actuarial (gain) loss | $ | (8.5 | ) | | $ | (3.1 | ) | | $ | 16.3 |
|
| Amortization of actuarial loss | (5.1 | ) | | (6.0 | ) | | (5.3 | ) |
| Amortization of prior service credit | (0.8 | ) | | 2.5 |
| | — |
|
| Current year prior service credit | (4.9 | ) | | — |
| | — |
|
| Amortization of transition obligation | — |
| | — |
| | (0.1 | ) |
| Subtotal | (19.3 | ) | | (6.6 | ) | | 10.9 |
|
| Regulatory adjustment | 19.3 |
| | 6.6 |
| | (10.9 | ) |
| Total recognized in other comprehensive income | $ | — |
| | $ | — |
| | $ | — |
|
*Includes Alagasco.
| | | | | |
| | | | | | |
| Laclede Gas | 2015 | | 2014 | | 2013 |
| Current year actuarial (gain) loss | $ | (2.4 | ) | | $ | (4.2 | ) | | $ | 16.3 |
|
| Amortization of actuarial loss | (5.1 | ) | | (6.0 | ) | | (5.3 | ) |
| Amortization of prior service credit | (0.8 | ) | | 2.5 |
| | — |
|
| Current year prior service credit | (4.9 | ) | | — |
| | — |
|
| Amortization of transition obligation | — |
| | — |
| | (0.1 | ) |
| Subtotal | (13.2 | ) | | (7.7 | ) | | 10.9 |
|
| Regulatory adjustment | 13.2 |
| | 7.7 |
| | (10.9 | ) |
| Total recognized in other comprehensive income | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Alagasco | 2015 | | 2014 | | 2013 |
| Current year actuarial (gain) loss | $ | (6.1 | ) | | $ | 1.1 |
| | $ | (8.1 | ) |
| Amortization of actuarial loss | — |
| | — |
| | 0.6 |
|
| Amortization of transition obligation | — |
| | — |
| | (0.3 | ) |
| Subtotal | (6.1 | ) | | 1.1 |
| | (7.8 | ) |
| Regulatory adjustment | 6.1 |
| | (1.1 | ) | | — |
|
| Total recognized in other comprehensive income | $ | — |
| | $ | — |
| | $ | (7.8 | ) |
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 $9.5 effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the statements of income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.
The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| ($ Millions) | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014 ** |
| Benefit obligation, beginning of year | $ | 258.5 |
| | $ | 180.1 |
| | $ | 197.9 |
| | $ | 180.1 |
| | $ | 60.6 |
| | $ | 63.3 |
|
| Service cost | 12.8 |
| | 11.3 |
| | 12.3 |
| | 11.2 |
| | 0.5 |
| | 0.4 |
|
| Interest cost | 11.2 |
| | 8.9 |
| | 8.6 |
| | 8.7 |
| | 2.6 |
| | 1.9 |
|
| Actuarial loss (gain) | (23.7 | ) | | 1.2 |
| | (10.9 | ) | | 2.2 |
| | (12.8 | ) | | 4.3 |
|
| Plan amendments | (4.9 | ) | | 2.5 |
| | (4.9 | ) | | 2.5 |
| | — |
| | — |
|
| Energen divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | (5.6 | ) |
| Alagasco acquisition | — |
| | 61.8 |
| | — |
| | — |
| | — |
| | — |
|
| Retiree drug subsidy program | 0.4 |
| | — |
| | — |
| | — |
| | 0.4 |
| | 0.3 |
|
| Gross benefits paid | (15.1 | ) | | (7.3 | ) | | (11.1 | ) | | (6.8 | ) | | (4.0 | ) | | (4.0 | ) |
| Benefit obligation, end of year | $ | 239.2 |
| | $ | 258.5 |
| | $ | 191.9 |
| | $ | 197.9 |
| | $ | 47.3 |
| | $ | 60.6 |
|
| | * Includes Alagasco. |
| | ** Nine-month transition period ended September 30. |
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014 |
| Fair value of plan assets at beginning of year | $ | 222.5 |
| | $ | 111.6 |
| | $ | 137.2 |
| | $ | 111.6 |
| | $ | 85.3 |
| | $ | 98.6 |
|
| Actual return on plan assets | (2.0 | ) | | 11.6 |
| | (0.4 | ) | | 13.3 |
| | (1.6 | ) | | 1.4 |
|
| Employer contributions | 17.9 |
| | 19.1 |
| | 17.9 |
| | 19.1 |
| | — |
| | 0.3 |
|
| Energen divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | (11.0 | ) |
| Alagasco acquisition | — |
| | 87.5 |
| | — |
| | — |
| | — |
| | — |
|
| Gross benefits paid | (15.1 | ) | | (7.3 | ) | | (11.1 | ) | | (6.8 | ) | | (4.0 | ) | | (4.0 | ) |
| Fair value of plan assets, end of year | $ | 223.3 |
| | $ | 222.5 |
| | $ | 143.6 |
| | $ | 137.2 |
| | $ | 79.7 |
| | $ | 85.3 |
|
| Funded status of plans, end of year | $ | (15.9 | ) | | $ | (36.0 | ) | | $ | (48.3 | ) | | $ | (60.7 | ) | | $ | 32.4 |
| | $ | 24.7 |
|
| | * Includes Alagasco. |
| | ** Nine-month transition period ended September 30. |
The following table sets forth the amounts recognized in the balance sheets at September 30:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014 |
| Noncurrent assets | $ | 35.5 |
| | $ | 25.0 |
| | $ | 3.1 |
| | $ | 0.3 |
| | $ | 32.4 |
| | $ | 24.7 |
|
| Current liabilities | (0.3 | ) | | (0.3 | ) | | (0.3 | ) | | (0.3 | ) | | — |
| | — |
|
| Noncurrent liabilities | (51.1 | ) | | (60.7 | ) | | (51.1 | ) | | (60.7 | ) | | — |
| | — |
|
| Total | $ | (15.9 | ) | | $ | (36.0 | ) | | $ | (48.3 | ) | | $ | (60.7 | ) | | $ | 32.4 |
| | $ | 24.7 |
|
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014* | | 2015 | | 2014 | | 2015 | | 2014 |
| Net actuarial loss | $ | 40.8 |
| | $ | 54.4 |
| | $ | 45.8 |
| | $ | 53.3 |
| | $ | (5.0 | ) | | $ | 1.1 |
|
| Prior service credit | (3.1 | ) | | 2.5 |
| | (3.1 | ) | | 2.5 |
| | — |
| | — |
|
| Subtotal | 37.7 |
| | 56.9 |
| | 42.7 |
| | 55.8 |
| | (5.0 | ) | | 1.1 |
|
| Adjustments for amounts included in Regulatory Assets | $ | (37.7 | ) | | $ | (56.9 | ) | | $ | (42.7 | ) | | $ | (55.8 | ) | | $ | 5.0 |
| | $ | (1.1 | ) |
| Total | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
At September 30, 2015, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2016:
|
| | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| Amortization of net actuarial loss | $ | 3.7 |
| | $ | 3.9 |
| | $ | (0.2 | ) |
| Amortization of prior service cost | 0.3 |
| | 0.3 |
| | — |
|
| Subtotal | 4.0 |
| | 4.2 |
| | (0.2 | ) |
| Regulatory adjustment | (4.0 | ) | | (4.2 | ) | | 0.2 |
|
| Total | $ | — |
| | $ | — |
| | $ | — |
|
The assumptions used to calculate net periodic postretirement benefit costs for Laclede Gas are as follows:
|
| | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Weighted average discount rate Laclede Gas plans | 4.15 | % | | 4.60 | % | | 3.80 | % |
| Weighted average discount rate MGE plans | 4.40 | % | | 4.95 | % | | 5.00 | % |
| Weighted average rate of future compensation increase (Laclede Gas and MGE Plans) | 3.00 | % | | 3.00 | % | | 3.00 | % |
| Expected long-term rate of return on plan assets - Laclede Gas plans | 6.25% / 7.75% |
| | 6.25% / 7.75% |
| | 7.75 | % |
| Expected long-term rate of return on plan assets - MGE plans | 5.00 | % | | 3.75% / 5.75% |
| | 5.75 | % |
The assumptions used to calculate net periodic postretirement benefit costs for Alagasco are as follows:
|
| | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| Weighted average discount rate | 4.40 | % | | 4.25 | % | | 4.26 | % |
| Expected long-term rate of return on plan assets | 4.75% / 7.50% |
| | 4.75% / 7.25% |
| | 7.00 | % |
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 accumulated postretirement benefit obligations for Laclede Gas are as follows:
|
| | | | | |
| | 2015 | | 2014 |
| Weighted average discount rate - Laclede Gas plans | 4.00 | % | | 4.15 | % |
| Weighted average discount rate - MGE Plans | 4.30 | % | | 4.40 | % |
| Weighted average rate of future compensation increase | 3.00 | % | | 3.00 | % |
The assumptions used to calculate the accumulated postretirement benefit obligations for Alagasco are as follows:
|
| | | | | |
| | 2015 | | 2014 |
| Weighted average discount rate | 4.50 | % | | 4.40 | % |
| Weighted average rate of future compensation increase | n/a |
| | n/a |
|
The assumed medical cost trend rates at September 30 are as follows:
|
| | | | | |
| | 2015 | | 2014 |
| Medical cost trend assumed for next year - Laclede Gas & MGE | 7.00 | % | | 7.50 | % |
| Medical cost trend assumed for next year - Alagasco | 7.00 | % | | 7.25 | % |
| 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 |
| | 2020 |
|
The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:
|
| | | | | | | |
| | 1% Increase | | 1% Decrease |
| Laclede Group | | | |
| Effect on net periodic postretirement benefit cost | $ | 1.6 |
| | $ | (1.5 | ) |
| Effect on accumulated postretirement benefit obligation | 9.2 |
| | (8.5 | ) |
| | | | |
| Laclede Gas | | | |
| Effect on net periodic postretirement benefit cost | $ | 1.5 |
| | $ | (1.4 | ) |
| Effect on accumulated postretirement benefit obligation | 8.7 |
| | (8.0 | ) |
| | | | |
| Alagasco | | | |
| Effect on net periodic postretirement benefit cost | $ | 0.1 |
| | $ | (0.1 | ) |
| Effect on accumulated postretirement benefit obligation | 0.5 |
| | (0.5 | ) |
Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas:
|
| | | | | | | | |
| | Target | | 2015 Actual | | 2014 Actual |
| Equity securities | 60.0 | % | | 59.6 | % | | 59.0 | % |
| Debt securities | 40.0 | % | | 39.7 | % | | 39.0 | % |
| Other | — | % | | 0.7 | % | | 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. Laclede Gas established Voluntary Employees’ Beneficiary Association and Rabbi Trusts as its external funding mechanisms. Laclede Gas’ investment policy seeks to maximize investment returns consistent with Laclede Gas' 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. Laclede Gas' 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. Laclede Gas currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across US stock and bond markets.
Following are the targeted and actual plan assets by category as of September 30 of each year for Alagasco:
|
| | | | | | | | |
| | Target | | 2015 Actual | | 2014 Actual |
| Equity securities | 60.0 | % | | 59.7 | % | | 60.0 | % |
| Debt securities | 40.0 | % | | 40.3 | % | | 40.0 | % |
| Total | 100.0 | % | | 100.0 | % | | 100.0 | % |
Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter for Laclede Group, Laclede Gas, and Alagasco:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Laclede Group | | Laclede Gas | | Alagasco |
| | | Benefits from Qualified Trust | | Benefits from Company Funds | | Benefits from Qualified Trust | | Benefits from Laclede Gas Funds | | Benefits from Qualified Trust |
| 2016 | | $ | 15.1 |
| | $ | 0.4 |
| | $ | 12.3 |
| | $ | 0.4 |
| | $ | 2.8 |
|
| 2017 | | 16.2 |
| | 0.4 |
| | 13.3 |
| | 0.4 |
| | 2.9 |
|
| 2018 | | 17.5 |
| | 0.4 |
| | 14.6 |
| | 0.4 |
| | 2.9 |
|
| 2019 | | 18.3 |
| | 0.4 |
| | 15.4 |
| | 0.4 |
| | 2.9 |
|
| 2020 | | 19.2 |
| | 0.4 |
| | 16.3 |
| | 0.4 |
| | 2.9 |
|
| 2021 – 2025 | | 104.9 |
| | 2.3 |
| | 90.4 |
| | 2.3 |
| | 14.5 |
|
Laclede Gas' 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 2016 are anticipated to be $14.3 to the qualified trusts, and $0.4 paid directly to participants from Laclede Gas funds.
Alagasco's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. In fiscal 2016 it is not anticipated that contributions will be made to the postretirement plans.
Other Plans
Laclede Gas and Alagasco sponsor 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. Laclede Gas provides a match of such contributions within specific limits. The cost of the defined contribution plans of Laclede Gas amounted to $8.0, $6.7, and $5.0 for fiscal years 2015, 2014, and 2013, respectively. Alagasco also provides a match of employee contributions within specific limits. The cost of the defined contribution plans of Alagasco amounted to $3.0, $4.7, and $7.1 for the fiscal year 2015, the transition period ended September 30, 2014, and calendar year 2013, respectively.
Fair Value Measurements of Pension and Other Postretirement Plan Assets
Laclede Group
The table below categorizes the fair value measurements of the Laclede Group's pension plan assets:
|
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| Cash and cash equivalents | $ | 43.4 |
| | $ | 0.2 |
| | $ | — |
| | $ | 43.6 |
|
| Stock/bond mutual fund | 46.4 |
| | 74.6 |
| | 9.6 |
| | 130.6 |
|
| Debt Securities | | | | | | | |
| US bond mutual funds | — |
| | 9.3 |
| | — |
| | 9.3 |
|
| US government | 58.7 |
| | — |
| | — |
| | 58.7 |
|
| US corporate | 123.7 |
| | 42.9 |
| | — |
| | 166.6 |
|
| US municipal | — |
| | 5.9 |
| | — |
| | 5.9 |
|
| International | — |
| | 31.3 |
| | — |
| | 31.3 |
|
| Derivative instruments (a) | — |
| | 2.9 |
| | — |
| | 2.9 |
|
| Total | $ | 272.2 |
| | $ | 167.1 |
| | $ | 9.6 |
| | $ | 448.9 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 8.6 |
| | $ | 1.6 |
| | $ | — |
| | $ | 10.2 |
|
| Stock/bond mutual fund | 54.2 |
| | 74.7 |
| | 9.3 |
| | 138.2 |
|
| Debt Securities | | | | | | | |
| US bond mutual funds | 73.6 |
| | — |
| | — |
| | 73.6 |
|
| US government | — |
| | 64.5 |
| | — |
| | 64.5 |
|
| US corporate | — |
| | 164.0 |
| | — |
| | 164.0 |
|
| US municipal | — |
| | 8.2 |
| | — |
| | 8.2 |
|
| International | — |
| | 35.5 |
| | — |
| | 35.5 |
|
| Derivative instruments (b) | — |
| | (1.0 | ) | | — |
| | (1.0 | ) |
| Other | — |
| | 13.4 |
| | — |
| | 13.4 |
|
| Total | $ | 136.4 |
| | $ | 360.9 |
| | $ | 9.3 |
| | $ | 506.6 |
|
| |
| (a) | Cash collateral of $8.3 net of derivative liabilities of $5.4. |
| |
| (b) | Derivative assets of $2.9 net of cash margin payable of $3.9. |
The table below categorizes the fair value measurements of Laclede Group's postretirement plan assets: |
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| Cash and cash equivalents | $ | 1.6 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
|
| US stock/bond mutual fund | 115.5 |
| | 92.8 |
| | — |
| | 208.3 |
|
| International fund | — |
| | 13.4 |
| | — |
| | 13.4 |
|
| Total | $ | 117.1 |
| | $ | 106.2 |
| | $ | — |
| | $ | 223.3 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 2.3 |
| | $ | — |
| | $ | — |
| | $ | 2.3 |
|
| US stock/bond mutual fund | 213.0 |
| | — |
| | — |
| | 213.0 |
|
| International fund | 7.2 |
| | — |
| | — |
| | 7.2 |
|
| Total | $ | 222.5 |
| | $ | — |
| | $ | — |
| | $ | 222.5 |
|
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.
Laclede Gas
The table below categorizes the fair value measurements of Laclede Gas' pension plan assets:
|
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| Cash and cash equivalents | $ | 31.8 |
| | $ | — |
| | $ | — |
| | $ | 31.8 |
|
| Stock/bond mutual fund | — |
| | 67.6 |
| | 0.1 |
| | 67.7 |
|
| Debt Securities | | | | | | | |
| US government | 37.7 |
| | — |
| | — |
| | 37.7 |
|
| US corporate | 123.7 |
| | 42.9 |
| | — |
| | 166.6 |
|
| US municipal | — |
| | 5.9 |
| | — |
| | 5.9 |
|
| International | — |
| | 27.3 |
| | — |
| | 27.3 |
|
| Derivative instruments (a) | — |
| | 2.9 |
| | — |
| | 2.9 |
|
| Total | $ | 193.2 |
| | $ | 146.6 |
| | $ | 0.1 |
| | $ | 339.9 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 8.3 |
| | $ | — |
| | $ | — |
| | $ | 8.3 |
|
| Stock/bond mutual fund | — |
| | 39.2 |
| | 9.3 |
| | 48.5 |
|
| Debt Securities | | | | | | | |
| US bond mutual funds | 73.6 |
| | — |
| | — |
| | 73.6 |
|
| US government | — |
| | 60.5 |
| | — |
| | 60.5 |
|
| US corporate | — |
| | 154.5 |
| | — |
| | 154.5 |
|
| US municipal | — |
| | 8.2 |
| | — |
| | 8.2 |
|
| International | — |
| | 34.8 |
| | — |
| | 34.8 |
|
| Derivative instruments (b) | — |
| | (1.0 | ) | | — |
| | (1.0 | ) |
| Total | $ | 81.9 |
| | $ | 296.2 |
| | $ | 9.3 |
| | $ | 387.4 |
|
| |
| (a) | Cash collateral of $8.3net of derivative liabilities of $5.4. |
| |
| (b) | Derivative assets of $2.9 net of cash margin payable of $3.9. |
The table below categorizes the fair value measurements of Laclede Gas' postretirement plan assets:
|
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| Cash and cash equivalents | $ | 1.6 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
|
| US stock/bond mutual fund | 115.5 |
| | 26.5 |
| | — |
| | 142.0 |
|
| Total | $ | 117.1 |
| | $ | 26.5 |
| | $ | — |
| | $ | 143.6 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 2.3 |
| | $ | — |
| | $ | — |
| | $ | 2.3 |
|
| US stock/bond mutual fund | 134.9 |
| | — |
| | — |
| | 134.9 |
|
| Total | $ | 137.2 |
| | $ | — |
| | $ | — |
| | $ | 137.2 |
|
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.
Alagasco
The table below categorizes the fair value measurements of Alagasco's pension plan assets:
|
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| Cash and cash equivalents | $ | 11.6 |
| | $ | 0.2 |
| | $ | — |
| | $ | 11.8 |
|
| Stock/bond mutual fund | 46.4 |
| | 7.0 |
| | 9.5 |
| | 62.9 |
|
| Debt Securities | | | | | | | |
| US bond mutual funds | — |
| | 9.3 |
| | — |
| | 9.3 |
|
| US government | — |
| | 21.0 |
| | — |
| | 21.0 |
|
| International | — |
| | 4.0 |
| | — |
| | 4.0 |
|
| Derivative instruments (a) | — |
| | — |
| | — |
| | — |
|
| Total | $ | 58.0 |
| | $ | 41.5 |
| | $ | 9.5 |
| | $ | 109.0 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 0.3 |
| | $ | 1.6 |
| | $ | — |
| | $ | 1.9 |
|
| Stock/bond mutual fund | 54.2 |
| | 35.5 |
| | — |
| | 89.7 |
|
| Debt Securities | | | | | | | |
| US government | — |
| | 4.0 |
| | — |
| | 4.0 |
|
| US corporate |
|
| | 9.5 |
| | — |
| | 9.5 |
|
| International |
|
| | 0.7 |
| | — |
| | 0.7 |
|
| Other | — |
| | 13.4 |
| | — |
| | 13.4 |
|
| Total | $ | 54.5 |
| | $ | 64.7 |
| | $ | — |
| | $ | 119.2 |
|
The table below categorizes the fair value measurements of Alagasco's postretirement plan assets:
|
| | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) | | Significant Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| As of September 30, 2015 | | | | | | | |
| US stock/bond mutual fund | $ | — |
| | $ | 66.3 |
| | $ | — |
| | $ | 66.3 |
|
| International Fund | — |
| | 13.4 |
| | — |
| | 13.4 |
|
| Total | $ | — |
| | $ | 79.7 |
| | $ | — |
| | $ | 79.7 |
|
| | | | | | | | |
| As of September 30, 2014 | | | | | | | |
| Cash and cash equivalents | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
|
| US stock/bond mutual fund | 43.6 |
| | 34.4 |
| | — |
| | 78.0 |
|
| International Fund | 7.2 |
| | — |
| | — |
| | 7.2 |
|
| Total | $ | 50.9 |
| | $ | 34.4 |
| | $ | — |
| | $ | 85.3 |
|
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.
14. INFORMATION BY OPERATING SEGMENT
Laclede Group
The Company has two key operating segments: Gas Utility and Gas Marketing. The Gas Utility segment is the aggregation of the regulated operations of the Utilities. The Gas Marketing segment 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 utilizes natural gas storage contracts for providing natural gas sales. Other includes:
unallocated corporate items, including certain debt and associated interest costs,
Laclede Pipeline Company, a subsidiary of Laclede Group which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction, and
Laclede Group’s subsidiaries that are engaged in compression of natural gas, oil production, real estate development, risk management, and financial investments in other enterprises, among other activities. All subsidiaries are wholly owned.
Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from Laclede Gas to LER, propane storage services provided by Laclede Gas to Laclede Pipeline Company, sales of natural gas from LER to Laclede Gas, and propane transportation services provided by Laclede Pipeline Company to Laclede Gas. 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 exclude the after-tax impacts related to acquisition, divestiture, and restructuring activities.
|
| | | | | | | | | | | | | | | | | | | |
| | Gas Utility | | Gas Marketing | | Other | | Eliminations | | Consolidated |
| 2015 | | | | |
| Revenues from external customers | $ | 1,891.8 |
| | $ | 82.9 |
| | $ | 1.7 |
| | $ | — |
| | $ | 1,976.4 |
|
| Intersegment revenues | 4.0 |
| | 70.5 |
| | 2.0 |
| | (76.5 | ) | | — |
|
| Total Operating Revenues | 1,895.8 |
| | 153.4 |
| | 3.7 |
| | (76.5 | ) | | 1,976.4 |
|
| Operating Expenses | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| Natural and propane gas | 957.6 |
| | — |
| | — |
| | (75.2 | ) | | 882.4 |
|
| Other operation and maintenance | 391.6 |
| | — |
| | — |
| | (1.0 | ) | | 390.6 |
|
| Depreciation and amortization | 129.9 |
| | — |
| | — |
| | — |
| | 129.9 |
|
| Taxes, other than income taxes | 142.1 |
| | — |
| | — |
| | — |
| | 142.1 |
|
| Total Gas Utility Operating Expenses | 1,621.2 |
| | — |
| | — |
| | (76.2 | ) | | 1,545.0 |
|
| Gas Marketing and Other | — |
| | 146.6 |
| (a) | 12.6 |
| (b) | (0.3 | ) | | 158.9 |
|
| Total Operating Expenses | 1,621.2 |
| | 146.6 |
| | 12.6 |
| | (76.5 | ) | | 1,703.9 |
|
| Operating Income (Loss) | 274.6 |
| | 6.8 |
| | (8.9 | ) | | — |
| | 272.5 |
|
| Net Economic Earnings (Loss) | 150.4 |
| | 4.2 |
| | (16.3 | ) | | — |
| | 138.3 |
|
| Capital Expenditures | 284.4 |
| | — |
| | 5.4 |
| | — |
| | 289.8 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Gas Utility | | Gas Marketing | | Other | | Eliminations | | Consolidated |
| 2014 | | | | |
| Revenues from external customers | $ | 1,462.6 |
| | $ | 162.6 |
| | $ | 2.0 |
| | $ | — |
| | $ | 1,627.2 |
|
| Intersegment revenues | 5.2 |
| | 84.0 |
| | 1.8 |
| | (91.0 | ) | | — |
|
| Total Operating Revenues | 1,467.8 |
| | 246.6 |
| | 3.8 |
| | (91.0 | ) | | 1,627.2 |
|
| Operating Expenses | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| Natural and propane gas | 821.8 |
| | — |
| | — |
| | (90.1 | ) | | 731.7 |
|
| Other operation and maintenance | 288.7 |
| | — |
| | — |
| | (0.9 | ) | | 287.8 |
|
| Depreciation and amortization | 82.4 |
| | — |
| | — |
| | — |
| | 82.4 |
|
| Taxes, other than income taxes | 112.0 |
| | — |
| | — |
| | — |
| | 112.0 |
|
| Total Gas Utility Operating Expenses | 1,304.9 |
| | — |
| | — |
| | (91.0 | ) | | 1,213.9 |
|
| Gas Marketing and Other | — |
| | 226.4 |
| (a) | 20.5 |
| (b) | — |
| | 246.9 |
|
| Total Operating Expenses | 1,304.9 |
| | 226.4 |
| | 20.5 |
| | (91.0 | ) | | 1,460.8 |
|
| Operating Income (Loss) | 162.9 |
| | 20.2 |
| | (16.7 | ) | | — |
| | 166.4 |
|
| Net Economic Earnings (Loss) | 92.8 |
| | 10.2 |
| | (2.9 | ) | | — |
| | 100.1 |
|
| Capital Expenditures | 168.6 |
| | — |
| | 2.4 |
| | — |
| | 171.0 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Gas Utility | | Gas Marketing | | Other | | Eliminations | | Consolidated |
| 2013 | | | | |
| Revenues from external customers | $ | 847.2 |
| | $ | 165.1 |
| | $ | 4.7 |
| | $ | — |
| | $ | 1,017.0 |
|
| Intersegment revenues | 10.6 |
| | 24.3 |
| | 1.5 |
| | (36.4 | ) | | — |
|
| Total Operating Revenues | 857.8 |
| | 189.4 |
| | 6.2 |
| | (36.4 | ) | | 1,017.0 |
|
| Operating Expenses | | | | | | | | | |
| Gas Utility | | | | | | | | | |
| Natural and propane gas | 469.1 |
| | — |
| | — |
| | (35.7 | ) | | 433.4 |
|
| Other operation and maintenance | 180.7 |
| | — |
| | — |
| | (0.4 | ) | | 180.3 |
|
| Depreciation and amortization | 48.3 |
| | — |
| | — |
| | — |
| | 48.3 |
|
| Taxes, other than income taxes | 60.1 |
| | — |
| | — |
| | — |
| | 60.1 |
|
| Total Gas Utility Operating Expenses | 758.2 |
| | — |
| | — |
| | (36.1 | ) | | 722.1 |
|
| Gas Marketing and Other | — |
| | 176.6 |
| (a) | 22.1 |
| (b) | (0.3 | ) | | 198.4 |
|
| Total Operating Expenses | 758.2 |
| | 176.6 |
| | 22.1 |
| | (36.4 | ) | | 920.5 |
|
| Operating Income (Loss) | 99.6 |
| | 12.8 |
| | (15.9 | ) | | — |
| | 96.5 |
|
| Net Economic Earnings (Loss) | 56.6 |
| | 8.9 |
| | (0.5 | ) | | — |
| | 65.0 |
|
| Capital Expenditures | 128.5 |
| | — |
| | 2.3 |
| | — |
| | 130.8 |
|
| |
| (a) | Depreciation and amortization for Gas Marketing are included in Gas Marketing Expenses on the Consolidated Statements of Income ($0.3 for 2015, $0.4 for 2014, and $0.3 for 2013). |
| |
| (b) | Depreciation, amortization, and accretion for Other are included in the Other Operating Expenses on the Consolidated Statements of Income ($0.6 for 2015, $0.5 for 2014, and $0.6 for 2013). |
|
| | | | | | | | | | | |
| Total Assets | 2015 | | 2014 | | 2013 |
| Gas Utility | $ | 4,686.2 |
| | $ | 4,520.0 |
| | $ | 2,981.0 |
|
| Gas Marketing | 160.6 |
| | 156.7 |
| | 163.9 |
|
| Other | 1,560.2 |
| | 1,575.7 |
| | 115.6 |
|
| Eliminations | (1,116.8 | ) | | (1,178.4 | ) | | (135.1 | ) |
| Total Assets | $ | 5,290.2 |
| | $ | 5,074.0 |
| | $ | 3,125.4 |
|
|
| | | | | | | | | | | |
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
| 2015 | | 2014 | | 2013 |
| Net Income (GAAP) | $ | 136.9 |
| | $ | 84.6 |
| | $ | 52.8 |
|
| Unrealized loss (gain) on energy-related derivatives | (1.8 | ) | | (0.9 | ) | | 0.5 |
|
| Lower of cost or market inventory adjustments | 0.3 |
| | (0.7 | ) | | 0.9 |
|
Realized (gain) loss on economic hedges prior to the sale of the physical commodity | 1.5 |
| | (0.2 | ) | | — |
|
| Acquisition, divestiture and restructuring activities | 6.1 |
| | 17.3 |
| | 10.8 |
|
| Gain on sale of property | (4.7 | ) | | — |
| | — |
|
| Net Economic Earnings (Non-GAAP) | $ | 138.3 |
| | $ | 100.1 |
| | $ | 65.0 |
|
Laclede Gas and Alagasco account for regulated operations in accordance with ASC Topic 980, "Regulated Operations." This Topic sets forth the application of GAAP for those arrangementscompanies 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 Balance Sheets as of September 30, 2015 and 2014. Unamortized Purchased Gas Adjustments are also included below, which are reported separately in the current assets and liabilities sections of each balance sheet.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas | | Alagasco |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2015 | | 2014 |
| Regulatory Assets: | | | | | | | | | | | |
| Current: | | | | | | | | | | | |
| Pension and postretirement benefit costs | $ | 22.0 |
| | $ | 21.4 |
| | $ | 15.5 |
| | $ | 15.0 |
| | $ | 6.5 |
| | $ | 6.4 |
|
| Unamortized purchased gas adjustments | 12.9 |
| | 54.0 |
| | 12.9 |
| | 54.0 |
| | — |
| | — |
|
| Other | 5.6 |
| | 5.4 |
| | 0.7 |
| | 3.0 |
| | 4.9 |
| | 2.4 |
|
| Total Current Regulatory Assets | 40.5 |
| | 80.8 |
| | 29.1 |
| | 72.0 |
| | 11.4 |
| | 8.8 |
|
| Noncurrent: | | | | | | | | | | | |
| Future income taxes due from customers | 134.5 |
| | 117.0 |
| | 134.5 |
| | 117.0 |
| | — |
| | — |
|
| Pension and postretirement benefit costs | 448.7 |
| | 431.5 |
| | 368.0 |
| | 365.4 |
| | 80.7 |
| | 66.1 |
|
| Cost of removal | 78.9 |
| | 21.2 |
| | — |
| | — |
| | 78.9 |
| | 21.2 |
|
| Purchased gas costs | 24.1 |
| | 4.3 |
| | 24.1 |
| | 4.3 |
| | — |
| | — |
|
| Energy efficiency | 22.3 |
| | 18.9 |
| | 22.3 |
| | 18.9 |
| | — |
| | — |
|
| Other | 29.1 |
| | 21.4 |
| | 24.7 |
| | 18.1 |
| | 4.0 |
| | 3.3 |
|
| Total Noncurrent Regulatory Assets | 737.6 |
| | 614.3 |
| | 573.6 |
| | 523.7 |
| | 163.6 |
| | 90.6 |
|
| Total Regulatory Assets | $ | 778.1 |
| | $ | 695.1 |
| | $ | 602.7 |
| | $ | 595.7 |
| | $ | 175.0 |
| | $ | 99.4 |
|
| | | | | | | | | | | | |
| Regulatory Liabilities: | | | | | | | | | | | |
| Current: | | | | | | | | | | | |
| RSE adjustment | 12.2 |
| | 19.8 |
| | — |
| | — |
| | 12.2 |
| | 19.8 |
|
| Unbilled service margin | 6.4 |
| | 5.2 |
| | — |
| | — |
| | 6.4 |
| | 5.2 |
|
| Refundable negative salvage | 10.8 |
| | 13.4 |
| | — |
| | — |
| | 10.8 |
| | 13.4 |
|
| Unamortized purchased gas adjustments | 28.2 |
| | 22.4 |
| | — |
| | — |
| | 28.2 |
| | 22.4 |
|
| Other | 3.0 |
| | 2.9 |
| | 0.6 |
| | 0.6 |
| | 2.4 |
| | 2.3 |
|
| Total Current Regulatory Liabilities | 60.6 |
| | 63.7 |
| | 0.6 |
| | 0.6 |
| | 60.0 |
| | 63.1 |
|
| Noncurrent: | | | | | | | | | | | |
| Postretirement liabilities | 28.9 |
| | 26.2 |
| | — |
| | — |
| | 28.9 |
| | 26.2 |
|
| Refundable negative salvage | 16.2 |
| | 26.8 |
| | — |
| | — |
| | 16.2 |
| | 26.8 |
|
| Accrued cost of removal | 58.7 |
| | 60.5 |
| | 58.7 |
| | 60.5 |
| | — |
| | — |
|
| Other | 15.5 |
| | 12.3 |
| | 11.9 |
| | 11.6 |
| | 3.6 |
| | 0.7 |
|
| Total Noncurrent Regulatory Liabilities | 119.3 |
| | 125.8 |
| | 70.6 |
| | 72.1 |
| | 48.7 |
| | 53.7 |
|
| Total Regulatory Liabilities | 179.9 |
| | 189.5 |
| | 71.2 |
| | 72.7 |
| | 108.7 |
| | 116.8 |
|
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 and are shown in the schedule below:
|
| | | | | | | | | | | | | | | |
| | Laclede Group | | Laclede Gas |
| | 2015 | | 2014 | | 2015 | | 2014 |
| Regulatory Assets Not Earning a Return: | | | | | | | |
| Future income taxes due from customers | $ | 134.5 |
| | $ | 117.0 |
| | $ | 134.5 |
| | $ | 117.0 |
|
| Pension and postretirement benefit costs | 223.7 |
| | 240.9 |
| | 223.7 |
| | 240.9 |
|
| Other | 14.2 |
| | 16.0 |
| | 14.2 |
| | 16.0 |
|
| Total Regulatory Assets Not Earning a Return | $ | 372.4 |
| | $ | 373.9 |
| | $ | 372.4 |
| | $ | 373.9 |
|
All of Alagasco's regulatory assets currently earn a return.
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, 2015 and 2014, approximately $372.4 and $373.9, 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.
As authorized by the MoPSC, Laclede Gas 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 were recovered and amortized on a straight-line basis over a fifteen-year period ended in December 2014, without return on investment.
Laclede Gas
On April 17, 2015, Laclede Gas filed to increase its financial position.Infrastructure System Replacement Surcharge (ISRS) revenues by $5.5 in its Laclede Gas' eastern Missouri service territory and by $2.9 in its MGE service territory, to recover the cost of gas safety replacement investments and public improvement projects over six months from September 2014 through February 2015. Effective May 22, 2015, the MoPSC approved an increase to the ISRS tariffs in the amounts of $5.4 for Laclede Gas' eastern Missouri service territory and $2.8 for MGE's service territory.
On August 3, 2015, Laclede Gas filed applications to increase its ISRS revenues by $4.3 in its Laclede Gas eastern Missouri service territory and by $1.8 in its MGE service territory, to recover the cost of replacement investments related to gas safety and public improvement projects over six months from March through August 2015. On November 12, 2015, the MoPSC approved an incremental ISRS amount of $4.4 for Laclede Gas' eastern Missouri service territory and $1.9 for MGE, effective December 1, 2015, bringing total annualized ISRS revenue to $19.6 for Laclede Gas' eastern Missouri service territory and $6.7 for MGE's service territory.
Alagasco
Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. The amendmentprevious allowed range of return on average common equity was 13.15% to 13.65% through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4% of prior-year revenues.
The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual reporting periods beginning onincreases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using an index range equal to the June Consumer Price Index For All Urban Consumers each rate year plus or after January 1, 2013, and interim periodsminus 1.75%. If rate year O&M expense falls within those annual periods. In January 2013,this index range, no adjustment is required. If rate year O&M expense exceeds the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transitionindex range, three-quarters of the disclosure requirementdifference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the index range, Alagasco benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Benefit for fiscal 2015 was $4.9 and $2.4 for 2014.
Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in ASU No. 2011-11 remained1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.
The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self-insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $0.3 and $0.4, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $0.4 during a rate year. Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which prescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine-year term beginning December 1, 2010. Subsequent to the nine-year period and subject to APSC authorization, Alagasco expects to be able to recover underfunded ESR balances over a five-year amortization period with an annual limitation of $0.7. Amounts in excess of this limitation are deferred for recovery in future years.
unchanged. 16. COMMITMENTS AND CONTINGENCIES
Commitments
The adoptionCompany and the Utilities have entered into contracts with various counterparties, expiring on dates through 2021, for the storage, transportation, and supply of natural gas. Minimum payments required by the Company under the contracts in place at September 30, 2015 are estimated at $1,369.3. Minimum payments required for Laclede Gas and Alagasco under the contracts are estimated at $600.8 and $476.9, respectively. Additional contracts are generally entered into prior to or during the heating season of November through April. The Missouri Utilities recover their costs from customers in accordance with their PGA clause and Alagasco recovers its cost through its GSA rider.
Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $476.9 through August 2020. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 110 Bcf through August 2020.
Laclede Pipeline Company (Pipeline), a 100% owned subsidiary of Laclede Group, is providing liquid propane transportation service to Laclede Gas pursuant to an approved FERC tariff and a contractual arrangement between Pipeline and Laclede Gas. In accordance with the terms of that agreement, Laclede Gas is obligated to pay Pipeline approximately $1.0 annually, at current rates. The agreement renews at the end of each contract year, unless terminated by either party upon provision of at least six months’ notice.
Leases and Guarantees
The lease agreement covering the primary office space of Laclede Group and its Missouri Utilities extends through February 2025. The aggregate rental expense for fiscal years 2015, 2014, and 2013 was approximately $2.8, $1.0, and $1.0, respectively. The annual rental payment is anticipated to be approximately $3.8 through fiscal year 2016. The lease agreement covering the primary office space of Alagasco extends through February 2018. Alagasco has an operating lease for additional office space that extends to January 31, 2024. Alagasco has subleased all of this standardoffice space to Energen pursuant to a sublease that expires on December 31, 2019 with an option to extend through January 31, 2024.
Laclede Gas has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The rental costs will be approximately $2.2 in fiscal year 2016, $2.5 in fiscal year 2017, and $0.1 in fiscal year 2018. Laclede Gas 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 $1.5 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 Company and Utilities account for environmental liabilities and other contingencies in accordance with accounting standards under the loss contingency guidance of ASC Topic 450, "Contingencies," when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.
Laclede Gas
Similar to other natural gas utility companies, Laclede Gas 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 Laclede Gas' financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Company or Laclede Gas may incur additional environmental liabilities that may result in additional costs.
In the natural gas industry, many gas distribution companies like Laclede Gas have incurred environmental liabilities associated with sites they or their predecessor companies formerly owned or operated where manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites in eastern Missouri 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). In Laclede Gas' western service area, 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, Environmental Protection Agency (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.
In conjunction with redevelopment of one of the sites located in the City of St. Louis, 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. 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 coverage, 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. Accordingly, Laclede Gas entered into a cost sharing agreement for remedial investigation with other potentially responsible parties. Pending Missouri Department of Natural Resources approval which has not occurred as of the date of filing, the remedial investigation of the site will begin.
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.
On March 10, 2015, Laclede Gas received a Section 104(e) information request from EPA Region VII regarding the former Thompson Chemical/Superior Solvents site in St. Louis, Missouri. In turn, Laclede Gas issued a Freedom of Information Act (FOIA) request to the EPA on April 3, 2015, in an effort to identify the basis of the inquiry. The FOIA response from the EPA was received on July 15, 2015 and a response was provided to the EPA on August 15, 2015.
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 area, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. 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. On May 11, 2015, Missouri Department of Natural Resources approved the next phase of investigation at the Kansas City Station A North and Railroad area.
To date, costs incurred for all Missouri Utilities' MGP sites for investigation, remediation and monitoring 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. The actual future costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remediation actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and government regulations, the ultimate ability of other potential responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.
In 2013, Laclede Gas retained an outside consultant to conduct probabilistic cost modeling of 19 former MGP sites owned or operated by Laclede Gas in eastern Missouri or MGE in western Missouri. The purpose of this analysis was to develop an estimated range of probabilistic future liability for each site. That analysis, completed in August 2014, provided a range of demonstrated possible future expenditures to investigate, monitor and remediate all 19 MGP sites. Laclede Gas has recorded its best estimate of the probable expenditures that relate to these matters. The amount is not material.
Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. To the extent such costs (less any amounts received from insurance proceeds or as contributions from other potentially responsible parties (PRP)), are incurred prior to a rate case, Laclede Gas would request from the MoPSC authority
to defer such costs and collect them in the next rate case. Laclede Gas and the Company do not expect potential liabilities that may arise from remediating these sites to have a material impact on their future financial condition or results of operations.
Alagasco
Alagasco owns and operates natural gas distribution, transmission, and storage facilities, the consolidatedoperations 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 Alagasco's financial statementsposition and results of operations. As environmental laws, regulations, and their interpretations change, however, Alagasco may be required to incur additional costs.
Alagasco is in the Company. The additional disclosures are included in Note 8, Financial Instruments.
In February 2013,chain of title of nine former MGP sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. As of 9/30/2015, Alagasco does not foresee a probable or reasonably estimable loss associated with these nine sites. Alagasco and the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companiesCompany do not expect potential liabilities that may arise from remediating these sites to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on their future financial conditions or results of operations.
In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of the Comprehensive Environment Response, Compensation, and Liability Act (CERCLA) relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama in which Alagasco was identified as a Potentially Responsible Party (“PRP”) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the site. At this point, Alagasco has not been provided information that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and vigorously denies its inclusion as a PRP.
On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident, and additional lawsuits and claims may be filed against Alagasco.
Alagasco is, from time to time, a party to various pending or threatened legal proceedings and has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Alagasco recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the financial position of Alagasco. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.
Laclede Group
In addition to matters noted above, the Company, Laclede Gas and Alagasco are 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 statements of income, balance sheets, and statements of cash flows of the Company. The additional disclosures are included in Note 16, Accumulated Other Comprehensive Income (Loss).
Company, Laclede Gas or Alagasco.
18. SUMMARIZED QUARTERLY17. INTERIM FINANCIAL DATA (Unaudited)INFORMATION (UNAUDITED)
Laclede Group
In the opinion of Laclede Group, the quarterly information presented below for fiscal years 2015 and 2014 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 Laclede Gas and Alagasco. |
| | | | | | | | | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2015 | | | | | | | |
| Total Operating Revenues | $ | 619.6 |
| | $ | 877.4 |
| | $ | 275.2 |
| | $ | 204.2 |
|
| Operating Income (Loss) | 87.3 |
| | 157.7 |
| | 36.0 |
| | (8.5 | ) |
| Net Income (Loss) | 47.1 |
| | 94.4 |
| | 14.1 |
| | (18.7 | ) |
| Basic Earnings (Loss) Per Share of Common Stock | $ | 1.09 |
| | $ | 2.18 |
| | $ | 0.32 |
| | $ | (0.43 | ) |
| Diluted Earnings (Loss) Per Share of Common Stock | $ | 1.09 |
| | $ | 2.18 |
| | $ | 0.32 |
| | $ | (0.43 | ) |
| | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2014 | | | | | | | |
| Total Operating Revenues | $ | 468.6 |
| | $ | 694.5 |
| | $ | 241.8 |
| | $ | 222.3 |
|
| Operating Income | 62.9 |
| | 87.2 |
| | 24.7 |
| | (8.4 | ) |
| Net Income (Loss) | 35.6 |
| | 52.2 |
| | 11.7 |
| | (14.9 | ) |
| Basic Earnings (Loss) Per Share of Common Stock | $ | 1.09 |
| | $ | 1.59 |
| | $ | 0.34 |
| | $ | (0.35 | ) |
| Diluted Earnings (Loss) Per Share of Common Stock | $ | 1.09 |
| | $ | 1.59 |
| | $ | 0.33 |
| | $ | (0.35 | ) |
All quarters of 2015 include the results of the operations of Alagasco. Further, all quarters of 2015 reflect costs relating to the integration of both Alagasco and MGE, as well as interest expense associated with the debt issued in 2014 to fund the Alagasco acquisition.
All quarters of 2014 reflect transaction costs incurred associated with the acquisition of Alagasco and the integration of MGE. The Company’s business is seasonal in character. The following data summarizes quarterly operating results.
|
| | | | | | | | | | | | |
| | Year ended December 31, 2013 |
| (in thousands, except per share amounts) | First | Second | Third | Fourth |
| Operating revenues as originally reported | $ | 492,679 |
| $ | 490,057 |
| $ | 320,406 |
| $ | 472,733 |
|
| Discontinued operations* | (18,663 | ) | (18,562 | ) | — |
| — |
|
| Adjusted operating revenues | $ | 474,016 |
| $ | 471,495 |
| $ | 320,406 |
| $ | 472,733 |
|
| Operating income (loss) as originally reported | $ | 105,336 |
| $ | 146,304 |
| $ | (4,052 | ) | $ | 110,630 |
|
| Discontinued operations* | (3,146 | ) | (3,871 | ) | — |
| — |
|
| Adjusted operating income (loss) | $ | 102,190 |
| $ | 142,433 |
| $ | (4,052 | ) | $ | 110,630 |
|
| Income (loss) from continuing operations | $ | 54,694 |
| $ | 80,614 |
| $ | (5,486 | ) | $ | 63,325 |
|
| Net income (loss) | $ | 56,692 |
| $ | 83,067 |
| $ | (19,298 | ) | $ | 84,093 |
|
| Diluted earnings per average common share | | | | |
| Continuing operations | $ | 0.76 |
| $ | 1.11 |
| $ | (0.08 | ) | $ | 0.87 |
|
| Net income (loss) | $ | 0.78 |
| $ | 1.15 |
| $ | (0.27 | ) | $ | 1.15 |
|
| Basic earnings per average common share | | | | |
| Continuing operations | $ | 0.76 |
| $ | 1.12 |
| $ | (0.08 | ) | $ | 0.87 |
|
| Net income (loss) | $ | 0.79 |
| $ | 1.15 |
| $ | (0.27 | ) | $ | 1.16 |
|
* As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013,2014 includes one month of activity of the Company completedoperations of Alagasco.
Laclede Gas
In the saleopinion of its Black Warrior Basin coalbed methane propertiesLaclede Gas, the quarterly information presented below for fiscal years 2015 and 2014 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in Alabama. The property was classified as held-for-sale and reflected in discontinued operations duringreported on a quarterly basis primarily reflect the third quarterseasonal nature of 2013. Also, during the third quarterbusiness of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.Laclede Gas. |
| | | | | | | | | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2015 | | | | | | | |
| Total Operating Revenues | $ | 462.4 |
| | $ | 615.7 |
| | $ | 187.5 |
| | $ | 151.0 |
|
| Operating Income | 64.8 |
| | 80.6 |
| | 34.5 |
| | 5.5 |
|
| Net Income (Loss) | 39.0 |
| | 49.9 |
| | 20.0 |
| | (3.6 | ) |
| | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2014 | | | | | | | |
| Total Operating Revenues | $ | 435.2 |
| | $ | 638.8 |
| | $ | 214.2 |
| | $ | 160.0 |
|
| Operating Income (Loss) | 62.3 |
| | 74.5 |
| | 22.5 |
| | 7.1 |
|
| Net Income (Loss) | 35.3 |
| | 44.2 |
| | 12.0 |
| | (1.4 | ) |
Alagasco
In the opinion of Alagasco, the quarterly information presented below for fiscal years 2015 and 2014 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect the seasonal nature of the business of Alagasco. |
| | | | | | | | | | | | |
| | Year ended December 31, 2012 |
| (in thousands, except per share amounts) | First | Second | Third | Fourth |
| Operating revenues as originally reported | $ | 418,444 |
| $ | 470,355 |
| $ | 295,324 |
| $ | 433,046 |
|
| Discontinued operations | (20,255 | ) | (18,451 | ) | (18,895 | ) | (18,749 | ) |
| Adjusted operating revenues | $ | 398,189 |
| $ | 451,904 |
| $ | 276,429 |
| $ | 414,297 |
|
| Operating income as originally reported | $ | 104,170 |
| $ | 220,598 |
| $ | 19,458 |
| $ | 115,166 |
|
| Discontinued operations | 16,324 |
| (4,751 | ) | (5,494 | ) | (3,557 | ) |
| Adjusted operating income | $ | 120,494 |
| $ | 215,847 |
| $ | 13,964 |
| $ | 111,609 |
|
| Income (loss) from continuing operations | $ | 67,868 |
| $ | 128,305 |
| $ | (1,505 | ) | $ | 60,552 |
|
| Net income | $ | 57,406 |
| $ | 131,287 |
| $ | 2,046 |
| $ | 62,823 |
|
| Diluted earnings per average common share | | | | |
| Continuing operations | $ | 0.94 |
| $ | 1.77 |
| $ | (0.02 | ) | $ | 0.84 |
|
| Net income | $ | 0.79 |
| $ | 1.82 |
| $ | 0.03 |
| $ | 0.87 |
|
| Basic earnings per average common share | | | | |
| Continuing operations | $ | 0.94 |
| $ | 1.78 |
| $ | (0.02 | ) | $ | 0.84 |
|
| Net income | $ | 0.80 |
| $ | 1.82 |
| $ | 0.03 |
| $ | 0.87 |
|
Alagasco’s business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco’s quarterly operating results.
|
| | | | | | | | | | | | |
| | Year ended December 31, 2013 |
| (in thousands) | First | Second | Third | Fourth |
| Operating revenues | $ | 237,685 |
| $ | 104,514 |
| $ | 48,368 |
| $ | 142,771 |
|
| Operating income (loss) | $ | 79,293 |
| $ | 2,219 |
| $ | (22,544 | ) | $ | 34,800 |
|
| Net income (loss) | $ | 47,222 |
| $ | (704 | ) | $ | (8,961 | ) | $ | 19,842 |
|
|
| | | | | | | | | | | | |
| | Year ended December 31, 2012 |
| (in thousands) | First | Second | Third | Fourth |
| Operating revenues | $ | 194,487 |
| $ | 70,887 |
| $ | 61,809 |
| $ | 124,406 |
|
| Operating income (loss) | $ | 78,560 |
| $ | 4,448 |
| $ | (12,743 | ) | $ | 22,951 |
|
| Net income (loss) | $ | 46,918 |
| $ | 326 |
| $ | (10,039 | ) | $ | 12,197 |
|
|
| | | | | | | | | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2015 | | | | | | | |
| Total Operating Revenues | $ | 120.0 |
| | $ | 233.3 |
| | $ | 73.7 |
| | $ | 52.2 |
|
| Operating Income | 20.4 |
| | 77.4 |
| | 3.9 |
| | (12.5 | ) |
| Net Income (Loss) | 10.6 |
| | 46.3 |
| | 0.7 |
| | (9.6 | ) |
| | | | | | | | |
| Three Months Ended | December 31 | | March 31 | | June 30 | | September 30 |
| Fiscal Year 2014 | | | | | | | |
| Total Operating Revenues | $ | 142.8 |
| | $ | 263.9 |
| | $ | 93.8 |
| | $ | 59.5 |
|
| Operating Income (Loss) | 34.8 |
| | 72.4 |
| | 1.8 |
| | (12.0 | ) |
| Net Income (Loss) | 19.8 |
| | 43.1 |
| | (0.6 | ) | | (9.4 | ) |
19. OILITEM 9. CHANGES IN AND GAS OPERATIONS (Unaudited)DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Capitalized Costs: The following table sets forth capitalized costs:
|
| | | | | | |
| (in thousands) | December 31, 2013 | December 31, 2012 |
| Proved | $ | 7,043,779 |
| $ | 6,241,148 |
|
| Unproved | 168,975 |
| 197,979 |
|
| Total capitalized costs | 7,212,754 |
| 6,439,127 |
|
| Accumulated depreciation, depletion and amortization | 2,078,411 |
| 1,765,241 |
|
| Capitalized costs, net | $ | 5,134,343 |
| $ | 4,673,886 |
|
Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Property acquisition: | | | |
| Proved | $ | 4,661 |
| $ | 79,862 |
| $ | 214,993 |
|
| Unproved | 26,820 |
| 58,634 |
| 91,888 |
|
| Exploration | 435,636 |
| 419,284 |
| 190,854 |
|
| Development | 655,353 |
| 749,256 |
| 623,775 |
|
| Total costs incurred | $ | 1,122,470 |
| $ | 1,307,036 |
| $ | 1,121,510 |
|
Results of Operations From Producing Activities: The following table sets forth results of the Company’s oil and gas operations from producing activities:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Gross revenues* | $ | 1,206,293 |
| $ | 1,090,948 |
| $ | 834,700 |
|
| Production (lifting costs) | 351,541 |
| 278,193 |
| 226,361 |
|
| Exploration expense | 27,942 |
| 19,356 |
| 12,967 |
|
| Depreciation, depletion and amortization | 449,700 |
| 339,569 |
| 210,532 |
|
| Accretion expense | 6,995 |
| 6,339 |
| 5,699 |
|
| Income tax expense | 128,773 |
| 160,551 |
| 134,564 |
|
| Results of operations from producing activities | $ | 241,342 |
| $ | 286,940 |
| $ | 244,577 |
|
* The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million, respectively.
Oil and Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2013, 2012 and 2011. Changes to prices and costs couldThere have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States of America.
Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2013. Ryder Scott audited the reserve estimates for coalbed methane in the San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.
|
| | | | | | | | |
| Year ended December 31, 2013 | Gas MMcf |
| Oil MBbl |
| NGL MBbl |
| Total MMBOE |
|
| Proved reserves at beginning of period | 809,128 |
| 155,348 |
| 56,155 |
| 346.4 |
|
| Revisions of previous estimates | 18,465 |
| (680 | ) | 2,211 |
| 4.6 |
|
| Purchases | 282 |
| 142 |
| 56 |
| 0.2 |
|
| Extensions and discoveries | 50,568 |
| 20,517 |
| 7,823 |
| 36.8 |
|
| Production | (70,506 | ) | (10,378 | ) | (3,233 | ) | (25.4 | ) |
| Sales | (88,212 | ) | (79 | ) | (1 | ) | (14.8 | ) |
| Proved reserves at end of period | 719,725 |
| 164,870 |
| 63,011 |
| 347.8 |
|
| Proved developed reserves at end of period | 623,305 |
| 113,795 |
| 42,087 |
| 259.8 |
|
| Proved undeveloped reserves at end of period | 96,420 |
| 51,075 |
| 20,924 |
| 88.0 |
|
|
| | | | | | | | |
| Year ended December 31, 2012 | Gas MMcf |
| Oil MBbl |
| NGL MBbl |
| Total MMBOE |
|
| Proved reserves at beginning of period | 957,368 |
| 129,578 |
| 53,957 |
| 343.1 |
|
| Revisions of previous estimates | (143,704 | ) | (8,546 | ) | (9,557 | ) | (42.1 | ) |
| Purchases | 10,656 |
| 7,950 |
| 2,569 |
| 12.4 |
|
| Extensions and discoveries | 61,170 |
| 35,132 |
| 11,759 |
| 57.1 |
|
| Production | (76,362 | ) | (8,766 | ) | (2,573 | ) | (24.1 | ) |
| Proved reserves at end of period | 809,128 |
| 155,348 |
| 56,155 |
| 346.4 |
|
| Proved developed reserves at end of period | 708,657 |
| 105,976 |
| 36,440 |
| 260.5 |
|
| Proved undeveloped reserves at end of period | 100,471 |
| 49,372 |
| 19,715 |
| 85.9 |
|
|
| | | | | | | | |
| Year ended December 31, 2011 | Gas MMcf |
| Oil MBbl |
| NGL MBbl |
| Total MMBOE |
|
| Proved reserves at beginning of period | 954,387 |
| 103,262 |
| 40,601 |
| 302.9 |
|
| Revisions of previous estimates | (12,823 | ) | (4,513 | ) | 841 |
| (5.8 | ) |
| Purchases | 19,362 |
| 12,583 |
| 5,055 |
| 20.8 |
|
| Extensions and discoveries | 68,160 |
| 24,564 |
| 9,637 |
| 45.6 |
|
| Production | (71,718 | ) | (6,318 | ) | (2,177 | ) | (20.4 | ) |
| Proved reserves at end of period | 957,368 |
| 129,578 |
| 53,957 |
| 343.1 |
|
| Proved developed reserves at end of period | 788,812 |
| 83,899 |
| 33,154 |
| 248.5 |
|
| Proved undeveloped reserves at end of period | 168,556 |
| 45,679 |
| 20,803 |
| 94.6 |
|
2013 Activities: Energen Resources had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related tobeen no changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOEdisagreements on accounting and financial disclosure with Laclede Group’s outside auditors that are expectedrequired to be drilled beyond five yearsdisclosed.
Laclede Gas
There have been no changes in and disagreements on accounting and financial disclosure with the remainder no longer expectedLaclede Gas’ outside auditors that are required to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricingdisclosed.
Alagasco
There have been no disagreements on accounting and downward revisions of approximately 4.6 MMBOE of proved undeveloped reservesfinancial disclosure with Alagasco’s outside auditors that are expectedrequired to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.
Energen Resources purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.
During 2013, Energen Resources had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations.
During 2013, Energen Resources had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.
2012 Activities: Energen Resources had downward reserve revisions during 2012 which totaled 42.1 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 5.1 MMBOE of which approximately 5.9 MMBOE related to estimated negative price related revisions partially offset by better well performance. The San Juan Basin downward reserve revisions of 19.7 MMBOE included 22.5 MMBOE in negative price related revisions partially offset by better well performance, lower operating costs and lower fuel usage. Downward reserve revisions of 15.8 MMBOE in the Permian Basin were primarily due to lower than anticipated performance in certain development wells along with 1.0 MMBOE of estimated negative price related revisions.
Energen Resources purchased 12.4 MMBOE of reserves during 2012 primarily related to the acquisitions of oil properties in the Permian Basin.
During 2012, Energen Resources had extensions and discoveries of 57.1 MMBOE of which 59 percent were proved undeveloped reserves and 41 percent were proved developed reserves. Extension drilling resulted in 45.6 MMBOE of discoveries with exploratory drilling providing 11.5 MMBOE of discoveries. The San Juan Basin added 0.9 MMBOE of reserves through the drilling or identification of 6 well locations. The Permian Basin added 56.1 MMBOE of reserves primarily through the drilling or identification of 422 well locations.
2011 Activities: Energen Resources had downward reserve revisions during 2011 which totaled 5.8 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 0.3 MMBOE of which approximately 0.7 MMBOE related to estimated negative price related revisions partially offset by other positive revisions of 0.4 MMBOE. The San Juan Basin downward reserve revisions of 2.6 MMBOE included 3.9 MMBOE in negative performance related revisions partially offset by 1.3 MMBOE related to estimated positive price related revisions. Downward reserve revisions of 3.1 MMBOE in the Permian Basin were primarily due to lower than anticipated injection response in certain waterflood units and other performance related adjustments. These downward revisions were partially offset by 1.4 MMBOE of estimated positive price related revisions.
Energen Resources purchased 20.8 MMBOE of reserves during 2011 primarily related to the acquisitions of oil properties in the Permian Basin.
During 2011, Energen Resources had extensions and discoveries of 45.6 MMBOE of which 69 percent were proved undeveloped reserves and 31 percent were proved developed reserves. Extension drilling resulted in 41.1 MMBOE of discoveries with exploratory drilling providing 4.5 MMBOE of discoveries. The San Juan Basin added 5.9 MMBOE of reserves through the drilling or identification of 53 well locations. The Permian Basin added 39.6 MMBOE of reserves primarily through the drilling or identification of 395 well locations.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2013, 2012 and 2011, the Company had a deferred hedging gain of $21.6 million, a deferred hedging gain of $74.8 million and a deferred hedging gain of $15 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Future gross revenues | $ | 19,509,305 |
| $ | 17,735,363 |
| $ | 18,196,229 |
|
| Future production costs | 6,136,709 |
| 5,715,248 |
| 5,823,395 |
|
| Future development costs | 1,896,602 |
| 1,892,600 |
| 1,539,072 |
|
| Future income tax expense | 3,209,697 |
| 2,809,411 |
| 3,326,382 |
|
| Future net cash flows | 8,266,297 |
| 7,318,104 |
| 7,507,380 |
|
| Discount at 10% per annum | 4,248,456 |
| 3,618,785 |
| 3,878,217 |
|
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 4,017,841 |
| $ | 3,699,319 |
| $ | 3,629,163 |
|
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| Balance at beginning of year | $ | 3,699,319 |
| $ | 3,629,163 |
| $ | 2,467,136 |
|
| Revisions to reserves proved in prior years: | | | |
| Net changes in prices, production costs and future development costs | 566,838 |
| (922,792 | ) | 707,411 |
|
| Net changes due to revisions in quantity estimates | (81,762 | ) | (383,755 | ) | (80,004 | ) |
| Development costs incurred, previously estimated | 299,432 |
| 472,603 |
| 392,720 |
|
| Accretion of discount | 369,932 |
| 362,916 |
| 246,714 |
|
| Changes in timing and other | (179,502 | ) | (317,244 | ) | (25,937 | ) |
| Total revisions | 974,938 |
| (788,272 | ) | 1,240,904 |
|
| New field discoveries and extensions, net of future production and development costs | 376,326 |
| 1,025,419 |
| 755,977 |
|
| Sales of oil and gas produced, net of production costs | (1,014,593 | ) | (812,781 | ) | (763,171 | ) |
| Purchases | 4,690 |
| 189,755 |
| 232,768 |
|
| Sales | (24,876 | ) | — |
| — |
|
| Net change in income taxes | 2,037 |
| 456,035 |
| (304,451 | ) |
| Net change in standardized measure of discounted future net cash flows | 318,522 |
| 70,156 |
| 1,162,027 |
|
| Balance at end of year | $ | 4,017,841 |
| $ | 3,699,319 |
| $ | 3,629,163 |
|
20. INDUSTRY SEGMENT INFORMATION
The Company is principally engaged in two business segments: the development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.
|
| | | | | | | | | |
| Years ended December 31,(in thousands) | 2013 | 2012 | 2011 |
| Operating revenues from continuing operations | | | |
| Oil and gas operations | $ | 1,205,312 |
| $ | 1,089,230 |
| $ | 838,160 |
|
| Natural gas distribution | 533,338 |
| 451,589 |
| 534,953 |
|
| Total | $ | 1,738,650 |
| $ | 1,540,819 |
| $ | 1,373,113 |
|
| Operating income (loss) from continuing operations | | | |
| Oil and gas operations | $ | 257,963 |
| $ | 369,765 |
| $ | 308,561 |
|
| Natural gas distribution | 93,768 |
| 93,216 |
| 86,216 |
|
| Eliminations and corporate expenses | (530 | ) | (1,067 | ) | (1,078 | ) |
| Total | $ | 351,201 |
| $ | 461,914 |
| $ | 393,699 |
|
| Depreciation, depletion and amortization expense from continuing operations | |
| Oil and gas operations | $ | 453,474 |
| $ | 343,183 |
| $ | 213,841 |
|
| Natural gas distribution | 43,907 |
| 42,270 |
| 39,916 |
|
| Total | $ | 497,381 |
| $ | 385,453 |
| $ | 253,757 |
|
| Interest expense | | | |
| Oil and gas operations | $ | 53,981 |
| $ | 49,958 |
| $ | 30,907 |
|
| Natural gas distribution | 15,649 |
| 16,284 |
| 14,740 |
|
| Eliminations and other | (430 | ) | (700 | ) | (825 | ) |
| Total | $ | 69,200 |
| $ | 65,542 |
| $ | 44,822 |
|
| Income tax expense (benefit) from continuing operations | | | |
| Oil and gas operations | $ | 71,290 |
| $ | 115,090 |
| $ | 100,700 |
|
| Natural gas distribution | 34,687 |
| 30,244 |
| 26,670 |
|
| Other | (695 | ) | (800 | ) | (1,048 | ) |
| Total | $ | 105,282 |
| $ | 144,534 |
| $ | 126,322 |
|
| Capital expenditures | | | |
| Oil and gas operations | $ | 1,104,745 |
| $ | 1,291,211 |
| $ | 1,115,452 |
|
| Natural gas distribution | 88,769 |
| 71,869 |
| 73,984 |
|
| Total | $ | 1,193,514 |
| $ | 1,363,080 |
| $ | 1,189,436 |
|
| Identifiable assets | | | |
| Oil and gas operations | $ | 5,379,135 |
| $ | 4,975,170 |
| $ | 4,046,242 |
|
| Natural gas distribution | 1,193,413 |
| 1,177,134 |
| 1,163,959 |
|
| Eliminations and other | 49,664 |
| 23,586 |
| 27,215 |
|
| Total | $ | 6,622,212 |
| $ | 6,175,890 |
| $ | 5,237,416 |
|
| Property, plant and equipment, net | | | |
| Oil and gas operations | $ | 5,116,958 |
| $ | 4,697,683 |
| $ | 3,806,787 |
|
| Natural gas distribution | 885,550 |
| 842,685 |
| 813,471 |
|
| Other | 1,130 |
| 1,268 |
| 518 |
|
| Total | $ | 6,003,638 |
| $ | 5,541,636 |
| $ | 4,620,776 |
|
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Energen Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| ALLOWANCE FOR DOUBTFUL ACCOUNTS |
| Balance at beginning of year | $ | 6,549 |
| $ | 12,946 |
| $ | 15,048 |
|
| | | | |
| Additions: | | | |
| Charged to income | 2,244 |
| 1,415 |
| 4,269 |
|
| Recoveries and adjustments | (1,463 | ) | (1,262 | ) | (1,744 | ) |
| | | | |
| Net additions | 781 |
| 153 |
| 2,525 |
|
| | | | |
| Less uncollectible accounts written off | (1,636 | ) | (6,550 | ) | (4,627 | ) |
| | | | |
| Balance at end of year | $ | 5,694 |
| $ | 6,549 |
| $ | 12,946 |
|
Alabama Gas Corporation
|
| | | | | | | | | |
| Years ended December 31, (in thousands) | 2013 | 2012 | 2011 |
| | | | |
| ALLOWANCE FOR DOUBTFUL ACCOUNTS |
| Balance at beginning of year | $ | 5,700 |
| $ | 12,100 |
| $ | 14,200 |
|
| | | | |
| Additions: | | | |
| Charged to income | 2,243 |
| 1,409 |
| 4,202 |
|
| Recoveries and adjustments | (1,469 | ) | (1,263 | ) | (1,745 | ) |
| | | | |
| Net additions | 774 |
| 146 |
| 2,457 |
|
| | | | |
| Less uncollectible accounts written off | (1,474 | ) | (6,546 | ) | (4,557 | ) |
| | | | |
| Balance at end of year | $ | 5,000 |
| $ | 5,700 |
| $ | 12,100 |
|
| |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None
disclosed.
ITEM 9A. CONTROLS AND PROCEDURES
Laclede Group
Energen Corporation
a. Disclosure Controls and Procedures
Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, asAs of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our chief executive officermanagement, including our Chief Executive Officer and chief financial officerChief Financial Officer, of the effectiveness of the design and operation of our 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 at that reasonable assurance level.effective.
b. Management’s Report onChange in Internal Control Overover Financial Reporting
Management of Energen Corporation is responsible for establishingDuring our fourth fiscal quarter we converted our MGE customers onto the existing Laclede Gas customer care and maintaining adequatebilling application. This conversion and related changes to processes have changed our internal control over financial reporting as defined in Rules 13a-15(f)customer billing and 15d-15(f) under the Securities Exchange Act of 1934. Energen Corporation’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. Internal control over financial reporting includes those written policies and procedures that:
| |
i | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation; |
| |
ii | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and |
| |
iii | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2013. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed
Other than the results of its assessment with the Audit Committee of our Board of Directors.
Based on this assessment, management determined that, as of December 31, 2013, Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.
c. Changes in Internal Control Over Financial Reporting
Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this reportsystem conversion described above, there were 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.
AlabamaLaclede Gas Corporation
a. Disclosure Controls and Procedures
Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, asAs of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our chief executive officermanagement, including our Chief Executive Officer and chief financial officerChief Financial Officer, of the effectiveness of the design and operation of our 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 at that reasonable assurance level.effective.
b. Management’s Report onChanges in Internal Control Overover Financial Reporting
Management of AlabamaDuring our fourth fiscal quarter we converted our MGE customers onto the Laclede Gas Corporation is responsible for establishingcustomer care and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f)billing application. This conversion and 15d-15(f) under the Securities Exchange Act of 1934. Alabama Gas Corporation’s internal control over financial reporting is a process designedrelated changes 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. Internal control over financial reporting includes those written policies and procedures that:
| |
i | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Alabama Gas Corporation; |
| |
ii | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Alabama Gas Corporation are being made only in accordance with authorization of management and directors of Alabama Gas Corporation; and |
| |
iii | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2013. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Alabama Gas Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
Based on this assessment, management determined that, as of December 31, 2013, Alabama Gas Corporation maintained effective internal control over financial reporting. The effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.
c. Remediation of Material Weakness
Alabama Gas Corporation disclosed in Item4. Controls and Procedures of our Quarterly Report on Form 10-Q, for the quarter ended September 30, 2013, that we identified a material weakness inprocesses have changed our internal control over customer billing and financial reporting related to failure by Alabama Gas Corporation’s principal accounting officer to operate withinreporting.
Other than the Company’s code of conduct. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such thatsystem conversion discussed above, there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Due to this weakness, certain controls were overridden resulting in an immaterial understatement of expenses for the quarter ended June 30, 2013 of approximately $76,000. Since the override was identified by management prior to preparation of financial statements for the quarter ended September 30, 2013, it did not result in misstatement for that quarter.
Management, with the participation of the chief executive officer and chief financial officer, took action to remediate the material weakness described above including the following:
The principal accounting officer who overrode the control has separated from Alabama Gas Corporation
A qualified successor principal accounting officer has been elected by the Alabama Gas Corporation Board of Directors
In addition to an ongoing annual training process, the importance of adherence to Alabama Gas Corporation’s statement of principles and business conduct guidelines as well as compliance with applicable accounting and reporting principles was reviewed and reinforced with key accounting personnel
The importance of timely, complete and accurate recording of expenses was reviewed and reinforced with the Alabama Gas Corporation officers
Management has completed the remediation measures described above and, as of December 31, 2013, has concluded that the steps taken have remediated the material weakness.
d. Changes in Internal Control Over Financial Reporting
As described above under “Remediation of Material Weakness”, there was a change, during the most recent fiscal quarter,no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
Alagasco
Disclosure Controls and Procedures
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.
Changes in Internal Control over Financial Reporting
There were 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 Reports on Internal Control Over Financial Reporting and the Reports of Independent Registered Public Accounting Firm are included under Item 8, pages 49 through 54. ITEM 9B. OTHER INFORMATION
None.
PARTPart III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information about:
Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10our directors is incorporated herein by reference from Energen’s definitivethe discussion under Proposal 1 of our proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014. The definitive proxy statement will be filed on or about March 21, 2014.December 18, 2015 (2015 proxy statement);
our executive officers are 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 2015 proxy statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”;
our Financial Code of Ethics is posted on our website, www.TheLacledeGroup.com, in the Corporate Governance 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 2015 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.
ITEM 11. EXECUTIVE COMPENSATION
The information regardingInformation about director and executive compensation is incorporated herein by reference from Energen’s definitivethe discussion in our 2015 proxy statement forunder the Annual Meeting of Shareholders to be held April 23, 2014.
headings: “Directors’ Compensation,” “Compensation Discussion and Analysis,” and “Executive Compensation.” The 2015 proxy statement also includes the “Compensation Committee Report,” which is deemed furnished and not filed.
| |
ITEM 12. | ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
a. Security Ownership of Certain Beneficial Owners
The information regarding theInformation about security ownership of thecertain beneficial owners of more than five percent of Energen’s common stockand management is incorporated herein by reference from Energen’s definitivethe discussion in our 2015 proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014.
b. Securityunder “Beneficial Ownership of Management
The information regarding the security ownership of management is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014.
c. Securities Authorized for Issuance Under Equity Compensation Plans
Laclede Group Common Stock.”
The following table summarizessets forth aggregate information concerning securities authorized for issuance underregarding the Company’s equity compensation plans as of December 31, 2013:September 30, 2015:
|
| | | | | | |
Plan Category | Number of Securities to be Issued for Outstanding Options and Performance Share Awards |
Weighted Average Exercise Price | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans |
| Equity compensation plans approved by security holders* | 1,191,044 |
| $ | 51.06 |
| 3,754,816 |
| Equity compensation plans not approved by security holders | — |
| — |
| — |
| Total | 1,191,044 |
| $ | 51.06 |
| 3,754,816 |
* These plans include 2,921,392 shares associated with the Company’s Stock Incentive Plan, 138,284 shares associated with the 1992 Energen Corporation Directors Stock Plan and 695,140 shares associated with the 1997 Deferred Compensation Plan.
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a. Documents Filed as Part of This Report
|
| | | | | | | | | |
| 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) | 536,374 |
| | $ | 33.65 |
| | 967,555 |
|
| Equity compensation plans not approved by security holders | — |
| | — |
| | — |
|
| Total | 536,374 |
| | 33.65 |
| | 967,555 |
|
| |
| (1) | Financial StatementsReflects the Company’s 2015 and 2006 Equity Incentive Plans. Included in column (a) are 507,874 non-vested restricted stock units issued under the Equity Incentive Plan for which the weighted average exercise price in column (b) does not take into account. |
The consolidated financial statementsInformation regarding the above referenced plans is set forth in Note 3, Stock-Based Compensation, of Energen and the financial statements of Alagasco are includedNotes to Financial Statements in Item 8 of this Form 10-K.report.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information about:
our policy and procedures for related party transactions and
the independence of our directors
is included in our 2015 proxy statement under “Corporate Governance” and is incorporated by reference. There were no related party transactions in fiscal year 2015.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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 2015 proxy statement under “Fees of Independent Registered Public Accountant” and “Corporate Governance,” respectively.
Part IV
|
| | | | | | |
(2)ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES | | |
| | | | |
| (a) | 1. | Financial Statement SchedulesStatements | | |
| | See Item 8. Financial Statements and Supplementary Data, filed herewith, for a list of financial statements. |
| | | | |
| 2. | Exhibits | | |
| | Incorporated herein by reference to Exhibit Index, page 145. | | |
| | | | | | |
| (b) | | Incorporated herein by reference to Exhibit Index, page 145. | | | | |
The financial statement schedules are included in Item 8 of this Form 10-K.
(3)Exhibits
The exhibits listed on the accompanying Index to Exhibits are filed as part of this Form 10-K.
Energen CorporationSIGNATURES
Alabama Gas Corporation
INDEX TO EXHIBITS
Item 14(a)(3)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.
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Exhibit | |
Number | Description |
| | |
*3(a) | Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005THE LACLEDE GROUP, INC. |
| | | | |
*3(b)November 24, 2015 | Articles | | /s/ Steven P. Rasche |
| | | Steven P. Rasche |
| | | Executive 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.
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| Date | | Signature | Title |
| | | |
| November 24, 2015 | | /s/ Suzanne Sitherwood | Director, President, and Chief Executive Officer |
| | Suzanne Sitherwood | (Principal Executive Officer) |
| | | |
| November 24, 2015 | | /s/ Steven P. Rasche | Executive Vice President and Chief Financial Officer |
| | Steven P. Rasche | (Principal Finance and Accounting Officer) |
| | | |
| November 24, 2015 | | /s/ Edward L. Glotzbach | Chairman of Amendment to Restated Certificatethe Board |
| | Edward L. Glotzbach | |
| | | |
| November 24, 2015 | | /s/ Mark A. Borer | Director |
| | Mark A. Borer | |
| | | |
| November 24, 2015 | | /s/ Maria V. Fogarty | Director |
| | Maria V. Fogarty | |
| | | |
| November 24, 2015 | | /s/ Anthony V. Leness | Director |
| | Anthony V. Leness | |
| | | |
| November 24, 2015 | | /s/ W. Stephen Maritz | Director |
| | W. Stephen Maritz | |
| | | |
| November 24, 2015 | | /s/ Brenda D. Newberry | Director |
| | Brenda D. Newberry | |
| | | |
| November 24, 2015 | | /s/ John P. Stupp, Jr. | Director |
| | John P. Stupp, Jr. | |
| | | |
| November 24, 2015 | | /s/ Mary Ann Van Lokeren | Director |
| | Mary Ann Van Lokeren | |
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.
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| | | | LACLEDE GAS COMPANY |
| | | | |
| Dated: | November 24, 2015 | | | /s/ Steven P. Rasche |
| | | | Steven P. Rasche |
| | | | 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.
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| Date | | Signature | Title |
| | | |
| November 24, 2015 | | /s/ Suzanne Sitherwood | Chairman of Incorporationthe Board |
| | Suzanne Sitherwood | |
| | | |
| | | |
| November 24, 2015 | | /s/ Steven P. Rasche | Director and Chief Financial Officer |
| | Steven P. Rasche | (Principal Financial and Accounting Officer) |
| | | |
| November 24, 2015 | | /s/ Steven L. Lindsey | Director, Chief Executive Officer and President |
| | Steven L. Lindsey | (Principal Executive Officer) |
| | | |
| November 24, 2015 | | /s/ Mark C. Darrell | Director |
| | Mark C. Darrell | |
| | | |
| November 24, 2015 | | /s/ L. C. Dowdy | Director |
| | L. C. Dowdy | |
| | | |
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.
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| | | | ALABAMA GAS CORPORATION |
| | | | |
| Dated: | November 24, 2015 | | | /s/ Steven P. Rasche |
| | | | Steven P. Rasche |
| | | | 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.
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| Date | | Signature | Title |
| | | |
| November 24, 2015 | | /s/ Suzanne Sitherwood | Chairman of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which wasthe Board |
| | Suzanne Sitherwood | |
| | | |
| | | |
| November 24, 2015 | | /s/ Steven P. Rasche | Director and Chief Financial Officer |
| | Steven P. Rasche | (Principal Financial and Accounting Officer) |
| | | |
| November 24, 2015 | | /s/ Steven L. Lindsey | Director and Chief Executive Officer |
| | Steven L. Lindsey | (Principal Executive Officer) |
| | | |
| November 24, 2015 | | /s/ Mark C. Darrell | Director |
| | Mark C. Darrell | |
| | | |
| November 24, 2015 | | /s/ L. C. Dowdy | Director |
| | L. C. Dowdy | |
| | | |
EXHIBIT INDEX
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| Exhibit Number | | |
| 2.01* | | Agreement and Plan of Merger and Reorganization; filed as Exhibit 4(b)Appendix A to Energen’s Post Effective Amendment No. 1 toproxy statement/prospectus contained in the Company's Registration Statement on Form S-3 (RegistrationS-4 filed October 27, 2000, No. 333-00395)333-48794. |
| 3.01* | |
*3(c) | BylawsThe Company's Articles of Energen Corporation (as amended through July 23, 2008) which wasIncorporation, as amended; filed as Exhibit 99.13.1 to Energen’sthe Company's Current Report on Form 8-K dated July 25, 2008filed January 26, 2006. |
| 3.02* | | The Company's Bylaws, as amended, effective as of August 1, 2015; filed as Exhibit 3.1 to the Company's Current Report on Form 8-K filed on July 31, 2015. |
*3(d)3.03* | | Laclede Gas' Restated Articles of Incorporation as amended March 8, 2013; filed as Exhibit 3.1 to Laclede Gas' Quarterly Report on Form 10-Q/A for the fiscal quarter ended March 31, 2013. |
| 3.04* | | Amended and Restated Bylaws of Laclede Gas, effective as of August 1, 2015; filed as Exhibit 3.2 to Laclede Gas' Current Report on Form 8-K filed July 31, 2015. |
| 3.05* | | Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation,Alagasco, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant’sAlagasco's Annual Report on Form 10-K for the year ended September 30, 1995 |
| 3.06* | |
*3(e) | Bylaws of Alabama Gas CorporationAlagasco (as amended through October 24, 2007) which wasSeptember 2, 2014); filed as Exhibit 33(b) to Energen’s QuarterlyAlagasco's Annual Report on Form 10-KT for the fiscal year ended September 30, 2014. |
| 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 as Exhibit b-4 to registration statement No. 2-64857 filed June 26, 1979. |
| 4.03* | | Twenty-Fourth Supplemental Indenture dated as of June 1, 1999, between Laclede Gas and State Street Bank and Trust Company of Missouri, N.A., as trustee; filed as Exhibit 4.01 to Laclede Gas' Current Report on Form 8-K filed June 4, 1999. |
| 4.04* | | Twenty-Fifth Supplemental Indenture dated as of September 15, 2000, between Laclede Gas and State Street Bank and Trust Company of Missouri, as trustee; filed as Exhibit 4.01 to Laclede Gas' Current Report on Form 8-K filed September 27, 2000. |
| 4.05* | | Twenty-Seventh Supplemental Indenture dated as of April 15, 2004, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.01 to Laclede Gas' Current Report on Form 8-K filed April 28, 2004. |
| 4.06* | | Twenty-Eighth Supplemental Indenture dated as of April 15, 2004, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.02 to Laclede Gas' Current Report on Form 8-K filed April 28, 2004. |
| 4.07* | | Twenty-Ninth Supplemental Indenture dated as of June 1, 2006, between Laclede Gas and UMB Bank and Trust, N.A., as trustee; filed as Exhibit 4.1 to Laclede Gas' Current Report on Form 8-K filed June 9, 2006. |
| 4.08* | | Thirty-First Supplemental Indenture, dated as of March 15, 2013, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.1 to the Company's Form 10-Q for the periodfiscal quarter ended OctoberMarch 31, 20072013. |
| 4.09* | |
*4(a) | Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which wasThirty-Second Supplemental indenture, dated as of September 1, 1996 (the “Energen 1996 Indenture”)August 13, 2013, between Laclede Gas and UMB Bank & Trust, N.A., and which wasas trustee; filed as Exhibit 4(i)4.1 to the Registrant’s Registration StatementLaclede Gas' Current Report on Form S-3 (Registration No. 333-11239)8-K filed August 13, 2013. |
| 4.10* | |
*4(a)(i) | Officers’ Certificate,Laclede Gas Board of Directors’ Resolution dated September 13, 1996, pursuantAugust 28, 1986 which generally provides that the Board may delegate its authority in the adoption of certain employee benefit plan amendments to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which wascertain designated Executive Officers; filed as Exhibit 4(d)(i)4.12 to Energen’sLaclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 20011991. |
| 4.11* | |
*4(a)(ii) | Officers’ Certificate,Laclede Gas' Board of Directors’ Resolutions dated July 8, 1997,March 27, 2003, updating authority delegated pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which wasAugust 28, 1986 Laclede Gas resolutions; filed as Exhibit 4(d)(ii)4.19(a) to Energen’sthe Company's Annual Report on Form 10-K for the fiscal year ended September 30, 20012003. |
| 4.12* | |
*4(a)(iii) | AmendedJunior Subordinated Indenture, dated as of June 11, 2014, between the Company and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filedU.S. Bank National Association, as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001 |
| |
*4(a)(iv) | Officers’ Certificate, dated August 5, 2011, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 4.65 percent Senior Notes due September 1, 2021, which wastrustee; filed as Exhibit 4.1 to Energen’sThe Laclede Group's Current Report on Form 8-K dated August 5, 2011filed June 11, 2014. |
| 4.13* | | First Supplemental Indenture, dated as of June 11, 2014, between the Company and U.S. Bank National Association, as trustee (including Form of Series A 2.00% Remarketable Junior Subordinated Notes due 2022); filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed June 11, 2014. |
| 4.14* | | Purchase Contract and Pledge Agreement, dated as of June 11, 2014, between the Company and US Bank National Association, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (including Form of Remarketing Agreement, Form of Corporate Units and Form of Treasury Units); filed as Exhibit 4.4 to the Company's Current Report on Form 8-K filed June 11, 2014. |
| 4.15* | | Indenture, dated as of August 19, 2014, between the Company and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed August 19, 2014. |
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| | |
| Exhibit Number | | |
*4(b)4.16* | | First Supplemental Indenture, dated as of August 19, 2014, between the Company and UMB Bank & Trust, N.A., as trustee (including Form of Floating Rate Senior Notes due 2017, Form of 2.55% Senior Notes due 2019 and Form of 4.70% Senior Notes due 2044); filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed August 10, 2014. |
| 4.17* | | Indenture dated as of November 1, 1993, between Alabama Gas CorporationAlagasco and NationsBank of Georgia, National Association, Trustee, (“Alagasco 1993 Indenture”), which was filed as Exhibit 4(k) to Alabama Gas Corporations’Alagasco's Registration Statement on Form S-3 (Registration No. 33-70466). |
| 4.18* | |
*4(b)(i) | Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005 |
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*4(b)(ii) | Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas CorporationAlagasco 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’Alagasco's Current Report on Form 8-K filed January 14, 20052005. |
| 4.19* | |
|
| |
*4(b)(iii) | Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas CorporationAlagasco 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’Alagasco's Current Report on Form 8-K filed November 17, 20052005. |
| 4.20* | |
*4(b)(iv) | Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas CorporationAlagasco 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’Alagasco's Current Report on Form 8-K filed January 16, 20072007. |
| 10.01* | | Lease between Laclede Gas, as Lessee, and First National Bank in St. Louis, Trustee, as Lessor; filed as Exhibit 10.23 to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 2002. |
| 10.02* | | Automated Meter Reading Services Agreement, dated as of March 11, 2005, between Cellnet Technology, Inc. and Laclede Gas; filed as Exhibit 10.1 to Laclede Gas' Quarterly Report on 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. |
| 10.03* | | Restated Laclede Gas Supplemental Retirement Benefit Plan, as amended and restated as of January 1, 2005; filed as Exhibit 10.06 to Laclede Gas' Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.04* | | Laclede Gas Supplemental Retirement Benefit Plan II, effective as of January 1, 2005; filed as Exhibit 10.7 to Laclede Gas' Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.05* | | Amendment and Restatement of Retirement Plan for Non-Employee Directors of Laclede Gas as of November 1, 2002; filed as Exhibit 10.08c to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 2002. |
| 10.06* | | Amendment to Terms of Retirement Plan for Non-Employee Directors of Laclede Gas as of October 1, 2004; filed as Exhibit 10.2 to Laclede Gas' Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004. |
| 10.07* | | Salient Features of Laclede Gas' 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 Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 1991. |
| 10.08* | | Amendment to Laclede Gas' Deferred Income Plan for Directors and Selected Executives, adopted by the Board of Directors on August 27, 1992; filed as Exhibit 10.12a to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 1992. |
| 10.09* | | Salient Features of Laclede Gas' 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 Laclede Gas' Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.10* | | 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 Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.11* | | The Company's Deferred Income Plan for Directors and Selected Executives, as Amended and Restated as of January 1, 2015; filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed November 4, 2014. |
| 10.12* | | Form of Indemnification Agreement between Laclede Gas and its Directors and Officers; filed as Exhibit 10.13 to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 1990. |
| 10.13* | | The Company's Management Continuity Protection Plan, effective as of January 1, 2005; filed as Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.14* | | Form of Management Continuity Protection Agreement; filed as Exhibit 10.05a to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.15* | | The Company's 2011 Management Continuity Protection Plan; filed as Exhibit 10.25 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2010. |
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| Exhibit Number | | |
*10(a)10.16* | | Form of Agreement under the Company's 2011 Management Continuity Protection Plan; filed as Exhibit 10.25a to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2010. |
| 10.17* | �� | Restricted Stock Plan for Non-Employee Directors as amended and effective January 29, 2009; filed as Appendix A to the Company's Definitive Proxy Statement on Schedule 14A filed December 22, 2008. |
| 10.18* | | Amendment to Restricted Stock Plan for Non-Employee Directors; filed as Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011. |
| 10.19* | | Form of Non-Qualified Stock Option Award Agreement with Mandatory Retirement Provisions; filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed November 5, 2004. |
| 10.20* | | Form of Non-Qualified Stock Option Award Agreement without Mandatory Retirement Provisions; filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed November 5, 2004. |
| 10.21* | | The Company's 2002 Equity Incentive Plan; filed as Exhibit 10.22 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2002. |
| 10.22* | | The Company's 2006 Equity Incentive Plan, as amended effective February 1, 2012; filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2012. |
| 10.23* | | The Laclede Group 2015 Equity Incentive Plan; filed as the Appendix to the Company's Definitive Proxy Statement on Form DEF 14A filed December 19, 2014. |
| 10.24* | | The Company's Annual Incentive Plan; filed as Appendix 1 to the Company's Definitive Proxy Statement on Schedule 14A filed December 17, 2010. |
| 10.25* | | The Company's Form of Restricted Stock Award Agreement; filed as Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008. |
| 10.26* | | The Company's Form of Performance Contingent Restricted Stock Award Agreement; filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2009. |
| 10.27* | | The Company's Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2011. |
| 10.28* | | The Company's Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2012. |
| 10.29* | | Severance Benefits Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011. |
| 10.30* | | First Amendment to the Severance Benefits Agreement, dated August 1, 2014, between the Company and Suzanne Sitherwood; filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014. |
| 10.31* | | Performance Contingent Restricted Stock Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011. |
| 10.32* | | Restricted Stock Unit Award Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011. |
| 10.33* | | Restricted Stock Unit Award Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Ex 10.25 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2012. |
| 10.34* | | Performance Contingent Restricted Stock Unit Award Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Ex 10.26 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2012. |
| 10.35* | | Severance Benefits Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Exhibit 10.27 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2012. |
| 10.36* | | Note Purchase Agreement, dated August 3, 2012, by and among the Company and the Purchasers listed in Schedule A thereto; filed as Exhibit 10.28 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2012. |
| 10.37* | | Laclede Gas Cash Balance Supplemental Retirement Benefit Plan, effective as of January 1, 2009; filed as Exhibit 10.30 to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 2012. |
| 10.38* | | 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 Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2012. |
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| Exhibit Number | | |
| 10.39* | | Amended and Restated Storage Service Agreement For Rate Schedule FSS, Contract #3147, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.1 to Laclede Gas' Current Report on Form 8-K filed August 2, 2013. |
| 10.40* | | Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3310, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.2 to Laclede Gas' Current Report on Form 8-K filed August 2, 2013. |
| 10.41* | | Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3311, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.3 to Laclede Gas' Current Report on Form 8-K filed August 2, 2013. |
| 10.42* | | Purchase and Sale Agreement for Missouri Gas Energy, dated as of December 14, 2012, by and among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company (solely for purposes of Section 13.19 of the Agreement); filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed December 17, 2012. |
| 10.43* | | Purchase and Sale Agreement for New England Gas Company, dated as of December 14, 2012, among Southern Union Company, Plaza Massachusetts Acquisition, Inc. and the Company; filed as Exhibit 2.2 to the Company's Current Report on Form 8-K filed December 17, 2012. |
| 10.44* | | Employee Agreement for Missouri Gas Energy, dated as of December 14, 2012, among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company; filed as Exhibit 2.3 to the Company's Current Report on Form 8-K filed December 17, 2012. |
| 10.45* | | Employee Agreement for New England Gas Company, dated as of December 14, 2012, among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company; filed as Exhibit 2.4 to the Company's Current Report on Form 8-K filed December 17, 2012. |
| 10.46* | | Stock Purchase Agreement, dated as of February 11, 2013, by and among the Company, Plaza Massachusetts Acquisition, Inc., and Algonquin Power & Utilities Corp.; filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed February 12, 2013. |
| 10.47* | | Assignment and Assumption Agreement, dated as of January 11, 2013, by and between Plaza Missouri Acquisition, Inc. and Laclede Gas; filed as Exhibit 99.1 to Laclede Gas' Current Report on Form 8-K filed January 14, 2013. |
| 10.48* | | Consent to Assignment executed by Southern Union Company dated as of January 11, 2013; filed as Exhibit 99.2 to Laclede Gas' Current Report on Form 8-K filed January 14, 2013. |
| 10.49* | | Consent Agreement, dated as of February 11, 2013, by and among the Company, Plaza Massachusetts Acquisition, Inc. Southern Union Company and Algonquin Power & Utilities Corp.; filed as Exhibit 2.2 to the Company's Current Report on Form 8-K filed February 12, 2013. |
| 10.50* | | Loan agreement, dated September 3, 2013, among the Company and the several bank parties thereto, 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 Association 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; filed as Exhibit 10.20 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2013. |
| 10.51* | | First Amendment and Waiver to Loan Agreement, dated as of April 28, 2014, among the Company and the several banks parties thereto, including Wells Fargo Bank, National Association as Administrative Agent; filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014. |
| 10.52* | | First Extension Agreement, dated as of September 3, 2014, to Loan Agreement, dated September 3, 2013, as amended, by and among the Company and the several banks party thereto, including Wells Fargo Bank, National Association, as administrative agent; filed as Exhibit 99.2 to the Company's Current Report on Form 8-K filed September 4, 2014. |
| 10.53* | | Loan agreement, dated September 3, 2013, among Laclede Gas and the several bank parties thereto, 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 Association 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; filed as Exhibit 10.12 to Laclede Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 2013. |
| 10.54* | | First Extension Agreement, dated as of September 3, 2014, to Loan Agreement, dated September 3, 2013, as amended, by and among Laclede Gas and the several banks party thereto, including Wells Fargo Bank, National Association, as administrative agent; filed as Exhibit 99.3 to Laclede Gas' Current Report on Form 8-K filed September 4, 2014. |
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| | |
| Exhibit Number | | |
| 10.55* | | Lease Agreement, dated January 21, 2014, between the Company, as Tenant, and Market 700, LLC, as Landlord; filed as Exhibit 10.1 to Laclede Group, Inc.'s Current Report on Form 8-K filed January 27, 2014. |
| 10.56* | | Stock Purchase Agreement, dated as of April 5, 2014, between the Company and Energen Corporation; filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed April 7, 2014. |
| 10.57* | | Commitment Letter, dated April 5, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed April 7, 2014. |
| 10.58* | | First Amendment to the Commitment Letter, dated June 16, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed June 17, 2014. |
| 10.59* | | 2nd Amendment to Commitment Letter, dated August 19, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed August 21, 2014. |
| 10.60* | | The Company's Executive Severance Plan effective January 1, 2015; filed as Exhibit 10.59 to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2014. |
| 10.61* | | Master Note Purchase Agreement, dated as of June 5, 2015, among Alagasco and certain institutional purchasers; filed as Exhibit 10.1 to to Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2015. |
| 10.62* | | Credit Agreement dated September 2, 2014, by and among Alagasco, Wells Fargo Bank, National Association., as Administrative Agent, Credit Suisse AG, Cayman Islands Branch and U.S. Bank National Association, as CO-Syndication Agents, Wells Fargo Securities LLC, Credit Suisse Securities (USA) LLC and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 991. to Alagasco’s Current Report on Form 8-K filed September 4, 2014. |
| 10.63* | | Credit Agreement dated October 30, 2012, by and among Energen Corporation, Energen Resources Corporation,Alagasco, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 31, 2012 |
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*10(b) | Credit Agreement dated December 17, 2013, with respect to a $600 million term loan, by and among Energen Corporation, as Borrower, Energen Resources Corporation, as Guarantor, Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, National Association, Regions Bank, Compass Bank, JPMorgan Chase Bank, N.A. and U.S. Bank National Association, as Co-Syndication Agents, and the lenders party thereto, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed December 19, 2013 |
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*10(c) | Credit Agreement dated October 30, 2012, by and among Alabama Gas Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-DocumentationCo- Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Energen’sAlagasco’s Current Report on Form 8-K filed October 31, 20122012. |
| 10.64* | |
*10(d) | Note Purchase Agreement, dated December 22, 2011, among Alabama Gas CorporationAlagasco and the Purchasers thereto (the AIG purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.1 to Alabama Gas Corporation’sAlagasco’s Current Report on Form 8-K filed December 22, 20112011. |
| 10.65* | |
*10(e) | Note Purchase Agreement, dated December 22, 2011, among Alabama Gas CorporationAlagasco and the Purchasers thereto (the Prudential purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.2 to Alabama Gas Corporation’sAlagasco’s Current Report on Form 8-K filed December 22, 20112011. |
| 10.66* | |
*10(f) | Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation,Alagasco, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’sAlagasco’s Annual Report on Form 10-K for the year ended December 31, 20052005. |
| 10.67* | |
10(g) | Amended Exhibit A, effective January 15, 2014, to Service Agreement Under Rate Schedule CSS (No. SSNG1) between Southern Natural Gas Company and Alabama Gas CorporationAlagasco dated September 1, 2005 which was filed as Exhibit 10(g) to Alagasco's Annual Report on Form 10-K for the year ended December 31, 2013. |
| 10.68* | |
*10(h) | Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas CorporationAlagasco dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’sAlagasco’s Annual Report on Form 10-K for the year ended December 31, 20052005. |
| 10.69* | |
10(i) | Amended Exhibit A, effective October 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas CorporationAlagasco, which was filed as Exhibit 10(i) to Alagasco's Annual Report on Form 10-K for the year ended December 31, 2013. |
| 10.70* | |
10(j) | Amended Exhibit B, effective November 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas CorporationAlagasco, which was filed as Exhibit 10(j) to Alagasco's Annual Report on Form 10-K for the year ended December 31, 2013. |
| 10.71* | |
*10(k) | Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation,Alagasco, which was filed as Exhibit 10(b) to Energen’sAlagasco’s Annual Report on Form 10-K for the year ended September 30, 19931993. |
| 10.72* | |
|
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*10(l) | Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation,Alagasco, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen’sAlagasco’s Annual Report on Form 10-K for the year ended December 31, 20032003. |
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| Exhibit Number | | |
*10(m)10.73* | | Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation,Alagasco, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’sAlagasco’s Annual Report on Form 10-K for the year ended December 31, 20052005. |
| 12.1 | | Ratio of Earnings to Fixed Charges of the Company. |
*10(n)12.2 | Form | Ratio of Executive Retirement Supplement Agreement between Energen CorporationEarnings to Fixed Charges of Laclede Gas. |
| 21 | | Subsidiaries of the Company and its executive officers (as revised October 2000) which was filedLaclede Gas. |
| 23.1 | | Consent of Independent Registered Public Accounting Firm of the Company. |
| 23.2 | | Consent of Independent Registered Public Accounting Firm of Laclede Gas. |
| 31.1 | | Certifications under Rule 13a-14(a) of the CEO and CFO of the Company. |
| 31.2 | | Certifications under Rule 13a-14(a) of the CEO and CFO of Laclede Gas. |
| 31.3 | | Certifications under Rule 13a-14(a) of the CEO and CFO of Alagasco. |
| 32.1 | | Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of the Company. |
| 32.2 | | Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of Laclede Gas. |
| 32.3 | | Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of Alagasco. |
| 101.INS | | XBRL Instance Document. (1) |
| 101.SCH | | XBRL Taxonomy Extension Schema. (1) |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase. (1) |
| 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 10(c)101 to Energen’sthis Annual Report on Form 10-Kare the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Consolidated Statements of Income and Statements of Income for the years ended September 30, 2015, 2014, and 2013; (iii) Consolidated Statements of Comprehensive Income and Statements of Comprehensive Income for the years ended September 30, 2015, 2014, and 2013; (iv) Consolidated Statements of Common Shareholders' Equity and Statements of Common Shareholder's Equity for the years ended September 30, 2015, 2014, and 2013; (v) Consolidated Statements of Cash Flows and Statements of Cash Flows for the years ended September 30, 2015, 2014, and 2013; (vi) Consolidated Balance Sheets and Balance Sheets at September 30, 2015 and 2014; (vii) Consolidated Statements of Capitalization and Statements of Capitalization at September 30, 2015 and 2014; and (viii) Notes to Financial Statements. For Alagasco, the Statements of Income, Comprehensive Income, Common Shareholder's Equity, and Cash Flows are for the year ended September 30, 2000 |
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10(o) | Form of Amendment to Executive Retirement Supplement Agreement between Energen Corporation2015, the nine months ended September 30, 2014, and its executive officers, dated December 12, 2007 |
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*10(p) | Form of Severance Compensation Agreement between Energen Corporation and its executive officers which was filed as Exhibit 10.3 to Energen’s Current Report on Form 8-K filed December 13, 2012 |
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*10(q) | Energen Corporation Stock Incentive Plan (as amended effective December 11, 2013) which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed December 12, 2013 |
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*10(r) | Form of Stock Option Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(r) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012 |
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*10(s) | Form of Restricted Stock Agreement under2013. We also make available on our website the Energen Corporation Stock Incentive Plan which was filedInteractive Data Files submitted as Exhibit 10(s)101 to Energen’sthis Annual Report on Form 10-K for the year ended December 31, 2012 |
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*10(t) | Form of Restricted Stock Unit Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed December 12, 2013 |
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*10(u) | Form of Performance Share Award under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(t) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012 |
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*10(v) | Energen Corporation 1997 Deferred Compensation Plan (as amended December 12, 2012) which was filed as Exhibit 10(u) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2013 |
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*10(w) | Energen Corporation Directors Stock Plan (as amended April 28, 2010) which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A , filed March 19, 2010 |
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*10(x) | Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2013, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K, filed December 13, 2012 |
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21 | Subsidiaries of Energen Corporation and Alabama Gas Corporation |
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23(a) | Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP) |
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23(b) | Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.) |
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23(c) | Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.) |
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24 | Power of Attorney |
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31(a) | Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) |
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31(b) | Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)Report. |
|
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31(c) | Alabama Gas Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) |
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31(d) | Alabama Gas Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) |
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32(a) | Energen Corporation Certification pursuant to 18 U.S.C. Section 1350 |
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32(b) | Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350 |
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99(a) | Reserve Audit – Ryder Scott & Company, L.P. |
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99(b) | Reserve Audit – T. Scott Hickman and Associates, Inc. |
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101 | The financial statements and notes thereto from Energen Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013 are formatted in XBRL |
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*Incorporated by reference |
SIGNATURE* Incorporated herein by reference and made a part hereof. The Company File No. 1-16681. Laclede Gas File No. 1-1822. Alagasco file No. 2-38960.
Pursuant to the requirements of Section 13Bold items reflect management, contract or 15(d) of the Securities and Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
|
| | |
March 3, 2014 | | By /s/ J.T. McManus, II |
| | J.T. McManus, II |
| | Chairman, Chief Executive Officer and President of
Energen Corporation; Chairman and Chief Executive
Officer of Alabama Gas Corporation; Director
|
compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrants and in the capacities and on the dates indicated:
|
| | | |
March 3, 2014 | | By | /s/ J.T. McManus, II |
| | J.T. McManus, II
Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation; Director
|
| | | |
March 3, 2014 | | By | /s/ Charles W. Porter, Jr. |
| | Charles W. Porter, Jr.
Vice President, Chief Financial Officer and
Treasurer of Energen Corporation and Alabama
Gas Corporation
|
| | | |
March 3, 2014 | | By | /s/ Russell E. Lynch, Jr. |
| | Russell E. Lynch, Jr.
Vice President and Controller of Energen
Corporation
|
| | | |
March 3, 2014 | | By | /s/ Leonarda M. DiChiara |
| | Leonarda M. DiChiara
Vice President and Controller of Alabama Gas
Corporation
|
| | | |
March 3, 2014 | | * |
| | Kenneth W. Dewey
Director
|
| | | |
March 3, 2014 | | * |
| | Jay Grinney
Director
|
| | | |
March 3, 2014 | | * |
| | Frances Powell Hawes
Director
|
| | | |
March 3, 2014 | | * |
| | Judy M. Merritt
Director
|
| | | |
| | *By | /s/ Charles W. Porter, Jr. |
| | Charles W. Porter, Jr.
Attorney-in-Fact
|
