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As filed with the Securities and Exchange Commission on May 29, 2013

No. 333-185376

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

Post-Effective Amendment No. 2

TO

 

FORM S-1

 

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

 


 

DYNEGY INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

4911

 

20-5653152

(State or other jurisdiction of incorporation

 

(Primary Standard Industrial

 

(I.R.S. Employer Identification No.)

or organization)

 

Classification Code Number)

 

 

 

601 Travis, Suite 1400, Houston, Texas 77002
(713) 507-6400
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 


 

Catherine B. Callaway
Executive Vice President, General Counsel and Chief Compliance Officer
Dynegy Inc.

601 Travis, Suite 1400

Houston, Texas 77002

(713) 507-6400

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 


 

Copies of all communications, including communications sent to agent for service, should be sent to:

 

Gregory Pryor

David Johansen

White & Case LLP
1155 Avenue of the Americas
New York,  New York 10036

(212) 819-8200

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

 


 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: x

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one): 

 

Large accelerated filer o

 

Accelerated filer x

 

Non-accelerated filer o

 

Smaller reporting company o

 

 

 

 

(Do not check if a smaller reporting company).

 

 

 

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 



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EXPLANATORY NOTE

 

This Post-Effective Amendment No. 2 to the Registration Statement on Form S-1 (File No. 333-185376) (the “Registration Statement”) of Dynegy Inc. (the “Dynegy”) is being filed to, among other things, update and supplement the Registration Statement, as originally declared effective by the Securities and Exchange Commission (the “SEC”) on February 13, 2013, to (i) incorporate by reference Dynegy’s Annual Report on Form 10-K for the year ended December 31, 2012, Dynegy’s Definitive Proxy Statement on Schedule 14A, filed on April 4, 2013, Dynegy’s Definitive Additional Materials on Schedule 14A, filed on April 4, 2013, Dynegy’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed on May 2, 2013, and Dynegy’s periodic reports on Form 8-K filed with the SEC on March 14, 2013, March 15, 2013, March 19, 2013, March 22, 2013, March 28, 2013, April 24, 2013, May 21, 2013 and May 22, 2013 to the extent such reports are filed and (ii) reflect other updated information about Dynegy.

 

The information included in this Post-Effective Amendment No. 2 to the Registration Statement updates and supplements the Registration Statement and the Prospectus contained therein.  No additional securities are being registered under this Post-Effective Amendment No. 2.  All applicable SEC registration fees were paid at the time of the filing of the original Registration Statement.

 

Unless otherwise specified or the context requires otherwise, as used herein:

 

·      “2012 Predecessor Period” refers to Dynegy’s operations, January 1, 2012 — October 1, 2012;

 

·      “Old Common Stock” refers to the outstanding common stock of Dynegy that was cancelled in accordance with the Plan on the Plan Effective Date (as defined herein);

 

·      “Predecessor” refers to Dynegy, pre-emergence from bankruptcy;

 

·      “Successor” refers to Dynegy, post-emergence from bankruptcy; and

 

·      “Successor Period” refers to Dynegy’s operations, October 2, 2012 — December 31, 2012.

 



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The information in this prospectus is not complete and may be changed. The selling stockholder may not sell these securities until the registration statement filed with the Securities and Exchange Commission relating to these securities is effective. This prospectus is not an offer to sell these securities and it is not a solicitation of an offer to buy these securities in any jurisdiction where such offer, solicitation or sale is not permitted.

 

Subject to completion, dated May 29, 2013

 

Prospectus

 

 

Dynegy Inc.

 

32,459,817 Shares Common Stock

 

The selling stockholder is offering 32,459,817 shares of common stock, including 1,533,887 shares of common stock issuable upon the exercise of the five-year warrants issued pursuant to the Plan (the “Warrants”). We are not selling any shares of common stock under this prospectus. We will not receive any proceeds from the sale of shares to be offered by the selling stockholder.

 

The common stock offered by this prospectus is being registered to permit the selling stockholder to sell the offered common stock from time to time. The selling stockholder may offer and sell the offered common stock at fixed prices, prevailing market prices at the times of sale, prices related to the prevailing market prices, varying prices determined at the times of sale or negotiated prices. The shares of our common stock offered by this prospectus and any prospectus supplement may be offered by the selling stockholder directly to investors or to or through underwriters, dealers or other agents. We do not know when or in what amounts the selling stockholder may offer these shares of common stock for sale.  The selling stockholder may sell all, some or none of the shares of common stock offered by this prospectus. See “Plan of Distribution” on page 43 for a more complete description of how the offered common stock may be sold.

 

Investing in our common stock involves risks.  See “Risk Factors” beginning on page 9.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete.  Any representation to the contrary is a criminal offense.

 

Our common stock is currently listed on the New York Stock Exchange, which we refer to as the NYSE, under the symbol “DYN.”

 

On May 24, 2013, the last reported sale price on the NYSE of our common stock was $23.95.

 

This prospectus is dated                 , 2013.

 



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

2

WHERE YOU CAN FIND ADDITIONAL INFORMATION

3

INCORPORATION BY REFERENCE OF CERTAIN DOCUMENTS

4

PROSPECTUS SUMMARY

6

THE OFFERING

8

RISK FACTORS

9

USE OF PROCEEDS

12

MARKET FOR OUR COMMON STOCK

13

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14

DIVIDEND POLICY

26

MANAGEMENT

27

PRINCIPAL STOCKHOLDERS

31

SELLING STOCKHOLDER

34

RELATED PARTY TRANSACTIONS AND MATERIAL RELATIONSHIPS WITH THE SELLING STOCKHOLDER

36

DESCRIPTION OF CAPITAL STOCK

38

SHARES ELIGIBLE FOR FUTURE SALE

41

PLAN OF DISTRIBUTION

43

EXPERTS

46

LEGAL MATTERS

 

ANNEX A: FINANCIAL STATEMENTS RELATING TO AER

 

 

You should rely only on the information contained in this prospectus or to which we have referred you. We have not authorized anyone to provide you with information that is different. This prospectus may only be used where it is legal to sell these securities. The information in this prospectus may only be accurate on the date of this prospectus.

 

IF YOU ARE IN A JURISDICTION WHERE OFFERS TO EXCHANGE OR SELL, OR SOLICITATIONS OF OFFERS TO EXCHANGE OR PURCHASE, THE SECURITIES OFFERED BY THIS PROSPECTUS ARE UNLAWFUL, OR IF YOU ARE A PERSON TO WHOM IT IS UNLAWFUL TO DIRECT THESE TYPES OF ACTIVITIES, THEN THE OFFER PRESENTED IN THIS PROSPECTUS DOES NOT EXTEND TO YOU.

 

YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE OF THIS PROSPECTUS AND NEITHER THE MAILING OF THIS PROSPECTUS NOR THE SALE OF OUR COMMON STOCK PURSUANT TO THIS OFFERING SHALL CREATE AN IMPLICATION TO THE CONTRARY.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Certain statements contained or incorporated by reference in this prospectus which are not statements of historical fact constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements included or incorporated by reference into this prospectus, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements.  These statements represent our reasonable judgment of the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements.  You can identify these statements by the fact that they do not relate strictly to historical or current facts.  They use words such as “anticipate”, “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning.  In particular, these include, but are not limited to, statements relating to the following:

 

·      expectations and beliefs related to the AER Acquisition (as defined herein) including satisfying closing conditions;

 

·      anticipated benefits and expected synergies resulting from the AER Acquisition and beliefs associated with integration of operations;

 

·                  our ability to consummate the Dynegy Danskammer, L.L.C. (“Danskammer”) asset sale in accordance with the DNE Debtor Entities Joint Plan of Liquidation (as defined herein) and asset purchase agreement;

 

·                  beliefs and assumptions relating to our liquidity, available borrowing capacity and capital resources generally, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;

 

·                  lack of comparable financial data due to the application of fresh start accounting;

 

·                  limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits;

 

·      expectations regarding our compliance with the new $1.775 billion senior secured Credit Agreement (as defined herein), including collateral demands, interest expense, financial ratios and other payments;

 

·                  the timing and anticipated benefits to be achieved through our company-wide savings improvement programs, including our PRIDE initiative;

 

·      efforts to identify opportunities to reduce congestion and improve busbar power prices;

 

·                  expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject;

 

·                  beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in natural gas prices, if any;

 

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·                  sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof;

 

·                  beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of higher market pricing over the longer term;

 

·                  the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;

 

·                  beliefs and assumptions regarding the outcome of the California tolling contract terminations dispute and the impact of such terminations on the timing and amount of future cash flows;

 

·      ability to mitigate impacts associated with expiring reliability must run and/or capacity contracts;

 

·                  beliefs and assumptions about weather and general economic conditions;

 

·                  projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

 

·                  our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;

 

·                  beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay power generation facility in California;

 

·      beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay and Vermilion facilities;

 

·                  beliefs about the outcome of legal, administrative, legislative and regulatory matters, including the impact of final rules regarding derivatives to be issued by the U.S Commodity Futures Trading Commission (the “CFTC”) under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010; and

 

·                  expectations regarding performance standards and estimates regarding capital and maintenance expenditures.

 

Any or all of our forward-looking statements may turn out to be wrong.  They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control.

 

WHERE YOU CAN FIND ADDITIONAL INFORMATION

 

We have filed a registration statement on Form S-1 under the Securities Act of 1933, as amended (the “Securities Act”) with the SEC to register with the SEC the shares of our common stock being offered in this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules filed with it. For further information about us and our common stock, reference is made to the registration statement and the exhibits and schedules filed with it.  Statements contained in this prospectus regarding the contents of any contract or any other document that is filed as an exhibit to the registration statement are not necessarily complete, and each such

 

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statement is qualified in all respects by reference to the full text of such contract or other document filed as an exhibit to the registration statement.

 

We file annual, quarterly and current reports, proxy and registration statements and other information with the SEC. You may read and copy any reports, statements, or other information that we file, including the registration statement, of which this prospectus forms a part, the exhibits and schedules filed with it, and the information incorporated by reference herein, without charge at the public reference room maintained by the SEC, located at 100 F Street, NE, Washington, D.C. 20549, and copies of all or any part of the registration statement may be obtained from the SEC on the payment of the fees prescribed by the SEC. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room. The SEC also maintains an internet website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the website is www.sec.gov.

 

INCORPORATION BY REFERENCE OF CERTAIN DOCUMENTS

 

We are incorporating by reference specified documents that we file with the SEC, which means that we can disclose important information to you by referring you to those documents that are considered part of this prospectus. We incorporate by reference into this prospectus the documents listed below (other than portions of these documents that are either (1) described in paragraph (e) of Item 201 of Registration S-K or paragraphs (d)(1)-(3) and (e)(5) of Item 407 of Regulation S-K promulgated by the SEC or (2) furnished under Item 2.02 or Item 7.01 of a Current Report on Form 8-K):

 

·                  Dynegy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, filed on March 14, 2013;

 

·      Dynegy’s  Definitive Proxy Statement on Schedule 14A, filed on April 4, 2013;

 

·      Dynegy’s Definitive Additional Materials on Schedule 14A, filed on April 4, 2013;

 

·      Dynegy’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed on May 2, 2013; and

 

·                  Dynegy’s Current Reports on Form 8-K filed January 7, 2013, January 16, 2013, January 22, 2013, February 12, 2013, March 15, 2013, March 19, 2013, March 22, 2013, April 24, 2013, May 21, 2013 and May 22, 2013 (to the extent such reports are filed).

 

Any statement contained in a document incorporated or deemed to be incorporated by reference into this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or any other subsequently filed document that is deemed to be incorporated by reference into this prospectus modifies or supersedes the statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

 

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Any person, including any beneficial owner, to whom this prospectus is delivered may request copies of this prospectus and any of the documents incorporated by reference in this prospectus, without charge, by written or oral request directed to Dynegy Inc., Attention: Investor Relations Department, 601 Travis, Suite 1400, Houston, Texas 77002, telephone (713) 507-6400, on the “Investor Relations” section of our website at http://www.dynegy.com or from the SEC through the SEC’s website at the web address provided under the heading “Where You Can Find More Information.” Documents incorporated by reference are available without charge, excluding any exhibits to those documents unless the exhibit is specifically incorporated by reference into those documents.

 

Except for the documents incorporated by reference as noted above, we do not intend to incorporate into this prospectus any of the information included on our website.

 

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PROSPECTUS SUMMARY

 

The following summary highlights information contained elsewhere in this prospectus. It does not contain all the information that may be important to you in making an investment decision.  You should read this entire prospectus carefully, including the documents incorporated by reference herein and annexed hereto, which are described under “Incorporation by Reference of Certain Documents,” “Where You Can Find Additional Information”and “Annex A: Financial Statements Relating to AER”. You should also carefully consider, among other things, the matters discussed in the section titled “Risk Factors.”  In this prospectus, unless the context requires otherwise, references to “the Company,” “the Issuer,” “we,” “our,” or “us” refer to Dynegy and its consolidated subsidiaries, and references to our “common stock” refer to the common stock of Dynegy.

 

Our Business

 

We began operations in 1984 and became incorporated in the State of Delaware in 2007. We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our primary business is the production and sale of electric energy, capacity and ancillary services from our fleet of twelve operating power plants in six states totaling approximately 9,800 megawatts of generating capacity, which excludes the 1,700 megawatts of generating capacity of our Dynegy Northeast segment (“DNE”) generation facilities that were deconsolidated effective October 1, 2012, and are under agreements to be sold.

 

We sell electric energy, capacity and ancillary services on a wholesale basis from our power generation facilities. Wholesale electricity customers will, for reliability reasons and to meet regulatory requirements, contract for rights to capacity from generating units. Ancillary services are the products of a power generation facility that support the transmission grid operation, follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load. We sell these products individually or in combination to our customers under short-, medium- and long-term agreements.

 

We do business with a wide range of customers, including: regional transmission organizations (“RTOs”) and independent system operators (“ISOs”), integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, industrial customers, power marketers, financial participants such as banks and hedge funds, other power generators and commercial end-users. All of our products are sold on a wholesale basis for various lengths of time, from hourly to multi-year transactions. Some of our customers, such as municipalities or integrated utilities, purchase our products for resale in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from us to serve their own wholesale or retail customers or as a hedge against power sales they have made.

 

Recent Events

 

AER Acquisition

 

On March 14, 2013, we entered into a definitive agreement by and between Ameren Corporation (“Ameren”) and Illinois Power Holdings, LLC, a newly-formed, wholly-owned subsidiary of Dynegy (“IPH”) to acquire Ameren Energy Resources Company, LLC (“AER”) and its subsidiaries, Ameren Energy Generating Company (“Genco”), Ameren Energy Resources Generating Company (“AERG”) and Ameren Energy Marketing Company (“AEM”) from Ameren (the “AER Acquisition”).  The AER Acquisition will add 4,119 MW of generation to our portfolio in Illinois through the Duck Creek, Coffeen, E.D. Edwards, Newton, and Joppa plants and also includes AER’s marketing and retail businesses.  Upon closing, we will own more than 8,000 MW of generating capacity in Illinois, and nearly 14,000 MW nationally. There is no cash consideration or stock issuance as part of the purchase price for the AER Acquisition. Genco’s $825 million debt will remain outstanding at Genco. The AER Acquisition remains subject to certain closing conditions and the receipt of regulatory approvals. We expect to close the AER Acquisition in the fourth quarter of 2013.  Please see Annex A hereto for certain financial statements of AER relating to the AER Acquisition.

 

DNE Bankruptcy Proceedings and Facilities Sale

 

Dynegy Northeast Generation, Inc. (“Northeast Generation”), Hudson Power, L.L.C. (“Hudson”), Danskammer and Dynegy Roseton, L.L.C. (“Roseton” and, together with Northeast Generation, Hudson and Danskammer the “DNE Debtor Entities”) remain in Chapter 11 bankruptcy and continue to operate their businesses as “debtors-in-possession.” As a result, we deconsolidated the DNE Debtor Entities, which include two facilities totaling approximately 1,700 MW, effective October 1, 2012.  On December 14, 2012 the DNE Debtors filed a Chapter 11 Joint Plan of Liquidation (the “DNE Debtor Entities Joint Plan of Liquidation”) and a related disclosure statement with the United States Court for the Southern District of New York, Poughkeepsie Division (the “Bankruptcy Court”). On March 15, 2013, the Bankruptcy Court entered an order confirming the DNE Debtor Entities’ Joint Plan of Liquidation (the “DNE Confirmation Order”). The DNE Confirmation Order and the Bankruptcy Court’s prior approval of the agreements to sell the Danskammer and Roseton facilities (the “Danskammer APA” and the “Roseton APA,” respectively) for a combined cash purchase price of $23 million and the assumption of certain liabilities (the “Facilities Sale Transactions”) facilitate our completion of the Facilities Sale Transactions. On April 30, 2013, we completed the sale of the Roseton facility. The Danskammer facility sale is expected to close upon the satisfaction of certain conditions and the receipt of any necessary regulatory approvals.

 

Refinancing

 

On April 23, 2013 we entered into a new $1.775 billion senior secured credit facility. The new credit facility is comprised of (i) a $500 million seven-year senior secured term loan B facility (the “B-1 Term Loan”), (ii) an $800 million seven-year senior secured term loan B facility (the “B-2 Term Loan” and, together with the B-1 Term Loan, the “Term Facilities”) and (iii) a $475 million five-year senior secured revolving credit facility (the “Revolving Facility”, and collectively with the Term Facilities, the “Credit Agreement”).  Borrowings under the Credit Agreement, together with a portion of Dynegy’s cash on hand, were used to repay in full and terminate commitments under the: (i) Dynegy Power, LLC (“GasCo”) Credit Agreement, dated as of August 5, 2011, (ii) GasCo Revolving Credit Agreement, dated as of January 16, 2013, (iii) Dynegy Midwest Generation, LLC (“CoalCo”) Credit Agreement, dated as of August 5, 2011, (iv) GasCo Letter of Credit Reimbursement and Collateral Agreement with Credit Suisse, dated as of August 5, 2011, (v) CoalCo Letter of Credit Reimbursement and Collateral Agreement with Credit Suisse, dated as of August 5, 2011, (vi) Dynegy Letter of Credit Reimbursement and Collateral Agreement with Credit Suisse, dated as of August 5, 2011 and (vii) Dynegy CS Letter of Credit Agreement with Credit Suisse, dated as of October 17, 2011 (collectively, the “Terminated Facilities”).

 

On May 20, 2013, we completed a private placement of $500 million in aggregate principal amount (the “Offering”) of our 5.875% Senior Notes due 2023 (the “Notes”).  We used the proceeds of the Offering to repay the recently issued $500 million, seven-year B-1 Term Loan.  The Notes have not been registered under the Securities Act, and may not be offered or sold in the United States without registration under the Securities Act or pursuant to an applicable exemption from such registration. 

 

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Our Corporate Information

 

Our principal executive offices are located at 601 Travis, Suite 1400, Houston, Texas 77002. Our telephone number is (713) 507-6400 and we have a website accessible at www.dynegy.com. The information posted on our website is not incorporated into this prospectus and is not part of this prospectus.

 

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THE OFFERING

 

Issuer

 

Dynegy Inc.

 

 

 

Securities offered by the selling stockholder

 

32,459,817 shares of common stock including 1,533,887 shares of common stock issuable upon the exercise of the Warrants.

 

 

 

Shares of common stock outstanding after this offering

 

100,001,082 shares of common stock.

 

 

 

Use of Proceeds

 

We will not receive any proceeds from the sale of shares of the common stock by the selling stockholder. See “Use of Proceeds.”

 

 

 

Risk Factors

 

Investing in our common stock involves substantial risk. For a discussion of risks relating to Dynegy, our business and investment in our common stock, see the section titled “Risk Factors” on page 9 of this prospectus and all other information set forth in this prospectus before investing in our common stock.

 

 

 

NYSE Trading Symbol

 

DYN

 

The number of shares to be outstanding after consummation of this offering is based on 100,001,082 shares of common stock outstanding as of May 29, 2013, which does not include 15,606,936 additional shares of common stock reserved for issuance upon the exercise of the Warrants at an exercise price of $40.00 per share that expire at 5:00 p.m. New York City time on October 2, 2017, and also does not include restricted stock units or options issued under the 2012 Dynegy Inc. Long Term Incentive Plan (the “Dynegy LTIP”) regardless of whether such units or options have vested.

 

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RISK FACTORS

 

Investing in our common stock involves risks including, without limitation, those set forth below. There may be other unknown or unpredictable economic, business, competitive, regulatory or other factors that could have material adverse effects on our future results. Past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods. If any of the risks described below or in any document incorporated by reference herein actually occurs, our business, financial condition and results of operations would likely suffer. In that event, the market price of our common stock could decline and investors in our common stock could lose all or part of their investment. You should carefully consider all of the information set forth in this prospectus and the documents incorporated by reference herein and annexed hereto, and, in particular, the risk factors described in Dynegy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and in Dynegy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, filed with the SEC, which are incorporated by reference into this prospectus, with your respective legal counsel, tax and financial advisors and/or accountants prior to purchasing our common stock.

 

Risks Related to Ownership of Our Common Stock

 

The resale of shares of our common stock offered may adversely affect the market price of our common stock and substantial sales of or trading in our common stock could occur in connection with emergence from bankruptcy, which could cause our stock price to be adversely affected.

 

At the time of our emergence from bankruptcy, we granted registration rights to the selling stockholder. The shares of our outstanding common stock held by the selling stockholder are registered for resale under the registration statement of which this prospectus forms a part. The selling stockholder, as of May 29, 2013, owned approximately 32% of our outstanding common stock (which includes 1,533,887 shares of common stock issuable upon exercise of the Warrants), all of which may be sold from time to time pursuant to the registration statement of which this prospectus forms a part.

 

On October 1, 2012, the date on which all conditions to the effectiveness contemplated under the Plan were satisfied or waived (the “Plan Effective Date”), we issued an aggregate of 100,000,000 shares to holders of our Old Common Stock and our former creditors. These shares were issued pursuant to Section 1145 of the Bankruptcy Code (“Section 1145”) and are freely tradable and may be sold in the public markets immediately following our emergence from bankruptcy or thereafter from time to time, subject to certain limitations provided in Section 1145.

 

Commencing on April 1, 2013, assuming we remain current in our reporting obligations under the Securities Exchange Act of 1934, as amended (“Exchange Act”) and commencing on October 1, 2013, if we do not, these shares may be sold under Rule 144 of the Securities Act (“Rule 144”), subject in the case of holders that are affiliates, to restrictions on volume and manner of sale.

 

Some of our former creditors or other investors who received shares of our new common stock in connection with the Plan had the ability to sell and may have sold our shares shortly after emergence from bankruptcy for any number of reasons. The sale of significant amounts of our new common stock or substantial trading in our new common stock or the perception in the market that substantial trading in our new common stock will occur may adversely affect the market price of our new common stock.

 

The market price of our common stock may be volatile, which could cause the value of your investment to decline.

 

The trading price of our common stock on the NYSE may fluctuate substantially. The price of our common stock that will prevail in the market after the sale of the shares of common stock by the selling stockholder may be higher or lower than the price you have paid.

 

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Numerous factors, including many over which we have no control, may have a significant impact on the market price of our common stock. These risks include those described or referred to in this “Risk Factors” section and in the other documents incorporated herein by reference as well as, among other things:

 

·                  our operating and financial performance and prospects;

 

·                  our access to financial and capital markets to issue debt or enter into new credit facilities;

 

·                  investor perceptions of us and the industry and markets in which we operate;

 

·                  future sales of equity or equity-related securities;

 

·                  changes in earnings estimates or buy/sell recommendations by analysts; and

 

·                  general financial, domestic, economic and other market conditions.

 

Our common stock is an equity interest and therefore subordinated to our indebtedness.

 

In the event of our liquidation, dissolution or winding up, our common stock would rank below all debt claims against us. As a result, holders of our common stock will not be entitled to receive any payment or other distribution of assets upon our liquidation, dissolution or winding up until after all of our obligations to our debt holders have been satisfied.

 

Certain holders of our common stock or Warrants may be restricted in their ability to transfer or sell their securities.

 

Our common stock and Warrants issued under the Plan are exempt from registration under Section 1145(a)(1) and they may be resold by the holders thereof without registration unless the holder is an “underwriter” with respect to such securities. Resales by persons who received our common stock or Warrants pursuant to the Plan that are deemed to be “underwriters” as defined in Section 1145(b) would not be exempted by Section 1145 from registration under the Securities Act, or other applicable law. Such persons would only be permitted to sell such securities without registration if they are able to comply with the provisions of Rule 144 under the Securities Act or another applicable exemption. See “Shares Eligible for Future Sales—Common Stock and Warrants Issued in Reliance on Section 1145.” However, pursuant to the Plan, each holder of an allowed general unsecured claim that was also a holder of 10% or more of the issued and outstanding shares on the Plan Effective Date had the right to become a party to a registration rights agreement which provides such holder with customary registration rights, including a customary shelf registration, with respect to any shares of our common stock it receives under the Plan. On the Plan Effective Date, Franklin Advisers, Inc. (“FAV”) was the only such holder. See footnote 2 to “Principal Stockholders” table.

 

Certain provisions of our corporate documents could delay or prevent a change of control, even if that change would be beneficial to stockholders, or could have a material negative impact on our business.

 

Certain provisions in our third amended and restated certificate of incorporation may have the effect of deterring transactions involving a change in control of us, including transactions in which stockholders might receive a premium for their shares.

 

Our third amended and restated certificate of incorporation provides for the issuance of up to 20,000,000 shares of preferred stock with such designations, rights and preferences as may be determined from time to time by our board of directors (the “Board”). The authorization of preferred shares empowers our board of directors, without further stockholder approval, to issue preferred shares with dividend, liquidation, conversion, voting or other rights which could adversely affect the voting power or other rights of the holders of the common stock. If issued, the preferred stock could also dilute the holders of our common stock and could be used to discourage, delay or prevent a change of control of us.

 

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We do not currently anticipate paying cash dividends on our common stock in the foreseeable future.

 

We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determination to pay cash dividends will be at the discretion of our Board, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board.

 

The ownership position of Franklin Advisers, Inc. limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.

 

As of May 29, 2013, FAV had sole voting power and sole dispositive power over approximately 32% of our outstanding common stock (the “FAV stock”). As a result, it, or any entity to which FAV sells the FAV stock, may be able to exercise significant control over matters requiring stockholder approval.  Further, because of its large ownership position, if FAV sells the FAV stock, it could depress our share price.

 

Risks Related to Our Business and Industry

 

Please see “Item 1A—Risk Factors” contained in Dynegy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, and Dynegy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 which are incorporated by reference herein, for risk factors related to our business and industry.

 

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USE OF PROCEEDS

 

We will not receive any proceeds from the sale of our common stock by the selling stockholder. We will pay estimated transaction expenses of approximately $500 thousand in connection with this offering.

 

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MARKET FOR OUR COMMON STOCK

 

Our new common stock is listed on the NYSE under the symbol “DYN” and has been trading since October 3, 2012. No prior established public trading market existed for our new common stock prior to this date. The following table sets forth the per share high and low closing prices for our common stock as reported on the NYSE for the periods presented.

 

Quarter Ended

 

High

 

Low

 

2013:

 

 

 

 

 

 

 

June 30, 2013 (through May 28, 2013)

 

$

24.76

 

$

22.96

 

March 31, 2013

 

$

23.99

 

$

19.39

 

2012:

 

 

 

 

 

December 31, 2012

 

$

 19.35

 

$

17.35

 

 

The closing price of our common stock on the NYSE on May 24, 2013 was $23.95 per share.

 

As of May 29, 2013 we had approximately 2800 holders of record of our common stock, based on information provided by our transfer agent.

 

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

 

The following unaudited pro forma condensed consolidated financial information (the “Pro Forma Financial Information”) sets forth selected historical consolidated financial information for Dynegy. The historical data provided for the 2012 Predecessor and Successor periods, as defined below, and the three months ended March 31, 2013 are derived from our audited annual consolidated financial statements, and unaudited interim condensed consolidated financial statements, which have been incorporated by reference into this prospectus.

 

The unaudited pro forma condensed consolidated statements of operations are presented for the fiscal year ended December 31, 2012 and for the three months ended March 31, 2013.  The unaudited pro forma condensed consolidated balance sheet is presented as of March 31, 2013.

 

The Pro Forma Financial Information is provided for informational and illustrative purposes only and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes in Dynegy’s annual report on Form 10-K for the year ended December 31, 2012 and Dynegy’s quarterly report on Form 10-Q for the three months ended March 31, 2013, which have been incorporated by reference into this prospectus.

 

The pro forma adjustments, as described in the notes to the unaudited pro forma condensed consolidated financial statements, are based on currently available information.  Management believes such adjustments are reasonable, factually supportable and directly attributable to the following events and transactions:

 

·                  Merger, DMG Transfer, and DMG Acquisition. On September 30, 2012, pursuant to our Plan of Reorganization (“the Plan”), Dynegy Holdings, LLC (“DH”) merged with and into Dynegy, with Dynegy continuing as the surviving legal entity (the “Merger”). The accounting treatment of the Merger was reflected as a recapitalization of DH and is accounted for similar to a reverse merger; therefore, DH is our accounting Predecessor.

 

On September 1, 2011, DH sold 100 percent of the outstanding membership interests of Dynegy Coal Holdco (“Coal Holdco”) to Legacy Dynegy (the “DMG Transfer”). On June 5, 2012, in connection with the execution of a settlement agreement entered into with certain of DH’s creditors, DH reacquired Coal Holdco from Legacy Dynegy (the “DMG Acquisition”). Therefore, the results of our Coal segment are only included in our 2012 Predecessor consolidated results for the period from June 6, 2012 through October 1, 2012.

 

·                  Fresh-Start Accounting. On October 1, 2012, we consummated our reorganization under Chapter 11 pursuant to the Plan and we exited bankruptcy. Upon emergence, we applied fresh-start accounting to our consolidated financial statements.

 

Fresh-start accounting required us to allocate the reorganization value to our assets and liabilities in a manner similar to that which is required using the acquisition method of accounting for a business combination. Under the provisions of fresh-start accounting, a new entity was created for financial reporting purposes. As such, our financial information for the Successor is presented on a basis different from, and is therefore not comparable to, our financial information for the Predecessor for the period ended and as of October 1, 2012.

 

·                  AER Acquisition. On March 14, 2013, IPH, entered into a definitive agreement (the “AER Transaction Agreement”) with Ameren pursuant to which IPH will, subject to the terms and conditions in the AER Transaction Agreement, acquire from Ameren 100 percent of the equity interest of AER (or, following a pre-closing reorganization contemplated by Ameren, a

 

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successor thereto) for no cash or stock consideration. AER and its subsidiaries consist of Ameren’s merchant generation and its wholesale and retail marketing business. Pursuant to the AER Transaction Agreement, IPH will indirectly acquire AER’s subsidiaries, including (i) Genco, (ii) AERG and (iii) AEM.

 

The transaction does not include AER’s gas-fired power generation facilities: Elgin, Gibson City and Grand Tower (the “Put Assets”). Prior to signing the AER Transaction Agreement, AERG, Genco and Ameren Energy Medina Valley Cogen L.L.C. (“Medina Valley”), an affiliate of AER that IPH will not be acquiring in the transaction, entered into an amendment to a put option agreement (the “Put Option Agreement”), dated as of March 28, 2012, whereby the Put Assets will be sold by Genco, subject to approval by FERC, to Medina Valley for a minimum of $133 million (the “Put Transaction”). New appraisals will be obtained for the Put Assets prior to closing, and if the average value of the appraisals exceeds $133 million, any excess amount will be remitted to Genco. Further, in the event Ameren sells the Put Assets within two years of closing, Ameren will pay to Genco any after-tax proceeds in excess of $133 million, or the higher appraised value, if applicable. The minimum amount of $133 million is based on an average of three appraisals obtained in October 2012. The amount may increase as a result of new appraisals, but cannot be reduced.

 

In connection with the transaction, Ameren will retain certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities.  Genco’s approximately $825 million of senior notes will remain outstanding as an obligation of Genco. The debt bears interest at rates from 6.30 percent to 7.95 percent and matures between 2018 and 2032.

 

In addition, Ameren is required at closing to ensure that a minimum of $85 million of cash is available at AER and its subsidiaries, plus the proceeds of the Put Transaction described above.

 

Upon the effective date of the AER Transaction Agreement, we are required to record the assets and liabilities acquired in the AER Acquisition at their estimated fair values. We have not yet completed our analysis of the fair value of AER’s assets and liabilities given the complexities inherent in the valuation; therefore, the purchase price allocation used in the preparation of the unaudited pro forma condensed consolidated financial statements included herein should be considered preliminary.  Actual results could vary materially from the pro forma financial information. In addition, the adjustments related to the AER Acquisition do not reflect any of the synergies and cost reductions that may result from the AER Transaction Agreement.

 

In connection with the final purchase price allocation, we will perform a discounted cash flow analysis using market-quoted prices, internal forecasts, and market assumptions as of the date of acquisition.  As a result of performing this analysis, we expect that a portion of the value assigned to property, plant and equipment in these pro forma financial statements will be allocated to intangible assets and liabilities for contracts that are above or below the fair market value on the date of acquisition.  The fair values of these intangible assets and liabilities will be amortized through revenues or cost of sales over the life of the respective contract. We have not yet completed this analysis and have therefore made simplifying assumptions for purposes of preparing the unaudited pro forma financial information included herein.

 

·                  Credit Agreement. On April 23, 2013, Dynegy (the “Borrower”) entered into an approximate $1.8 billion credit agreement that consists of (i) the $500 million B-1 Term Loan, (ii) the $800 million B-2 Term Loan and (iii) the $475 million Revolving Facility (collectively, the “Credit Agreement”). The Term Facilities were offered to investors below par with an original issue discount of 99.5. The Term Facilities bear interest at LIBOR plus 3.00 percent per annum with a one percent floor. The Term Facilities mature April 23, 2020 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.00 percent of the original principal amount with the balance payable on the maturity date. The Revolving Facility bears interest, initially, at LIBOR

 

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plus 2.75 percent per annum, with steps down based on a Senior Secured Leverage Ratio (as defined in the Credit Agreement) and matures April 23, 2018.

 

Borrowings under the Credit Agreement, together with a portion of our cash on hand, were used to repay in full and terminate commitments under all of our previous credit agreements. As a result of repaying and terminating these credit agreements, all of the restricted cash on hand was released. None of the borrowings under the Credit Agreement will be classified as restricted cash.

 

The unaudited pro forma condensed consolidated financial statements are presented for informational purposes only and are not necessarily indicative of the operating results or financial position that would have occurred had the transactions described above occurred on January 1, 2012, in the case of the unaudited pro forma condensed consolidated statements of operations, or on March 31, 2013, in the case of the unaudited pro forma condensed consolidated balance sheet, nor are they necessarily indicative of future operating results or financial position.

 

Pro Forma Financial Information— Unaudited Pro Forma Condensed Consolidated Statement of Operations

 

The following Pro Forma Financial Information was prepared by applying adjustments to historical consolidated financial statements. These adjustments give effect to the Plan and fresh-start accounting, Credit Agreement and AER Transaction Agreement, reflecting our post-emergence financial statements as if the emergence date had occurred and the Credit Agreement and AER Transaction Agreement had been completed on January 1, 2012.

 

Dynegy Transactions

 

In the discussion below, we have included a discussion of the significant items resulting in adjustments included in the Dynegy Transactions column in the pro forma statement of operations:

 

·                 DMG Transfer/Merger— As discussed above, the results of our Coal segment are not included in our historical results between September 1, 2011, the date of the DMG Transfer, and June 5, 2012, the date of the DMG Acquisition. The DMG Transfer adjustments included in the unaudited pro forma condensed consolidated statements of operations remove the effects of the DMG Transfer.  Accordingly, the results of our Coal segment are included for all periods presented.

 

·                 Fresh-Start Adjustments— The fresh-start adjustments included in the unaudited pro forma condensed consolidated statements of operations adjust the effects of the fresh-start adjustments as if fresh-start accounting had been applied effective January, 1 2012, including (i) the effects of implementing the Plan; (ii) the amortization of intangible assets and liabilities that were established with the application of fresh-start accounting; and (iii) the change in depreciation expense as a result of adjusting property, plant and equipment to its estimated fair value in connection with the application of fresh-start accounting.

 

The impact of the above items and discussion of additional pro forma adjustments are included in the notes to the unaudited pro forma condensed consolidated statements of operations.

 

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DYNEGY INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

 

 

 

Three Months Ended March 31, 2013

 

 

 

Dynegy As Reported (a)

 

AER As Reported (b)

 

Dynegy Transactions

 

AER Transaction
Agreement

 

Pro Forma

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

318

 

$

297

 

$

 

$

(20

)(f)

$

595

 

Cost of sales

 

(284

)

(228

)

 

9

(g)

(503

)

Gross margin, exclusive of depreciation shown separately below

 

34

 

69

 

 

$

(11

)

92

 

Operating and maintenance expense, exclusive of depreciation shown separately below

 

(71

)

(62

)

 

10

(h)

(123

)

Depreciation and amortization expense

 

(54

)

(28

)

 

19

(i)

(63

)

Impairment and other charges

 

1

 

(207

)

 

207

(j)

1

 

General and administrative expenses

 

(22

)

 

 

(8

)(k)

(30

)

Acquisition and integration costs

 

(3

)

 

3

(c)

 

 

Operating loss

 

(115

)

(228

)

3

 

217

 

(123

)

Bankruptcy reorganization items, net

 

(1

)

 

1

(d)

 

 

Interest expense

 

(28

)

(21

)

13

(e)

7

(l)

(29

)

Other income and expense, net

 

2

 

(2

)

 

 

 

Loss from continuing operations before income taxes

 

(142

)

(251

)

17

 

224

 

(152

)

Income tax benefit

 

 

100

 

 

(100

)(m)

 

Loss from continuing operations before noncontrolling interests

 

(142

)

(151

)

17

 

124

 

(152

)

Net gain attributable to noncontrolling interest

 

 

 

 

(1

)(n)

(1

)

Loss from continuing operations

 

$

(142

)

$

(151

)

$

17

 

$

123

 

$

(153

)

 

 

 

 

 

 

 

 

 

 

 

 

Basic loss per share from continuing operations

 

$

(1.42

)

 

 

 

 

 

 

$

(1.53

)

Diluted loss per share from continuing operations

 

$

(1.42

)

 

 

 

 

 

 

$

(1.53

)

 

 

 

 

 

 

 

 

 

 

 

 

Basic shares outstanding

 

100

 

 

 

 

 

 

 

100

 

Diluted shares outstanding

 

100

 

 

 

 

 

 

 

100

 

 

See accompanying notes to the unaudited pro forma condensed consolidated financial statements

 

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DYNEGY INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

 

 

 

Twelve Months Ended December 31, 2012

 

 

 

Predecessor

 

 

Successor

 

Combined

 

 

 

 

 

 

 

 

 

 

 

January 1 Through
October 1, 2012
(As Reported) (o)

 

 

October 2 Through
December 31, 2012
(As Reported) (o)

 

Twelve Months Ended
December 31, 2012

 

AER As
Reported (p)

 

Dynegy
Transactions

 

AER Transaction
Agreement

 

Pro Forma

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

 981

 

 

$

 312

 

$

 1,293

 

$

 1,360

 

$

 161

(q)

$

(217

)(z)

$

2,597

 

Cost of sales

 

(662

)

 

(268

)

(930

)

(856

)

(164

)(r)

40

(aa)

(1,910

)

Gross margin, exclusive of depreciation shown separately below

 

319

 

 

44

 

363

 

504

 

$

(3

)

$

(177

)

687

 

Operating and maintenance expense, exclusive of depreciation shown separately below

 

(148

)

 

(81

)

(229

)

(284

)

(67

)(s)

55

(bb)

(525

)

Depreciation and amortization expense

 

(110

)

 

(45

)

(155

)

(108

)

21

(t)

82

(cc)

(160

)

Impairment and other charges

 

 

 

 

 

(698

)

 

70

(dd)

(628

)

General and administrative expenses

 

(56

)

 

(22

)

(78

)

 

(13

)(u)

(44

)(ee)

(135

)

Operating income (loss)

 

5

 

 

(104

)

(99

)

(586

)

(62

)

(14

)

(761

)

Bankruptcy reorganization items, net

 

1,037

 

 

(3

)

1,034

 

 

(1,034

)(d)

 

 

Earnings from unconsolidated investments

 

 

 

2

 

2

 

 

 

 

2

 

Interest expense

 

(120

)

 

(16

)

(136

)

(95

)

28

(v)

29

(l)

(174

)

Impairment of Undertaking receivable, affiliate

 

(832

)

 

 

(832

)

 

832

(w)

 

 

Other income and expense, net

 

31

 

 

8

 

39

 

 

(24

)(x)

 

15

 

Income (loss) from continuing operations before income taxes

 

121

 

 

(113

)

8

 

(681

)

(260

)

15

 

(918

)

Income tax benefit

 

9

 

 

 

9

 

278

 

(y)

(278

)(m)

9

 

Income (loss) from continuing operations before noncontrolling interests

 

130

 

 

(113

)

17

 

(403

)

(260

)

(263

)

(909

)

Net (gain) loss attributable to noncontrolling interest

 

 

 

 

 

7

 

 

(3

)(n)

4

 

Income (loss) from continuing operations

 

$

130

 

 

$

(113

)

$

17

 

$

(396

)

$

(260

)

$

(266

)

$

(905

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic loss per share from continuing operations

 

 

 

 

$

(1.13

)

 

 

 

 

 

 

 

 

$

(9.05

)

Diluted loss per share from continuing operations

 

 

 

 

$

(1.13

)

 

 

 

 

 

 

 

 

$

(9.05

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic shares outstanding

 

 

 

 

100

 

 

 

 

 

 

 

 

 

100

 

Diluted shares outstanding

 

 

 

 

100

 

 

 

 

 

 

 

 

 

100

 

 

See accompanying notes to the unaudited pro forma condensed consolidated financial statements

 

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NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

(a)         Represents our unaudited consolidated statement of operations for the period indicated as reported in the Dynegy Form 10-Q for the period ended March 31, 2013, as filed with the SEC on May 2, 2013 and incorporated by reference herein.

 

(b)         Represents AER’s unaudited consolidated statement of operations for the period ended March 31, 2013 as included at Annex A to this prospectus.  Certain reclassifications have been made to the historical presentation in order to conform to Dynegy’s presentation.

 

(c)          Represents the removal of $3 million of Dynegy’s Acquisition and integration costs due to the AER Transaction Agreement.

 

(d)         Removes Dynegy’s Bankruptcy reorganization items, net incurred during the period presented.

 

(e)          Represents the adjustment to eliminate all historical interest expense associated with the DMG and DPC credit agreements that were repaid in connection with the execution of the Credit Agreement and record interest expense associated with the Credit Agreement.

 

(f)           The decrease in Revenues is comprised of the following:

 

·                  $9 million of revenues associated with the Put Assets as these assets will not be acquired by Dynegy;

·                  $11 million due to the elimination of AER’s cash flow hedge accounting, as Dynegy will not elect to designate qualifying derivative instruments as cash flow hedges.  Eliminating cash flow hedge accounting results in the changes in the value of derivatives being recorded through revenue instead of through accumulated other comprehensive income.

 

(g)          Removes the $9 million in Cost of sales associated with the Put Assets as they will not be acquired by Dynegy.

 

(h)         Represents the adjustment to reflect:

 

·                  The reclassification of $8 million of allocated corporate costs to General and administrative expenses to conform to Dynegy’s policy.  AER classifies allocated corporate costs as Operating and maintenance expenses and Dynegy classifies these costs as General and administrative expenses;

·                  The removal of $2 million in Operating and maintenance expense associated with the Put Assets as they will not be acquired by Dynegy.

 

(i)             Represents the adjustment to reflect:

 

·                  The effect of the purchase accounting adjustments, which decreased depreciation expense by $15 million due to the $1.806 billion reduction of property, plant and equipment with a useful life of approximately 30 years (as discussed in note (i) to the unaudited pro forma condensed consolidated balance sheet included herein); and

·                  The elimination of $4 million of depreciation expense related to the Put Assets as they will not be acquired by Dynegy.

 

(j)            Reflects adjustment to eliminate $207 million in impairment charges recognized by AER as the impairment relates to the Put Assets which are not being acquired by Dynegy.

 

(k)         Reflects the reclassification of $8 million of allocated corporate costs as discussed in (h) above.

 

(l)             Represents the adjustment to interest expense to eliminate interest associated with intercompany notes and money pool borrowings as these will be settled prior to closing the AER Transaction, partially offset by the impact of adjusting AER’s $825 million in senior notes to their estimated fair value of $629 million as of March 31, 2013, resulting in increased amortization of the discount through interest expense.

 

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(m)     Eliminates the tax benefit recorded by Ameren.  Dynegy’s net deferred tax assets are fully valued.  For purposes of the unaudited pro forma condensed consolidated statements of operations, Dynegy has assumed any change in deferred tax assets or liabilities will be equally offset by a change in its valuation allowance.

 

(n)         Represents the impact to Net gain (loss) attributable to non-controlling interest for pro forma adjustments related to depreciation expense for EEI’s property, plant and equipment.

 

(o)         Represents our consolidated statement of operations for the period indicated as reported in the Dynegy Form 10-K for the period ended December 31, 2012, as filed with the SEC on March 14, 2013 and incorporated by reference herein.

 

(p)         Represents AER’s audited consolidated statement of operations for the year ended December 31, 2012 as included at Annex A to this prospectus. Certain reclassifications have been made to the historical presentation in order to conform to Dynegy’s presentation.

 

(q)         Represents the effect of the DMG Transfer, which increased Revenues by $230 million, partially offset by a decrease in Revenues of $69 million due to the amortization of intangible assets and liabilities related to capacity contracts, energy contracts and tolling agreements as a result of the application of fresh-start accounting.

 

(r)            Represents (i) the effect of the DMG Transfer, which increased Cost of sales by $132 million, and (ii) the effect of fresh-start adjustments, which increased Cost of sales by $32 million due to the amortization of intangible assets and liabilities related to coal and transportation contracts.

 

(s)           Represents the effect of the DMG Transfer, which increased Operating and maintenance expense by $69 million, partially offset by $2 million in fresh-start adjustments due to the elimination of other postretirement employee benefit and pension expense.

 

(t)            Represents a $99 million decrease in depreciation expense due to a reduction in the value of property, plant and equipment as a result of the application of fresh-start accounting partially offset by a $78 million increase in depreciation expense to include the effect of the DMG Transfer.

 

(u)         Represents the effect of the DMG Transfer, which increased General and administrative expenses by $14 million partially offset by a decrease of $1 million due to the elimination of other postretirement employee benefit and pension expense as a result of the application of fresh-start accounting.

 

(v)         Represents the adjustment to eliminate all historical interest expense associated with the terminated DMG and DPC credit agreements and estimated interest expense associated with the Credit Agreement.  After considering these adjustments, interest expense is comprised of (i) $28 million in mark-to-market changes related to interest rate swaps, (ii) $59 million of interest expense related to the Credit Agreement, and (iii) $21 million related to interest incurred on the $325 million of debt repaid in November 2012, as this debt was not repaid in connection with the execution of the Credit Agreement.

 

(w)       In connection with the DMG Acquisition, Dynegy recorded an impairment of the Undertaking receivable, affiliate that was established in connection with the DMG Transfer.  As the pro forma statement of operations assumes the DMG Transfer never occurred, the impairment of the Undertaking receivable, affiliate has been eliminated.

 

(x)         Removes the interest income associated with the Undertaking receivable, affiliate.

 

(y)         Dynegy’s net deferred tax assets were fully reserved as of December 31, 2012. Therefore, there is no tax impact related to the pro forma adjustments as we have assumed any changes to net deferred taxes would be offset by changes in the valuation allowance.

 

(z)         The decrease in revenues is comprised of the following:

 

·                  $58 million of Revenues associated with the Put Assets as these assets will not be acquired by Dynegy;

·                  $159 million due to the elimination of AER’s cash flow hedge accounting, as Dynegy does not plan to elect to designate qualifying derivative instruments as cash flow hedges.  Eliminating cash flow hedge accounting results in the changes in the value of the derivatives being recorded through Revenue instead of through Accumulated other comprehensive income.

 

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(aa)  Removes the $40 million in Cost of sales associated with the Put Assets as they will not be acquired by Dynegy.

 

(bb)  Represents the adjustment to reflect:

 

·                  The reclassification of $44 million of allocated corporate costs to conform to Dynegy’s policy.  AER classifies allocated corporate costs as Operating and maintenance expense and Dynegy classifies these costs as General and administrative expenses.

·                  The removal of $9 million in Operating and maintenance expense associated with the Put Assets as they will not be acquired by Dynegy; and

·                  The removal of $2 million in Operating and maintenance expense associated with accretion expense for the asset retirement obligations of the Hutsonville and Meredosia plants being retained by Ameren.

 

(cc)    Represents the adjustment to reflect:

 

·                  The effect of the purchase accounting adjustments, which decreased depreciation expense by $61 million due to the $1.806 billion reduction of property, plant and equipment (as discussed in note (i) to the unaudited pro forma condensed consolidated balance sheet included herein); and

·                  The elimination of $21 million in depreciation expense related to the Put Assets as they will not be acquired by Dynegy.

 

(dd)  Represents the elimination of the asset impairment charge related to the Put Assets.

 

(ee)    Reflects the reclassification of $44 million of allocated corporate costs as discussed in (bb) above.

 

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Pro Forma Financial Information— Unaudited Pro Forma Condensed Consolidated Balance Sheet

 

The pro forma unaudited condensed consolidated balance sheet was prepared by applying adjustments to historical consolidated financial statements. These adjustments give effect to the Credit Agreement and the AER Transaction Agreement as if the Credit Agreement and AER Transaction Agreement had been completed on March 31, 2013.  The impact of each of these adjustments is more fully described within the notes to the unaudited pro forma condensed consolidated balance sheet.

 

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DYNEGY INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

 

 

 

As of March 31, 2013

 

 

 

As Reported (a)

 

AER 
As Reported (b)

 

Credit 
Agreement (c)

 

AER Transaction
Agreement

 

Pro Forma

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

304

 

$

25

 

$

193

 

$

193

(d)

$

715

 

Restricted cash and investments

 

98

 

 

(98

)

 

 

Accounts receivable, net

 

87

 

102

 

 

 

189

 

Accounts receivable, affiliates

 

1

 

18

 

 

(18

)(e)

1

 

Advances to money pool

 

 

154

 

 

(154

)(e)

 

Inventory

 

93

 

112

 

 

2

(f)

207

 

Assets from risk-management activities

 

36

 

82

 

 

(66

)(g)

52

 

Assets from risk-management activities, affiliates

 

3

 

 

 

 

3

 

Broker margin account

 

34

 

 

 

 

34

 

Intangible assets

 

223

 

 

 

 

223

 

Prepayments and other current assets

 

77

 

17

 

5

 

(2

)(f)

97

 

Current assets held for sale

 

 

166

 

 

(166

)(h)

 

Total current assets

 

956

 

676

 

100

 

(211

)

1,521

 

Property, plant and equipment, net

 

2,988

 

2,270

 

 

(1,806

)(i)

3,452

 

Restricted cash and investments

 

224

 

 

(224

)

 

 

Assets from risk-management activities

 

1

 

 

 

8

(j)

9

 

Intangible assets

 

51

 

 

 

 

51

 

Deferred income taxes

 

95

 

 

 

 

95

 

Other long-term assets

 

67

 

85

 

23

 

(33

)(j)

142

 

Total assets

 

$

4,382

 

$

3,031

 

$

(101

)

$

(2,042

)

$

5,270

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

 

$

95

 

$

76

 

$

 

$

69

(e)

$

240

 

Accounts payable, affiliates

 

1

 

32

 

 

(32

)(e)

1

 

Borrowings from money pool

 

 

296

 

 

(296

)(e)

 

Deposit received from affiliate for pending asset sale

 

 

100

 

 

(100

)(e)

 

Accrued interest

 

1

 

 

 

 

1

 

Accrued liabilities and other current liabilities

 

75

 

96

 

 

(38

)(k)

133

 

Liabilities from risk-management activities

 

73

 

66

 

 

(66

)(g)

73

 

Deferred income taxes

 

95

 

 

 

 

95

 

Current portion of long-term debt

 

29

 

 

(17

)

 

12

 

Current liabilities held for sale

 

 

33

 

 

(33

)(h)

 

Total current liabilities

 

369

 

699

 

(17

)

(496

)

555

 

Notes payable, affiliates

 

 

425

 

 

(425

)(e)

 

Taxes payable, affiliates

 

 

38

 

 

(38

)(l)

 

Long-term debt

 

1,353

 

824

 

(72

)

(195

)(m)

1,910

 

Liabilities from risk-management activities

 

43

 

 

 

4

(n)

47

 

Deferred income taxes

 

 

217

 

 

(217

)(o)

 

Other long-term liabilities

 

254

 

185

 

 

(32

)(p)

407

 

Total liabilities

 

2,019

 

2,388

 

(89

)

(1,399

)

2,919

 

 

 

 

 

 

 

 

 

 

 

 

 

Total stockholders’ equity

 

2,363

 

643

 

(12

)

(643

)(q)

2,351

 

Total liabilities and stockholders’ equity

 

$

4,382

 

$

3,031

 

$

(101

)

$

(2,042

)

$

5,270

 

 

See accompanying notes to the unaudited pro forma condensed consolidated financial statements

 

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NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

 

(a)         Represents our unaudited condensed consolidated balance sheet as reported in our Form 10-Q for the period ended March 31, 2013, as filed with the SEC on May 2, 2013 and incorporated by reference herein.

 

(b)         Represents AER’s unaudited consolidated balance sheet for the period ended March 31, 2013, as included at Annex A to this prospectus. Certain reclassifications have been made to the historical presentation in order to conform to Dynegy’s presentation.

 

(c)          Represents the net balance sheet effect of the establishment of the Credit Agreement, including:

 

·                  The payment of $129 million in cash, which represents the cash on hand used to terminate Dynegy’s existing credit agreements and execute the Credit Agreement, including the prepayment penalty and debt issuance costs associated with the new Credit Agreement;

·                  The reclassification of $98 million of short-term and $224 million of long-term restricted cash to unrestricted cash;

·                  Approximately $28 million of debt issuance costs, of which $5 million is expected to be amortized to interest expense within 12 months; and

·                  A reduction in the carrying value of long-term debt to reflect the impact of removing the carrying value of the DMG and DPC credit agreements offset by the issuance of the $1.3 billion principal amount of the Term Facilities at an original issue discount of 99.5.

 

(d)         Adjusts the cash acquired in the AER Transaction to the minimum amount required in accordance with the terms of the Transaction Agreement.

 

(e)          Represents the adjustment to reflect the elimination of all intercompany agreements and debt between AER, on the one hand, and Ameren and its affiliates, on the other hand, with the exception of certain agreements, such as supply obligations to Ameren Illinois Company, and a note from AER to Ameren relating to cash collateral that will remain outstanding at closing.  The adjustment also assumes the Genco money pool advance of $154 million will be cash-settled prior to Dynegy’s acquisition of AER.  Of the surviving amounts, $69 million is included in Accounts payable and $31 million is included in Other long-term liabilities as discussed in (p) below.

 

(f)           Represents the adjustments to reflect the impact of conforming AER’s and Dynegy’s policy for the accounting of emissions credits. Dynegy classifies emissions credits as inventory and AER classifies them as intangible assets, which is included in Prepayments and other current assets.  The adjustment reflects a reclassification of $2 million related to emissions credits into Inventory.

 

(g)          Represents the impact to conform the financial statement presentation of derivatives, reducing the balance by $66 million. AER presents its derivatives on a gross basis, while Dynegy presents its derivatives on a net basis.

 

(h)         Represents the adjustment to reflect the completion of the sale of the Put Assets.

 

(i)            Represents the adjustments to reflect the reduction in fair value of the plant assets by $1.806 billion to effect the acquisition of net zero assets.

 

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(j)            Represents adjustments to reflect:

 

·                  A $28 million reduction to conform the financial statement presentation of derivative assets and liabilities. AER presents its derivatives on a gross basis and classifies its long-term derivative assets within Other long-term assets while Dynegy presents its derivatives on a net basis and classifies its long-term derivative assets within Assets from risk management activities.  The adjustment increased Assets from risk-management activities and decreased Other long-term assets by $28 million.  The adjustment to Assets from risk management activities was partially offset by $20 million to present derivatives on a net basis.

·                  The elimination of $5 million of unamortized debt issuance costs.

 

(k)         Represents the adjustments to reflect the removal of assets and liabilities not being acquired by Dynegy, which decreased Accrued liabilities and other current liabilities by $6 million due to the elimination of the current portion of AER’s Genco tax payable to Ameren Illinois Company and $32 million related to the elimination of current deferred tax liabilities. See discussion regarding deferred taxes at (o) below.

 

(l)             Represents the adjustment to remove Genco’s tax payable to Ameren Illinois Company, which will be eliminated upon consummation of the AER Transaction.

 

(m)     Represents the amount required to adjust Genco’s $825 million of senior notes to their March 31, 2013 estimated fair value of $629 million.

 

(n)         The adjustment conforms the financial statement presentation of derivative assets and liabilities as discussed in (j) above.  The adjustment includes an increase of $24 million due to reclassifying risk management liabilities out of Other long-term liabilities, partially offset by $20 million to present derivatives on a net basis.

 

(o)         Eliminates the deferred taxes recorded by Ameren. Dynegy’s net deferred tax assets are fully valued.  For purposes of this unaudited pro forma condensed consolidated balance sheet, Dynegy has assumed any change in deferred tax assets or liabilities will be equally offset by a change in its valuation allowance.

 

(p)         Represents the adjustment to reflect:

 

·                  The removal of the $27 million of asset retirement obligations for the Hutsonville and Meredosia plants that will be retained by Ameren;

·                  The elimination of $12 million related to uncertain tax position liabilities, which will be retained by Ameren; and

·                  A $24 million reclassification of AER’s derivative liabilities to Liabilities from risk management activities to conform to Dynegy’s financial statement presentation as discussed in (j) and (n) above; and

·                  An increase of $31 million related to a note payable to be issued to Ameren at closing related to collateral support they are required to provide for the two-year period following the closing of the AER Transaction.

 

(q)         Represents the elimination of AER’s historical equity balances.

 

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DIVIDEND POLICY

 

We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determination to pay cash dividends will be at the discretion of our Board, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board.

 

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MANAGEMENT

 

Board of Directors

 

Set forth below are the name, age, position and a description of the business experience and certain other past and present directorships of each of our directors as of May 29, 2013.

 

Director

 

Position(s)

 

Age as of May 29,
2013

 

Served with
Dynegy Since

Pat Wood III

 

Chairman

 

50

 

2012

Robert C. Flexon

 

Director, President and Chief Executive Officer

 

54

 

2011

Hilary E. Ackermann

 

Director

 

57

 

2012

Paul M. Barbas

 

Director

 

56

 

2012

Richard Lee Kuersteiner

 

Director

 

74

 

2012

Jeffrey S. Stein

 

Director

 

43

 

2012

John R. Sult

 

Director

 

53

 

2012

 

Pat Wood III became a member of our Board on October 1, 2012.  Mr. Wood is serving as the Board’s non-executive Chairman and has served as a principal of Wood3 Resources, an energy infrastructure developer, since July 2005. From 2001 until July 2005, Mr. Wood served as chairman of the Federal Energy Regulatory Commission.  From 1995 until 2001, he chaired the Public Utility Commission of Texas. Prior to 1995, Mr. Wood was an attorney with Baker & Botts, a global law firm, and an associate project engineer with Arco Indonesia, an oil and gas company, in Jakarta. Mr. Wood currently also serves on the boards of directors of Quanta Services Inc. and SunPower Corp.

 

Robert C. Flexon has served as the Company’s President and Chief Executive Officer since July 2011 and a director of the Company since June 2011. Prior to joining the Company, Mr. Flexon served as the Chief Financial Officer of UGI Corporation, a distributor and marketer of energy products and related services from February 2011 to July 2011. Mr. Flexon was the Chief Executive Officer of Foster Wheeler AG from June 2010 until October 2010 and the President and Chief Executive Officer of Foster Wheeler USA from November 2009 until May 2010. Prior to joining Foster Wheeler, Mr. Flexon was Executive Vice President and Chief Financial Officer of NRG Energy, Inc. from February 2009 until November 2009. Mr. Flexon previously served as Executive Vice President and Chief Operating Officer of NRG Energy from March 2008 until February 2009 and as its Executive Vice President and Chief Financial Officer from 2004 to March 2008. Prior to joining NRG Energy, Mr. Flexon held executive positions with Hercules, Inc. and various key positions, including General Auditor, with Atlantic Richfield Company. Mr. Flexon served on the board of directors of Foster Wheeler from 2006 until 2009 and from May 2010 until October 2010.

 

Hilary E. Ackermann became a member of our Board on October 1, 2012.  Ms. Ackermann was Chief Risk Officer with Goldman Sachs Bank USA from October 2008 to 2011. In this role, she managed Credit, Market and Operational Risk for Goldman Sach’s commercial bank; developed the bank’s risk management infrastructure including policies and procedures and processes; maintained ongoing relationship with bank regulators including New York Fed, NY State Banking Department and the FDIC; chaired Operational risk, Credit risk and Middle Market Loan Committees; served as Vice Chair of Bank Risk Committee; was a member of Community Investment, Business Standards and New Activities Committees; was a member of GS Group level Credit Policy and Capital Committees; and chaired GS Group level Operational Risk Committee. Ms. Ackermann served as Managing Director, Credit Department of Goldman, Sachs & Co. from January 2002 until October 2008, as VP, Credit Department from 1989 to 2001, and as an Associate in the Credit Department from 1985 to 1988. Prior to joining Goldman, Sachs, Ms. Ackermann served as Assistant Department Head of Swiss Bank Corporation from 1981 until 1985.

 

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Paul M. Barbas became a member of our Board on October 1, 2012.  Prior to joining the Company, Mr. Barbas was President and Chief Executive Officer of DPL Inc. and its principal subsidiary, The Dayton Power and Light Company (DP&L), from October 2006 until December 2011. He also served on the board of directors of DPL Inc. and DP&L. He previously served as Executive Vice President and Chief Operating Officer of Chesapeake Utilities Corporation, a diversified utility company engaged in natural gas distribution, transmission and marketing, propane gas distribution and wholesale marketing and other related services from 2005 until October 2006, as Executive Vice President from 2004 until 2005, and as President of Chesapeake Service Company and Vice President of Chesapeake Utilities Corporation, from 2003 until 2004. From 2001 until 2003, he was Executive Vice President of Allegheny Power, responsible for the operational and strategic functions of a $2.7 billion company serving 1.6 million customers with 3,200 employees. He joined Allegheny Energy in 1999 as President of its Ventures unit.

 

Richard Lee Kuersteiner became a member of our Board on October 1, 2012.  Mr. Kuersteiner was a member of the Franklin Templeton Investments legal department in San Mateo, California from 1990 until May 2012. Mr. Kuersteiner has a strong interest in good corporate governance practices and is a long-standing member of the Stanford Institutional Investors Forum. At Franklin he served in various capacities including as Associate General Counsel and Director of Restructuring and Managing Corporate Counsel. For many years he also was an officer of virtually all of the Franklin, Templeton and Mutual Series funds. In February 2010 when R H Donnelley Corporation emerged from Chapter 11 bankruptcy as Dex One Corporation, he joined its board of directors and is currently a member of the Audit and Finance Committee, the Compensation and Benefits Committee and Chair of the Corporate Governance Committee. Additionally, Mr. Kuersteiner is a director of each of the nine wholly-owned Dex One subsidiaries.

 

Jeffrey S. Stein became a member of our Board on October 1, 2012.  Mr. Stein is a Co-Founder and Managing Partner of Power Capital Partners LLC a private equity firm founded in January 2011. Mr. Stein is an investment professional with over 19 years of experience in the high yield, distressed debt and special situations asset class who has substantial experience investing in the merchant power and regulated electric utility industries. He has invested in numerous power companies representing a broad array of power plants diversified by fuel source, position on the dispatch curve, geographic location and technology. In addition, Mr. Stein has been actively involved in the hedging, refinancing, restructuring and sale of various power assets. Previously Mr. Stein was a Co-Founder and Principal of Durham Asset Management LLC, a global event-driven distressed debt and special situations asset management firm. From January 2003 through December 2009, Mr. Stein served as the Co-Director of Research at Durham responsible for the identification, evaluation and management of investments for the various Durham portfolios. From July 1997 to December 2002, Mr. Stein was a Director at The Delaware Bay Company, Inc. From September 1991 to August 1995, Mr. Stein was an Associate at Shearson Lehman Brothers in the Capital Preservation & Restructuring Group. Mr. Stein currently serves on the boards of Directors of Granite Ridge Holdings, LLC, and US Power Generating Company. Mr. Stein previously served as a member of the board of directors of KGen Power Corporation.

 

John R. Sult became a member of our Board on October 1, 2012.  Mr. Sult was Executive Vice President and Chief Financial Officer of El Paso Corporation from March 2010 until May 2012. He previously served as Senior Vice President and Chief Financial Officer from November 2009 until March 2010, and as Senior Vice President and Controller from November 2005 until November 2009. Mr. Sult served as Executive Vice President and Chief Financial Officer and director of El Paso Pipeline GP Company, L.L.C. from July 2010 until May 2012, as Senior Vice President and Chief Financial Officer from November 2009 until July 2010, and as Senior Vice President, Chief Financial Officer and Controller from August 2007 until November 2009. Mr. Sult also served as Chief Accounting Officer of El Paso Corporation and as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Prior to joining El Paso, Mr. Sult served as Vice President and Controller of Halliburton Energy Services from August 2004 until October 2005. Prior to joining Halliburton, Mr. Sult managed an independent consulting practice that provided a broad range of finance and accounting advisory services and assistance to public companies in the energy industry. Prior to private practice, Mr. Sult was an audit partner with Arthur Andersen

 

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LLP where he gained over 20 years of experience working with public and private companies in the energy industry. Mr. Sult currently serves on the private board of directors of Melior Technology Inc.

 

Executive Officers

 

The following table sets forth the name and positions of our executive officers as of May 29, 2013, together with their ages and period of service with us.

 

Executive Officer

 

Position

 

Age as of
May 29,
2013

 

Served with 
Dynegy 
Since

Robert C. Flexon

 

President and Chief Executive Officer

 

54

 

2011

Clint C. Freeland

 

Executive Vice President and Chief Financial Officer

 

44

 

2011

Carolyn J. Burke

 

Executive Vice President and Chief Administrative Officer

 

45

 

2011

Catherine B. Callaway

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

47

 

2011

Henry D. Jones

 

Executive Vice President and Chief Commercial Officer

 

53

 

2013

Mario E. Alonso

 

Vice President, Strategic Development

 

42

 

2001

 

The executive officers named above will serve in such capacities until the next annual meeting of our Board, or until their respective successors have been duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office.

 

Robert C. Flexon has served as our President and Chief Executive Officer since July 2011 and a director of Dynegy since June 2011. Prior to joining Dynegy, Mr. Flexon served as the Chief Financial Officer of UGI Corporation, a distributor and marketer of energy products and related services since February 2011. Mr. Flexon was the Chief Executive Officer of Foster Wheeler AG from June 2010 until October 2010 and the President and Chief Executive Officer of Foster Wheeler USA from November 2009 until May 2010. Prior to joining Foster Wheeler, Mr. Flexon was Executive Vice President and Chief Financial Officer of NRG Energy, Inc. from February 2009 until November 2009. Mr. Flexon previously served as Executive Vice President and Chief Operating Officer of NRG Energy from March 2008 until February 2009 and as its Executive Vice President and Chief Financial Officer from 2004 to 2008. Prior to joining NRG Energy, Mr. Flexon held executive positions with Hercules, Inc. and various key positions, including General Auditor, with Atlantic Richfield Company. Mr. Flexon served on the board of directors of Foster Wheeler from 2006 until 2009 and from May 2010 until October 2010.

 

Clint C. Freeland has served as our Executive Vice President and Chief Financial Officer since July 2011. Mr. Freeland is responsible for our financial affairs, including finance and accounting, treasury, tax and banking and credit agency relationships. Prior to joining Dynegy, Mr. Freeland served as Senior Vice President, Strategy & Financial Structure of NRG Energy since February 2009. Mr. Freeland served as NRG Energy’s Senior Vice President and Chief Financial Officer from February 2008 to February 2009 and its Vice President

 

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and Treasurer from April 2006 to February 2008. Prior to joining NRG, Mr. Freeland held various key financial roles within the energy sector.

 

Carolyn J. Burke has served as our Executive Vice President and Chief Administrative Officer since August 2011. Ms. Burke is responsible for managing key corporate functions including Information Technology, Human Resources, Investor Relations and communications. In addition, Ms. Burke oversees our cost savings initiative known as “PRIDE.” Prior to joining Dynegy, Ms. Burke served as Global Controller for J.P. Morgan’s Global Commodities business since March 2008. Ms. Burke served as NRG Energy’s Vice President and Corporate Controller from September 2006 to March 2008 and its Executive Director of Planning and Analysis from April 2004 to September 2006. Prior to joining NRG, Ms. Burke held various key financial roles at Yale University, the University of Pennsylvania and at Atlantic Richfield Company (now British Petroleum).

 

Catherine B. Callaway has served as our Executive Vice President and General Counsel since September 2011 and Chief Compliance Officer since June 2012. Ms. Callaway is responsible for managing all legal affairs, including legal services supporting Dynegy’s operational, commercial and corporate areas, as well as ethics and compliance. Prior to joining Dynegy, Ms. Callaway served as General Counsel for NRG Gulf Coast and Reliant Energy since August 2011. Ms. Callaway served as General Counsel for NRG Texas and Reliant Energy from August 2010 to August 2011 and as General Counsel for NRG Texas from November 2007 to August 2010. Prior to joining NRG, Ms. Callaway held various key legal roles at Calpine Corporation, Reliant Energy, The Coastal Corporation and Chevron.

 

Henry D. Jones began serving as our Executive Vice President and Chief Commercial Officer on April 1, 2013.  Mr. Jones is responsible for Dynegy’s commercial and asset management functions for its power generation business.  In addition, Mr. Jones leads a team that develops and executes both hedging and term contracting options for the entire fleet. He reports to Robert C. Flexon, Dynegy’s President and Chief Executive Officer, and serves on the executive management team.  Prior to joining Dynegy, Mr. Jones served as Managing Director, North American Power and Gas Sales, and Origination at Deutsche Bank since May 2010, and managed Deutsche Bank’s North American Power and Gas trading activity since August 2012. Prior to joining Deutsche Bank, Mr. Jones was the Chief Operating Officer and Head of Trading at EDF Trading North America from August 2009 to February 2010, Head of Electricity Trading at EDF Trading Markets Limited from August 2008 to July 2009, and Director of Renewable Fuels Trading from July 2007 to July 2008.

 

Mario E. Alonso has served as our Vice President, Strategic Development since June 2012 and is a member of Dynegy’s Executive Management Team.  Mr. Alonso is responsible for leading the Company’s strategic planning and corporate development activities.  Mr. Alonso most recently served as Vice President and Treasurer from July 2011 to June 2012.  He previously served as Vice President—Strategic Planning from December 2008 to July 2011 and as Managing Director—Strategic Planning from June 2007 to December 2008.  Prior to June 2007, Mr. Alonso served in various roles within the Company’s Strategic Planning and Treasury Departments.  Prior to joining Dynegy in 2001, Mr. Alonso was with Enron Corporation commencing in 1999.

 

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Table of Contents

 

PRINCIPAL STOCKHOLDERS

 

The following table sets forth information as of May 29, 2013 regarding the beneficial ownership of our common stock by:

 

·   each of our directors;

·   each of our named executive officers;

·   each holder of more than 5% of our outstanding shares of common stock; and

·   all of our directors and executive officers as a group.

 

Beneficial ownership for the purposes of this table is determined in accordance with the rules and regulations of the SEC. These rules generally provide that a person is the beneficial owner of securities if such person has or shares the power to vote or direct the voting thereof, or to dispose or direct the disposition thereof or has the right to acquire such powers within 60 days. Common stock subject to options and warrants that are currently exercisable or exercisable within 60 days of May 29, 2013 is deemed to be outstanding and beneficially owned by the person holding the options or warrants and common stock issuable upon vesting of restricted stock units that are vested or will vest within 60 days of May 29, 2013 is deemed to be outstanding and beneficially owned by the person holding the restricted stock units. These shares, however, are not deemed outstanding for the purposes of computing the percentage ownership of any other person. Percentage of beneficial ownership is based on 100,001,082 shares of common stock outstanding as of May 29, 2013. This reflects the shares issued on October 1, 2012 pursuant to the Plan. Except as disclosed in the footnotes to this table, we believe that each stockholder identified in the table possesses sole voting and investment power over all shares of common stock shown as beneficially owned by the stockholder.

 

All percentages and share amounts are approximate based on current information available to us. The information available to us may be incomplete.

 

Unless otherwise noted, the address for each person listed on the table is c/o Dynegy Inc., 601 Travis, Suite 1400, Houston, Texas 77002. The address for Franklin Advisers, Inc. is One Franklin Parkway,  San Mateo, California  94403.

 

 

 

Amount and Nature of Shares Beneficially Owned (1)

 

Name

 

Number

 

Percent of Class

 

5% Stockholders

 

 

 

 

 

Franklin Advisers, Inc. (2) 

 

32,459,817

 

32.0

%

Luminus Management, LLC

 

9,720,083

 

9.7

%

Geveran Investments Limited

 

7,330,571

 

7.3

%

Oaktree Capital Management, LP

 

7,224,407

 

7.2

%

JPMorgan Chase & Co.

 

5,100,060

 

5.1

%

 

 

 

 

 

 

Executive Officers and Directors

 

 

 

 

 

Robert C. Flexon (3) 

 

18,679

 

*

 

Clint C. Freeland (4) 

 

3,873

 

*

 

Catherine B. Callaway (5) 

 

1,232

 

*

 

Carolyn J. Burke (6) 

 

1,081

 

*

 

Mario E. Alonso (7) 

 

448

 

*

 

Henry D. Jones (8)

 

5

 

*

 

Pat Wood, III (9)

 

24,087

 

*

 

Hilary E. Ackermann (10)

 

8,050

 

*

 

Paul M. Barbas (11)

 

8,050

 

*

 

Richard Lee Kuersteiner (12)

 

11,979

 

*

 

John R. Sult (13)

 

8,050

 

*

 

Jeffrey S. Stein (14)

 

8,050

 

*

 

 

 

 

 

 

 

All executive officers and directors as a group (12 persons) (**)

 

92,155

 

*

 

 

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*    Less than 1%.

 

(1)         Shares shown in the table above include shares held in the beneficial owner’s name or jointly with others, or in the name of a bank, nominee or trustee for the beneficial owner’s account.

 

(2)         These shares include 1,533,887 shares issuable on the exercise of the Warrants. Notwithstanding the foregoing, a holder may not exercise any Warrant if it would cause such holder’s beneficial ownership of our common stock and any other of our equity securities on parity (with respect to dividends) with such common stock (when aggregated with that of any of the holder’s affiliates) to require the prior permission (including the expiration of applicable waiting periods) of any governmental or regulatory authority applicable to us, unless we and such holder have made all filings and registrations with, and obtained such permission (including the expiration of any such waiting periods) from, any such governmental and regulatory authorities, as are necessary or advisable.

 

FAV, an indirectly wholly owned subsidiary of Franklin Resources, Inc. (“FRI”), is deemed to be the beneficial owner of these shares for purposes of Rule 13d-3 under the Exchange Act in its capacity as the investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940 and other accounts.  When an investment management contract (including a sub-advisory agreement) delegates to FAV investment discretion or voting power over the securities held in the investment advisory accounts that are subject to that agreement, FRI treats FAV as having sole investment discretion or voting authority, as the case may be, unless the agreement specifies otherwise. Accordingly, FAV reports for purposes of section 13(d) of the Exchange Act that it has sole investment discretion and voting authority over the securities covered by any such investment management agreement, unless otherwise specifically noted.

 

(3)         Includes 5,337 shares issuable upon the exercise of the Warrants. As of May 29, 2013, Mr.Flexon also holds 105,281 restricted stock units and 273,059 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on October 31, 2013. Mr. Flexon also holds 64,936 restricted stock units and 101,352 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on March 18, 2014.

 

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(4)         Includes 1,055 shares issuable on the exercise of the Warrants. As of May 29, 2013, Mr. Freeland also holds 27,073 restricted stock units and 70,215 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on October 31, 2013. Mr. Freeland also holds 21,646 restricted stock units and 33,784 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on March 18, 2014.

 

(5)         Includes 1,158 shares issuable on the exercise of the Warrants. As of May 29, 2013, Ms. Callaway also holds 27,073 restricted stock units, and 70,215 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on October 31, 2013. Ms. Callaway also holds 17,317 restricted stock units and 27,028 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on March 18, 2014.

 

(6)         Includes 1,016 shares issuable on the exercise of the Warrants. As of May 29, 2013, Ms. Burke also holds 27,073 restricted stock units, and 70,215 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on October 31, 2013. Ms. Burke also holds 16,234 restricted stock units and 25,338 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on March 18, 2014.

 

(7)         Includes 421 shares issuable on the exercise of the Warrants. As of May 29, 2013, Mr. Alonso also holds 4,071 restricted stock units, and 10,559 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on October 31, 2013 Mr. Alonso also holds 4,871 restricted stock units and 7,602 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on March 18, 2014. Mr. Alonso also holds 10,832 units of phantom stock, which are solely payable in cash.

 

(8)   Amount includes 5 shares issuable on the exercise of warrants. As of May 29, 2013, Mr. Jones also holds 45,606 restricted stock units and 71,277 options, each granted pursuant to the Dynegy LTIP and vesting ratably over three years, with the first vesting period taking place on April 1, 2014.

 

(9)   Amount includes 7,068 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

(10) Amount includes 4,039 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

(11) Amount includes 4,039 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

(12)  Amount includes 3,929 shares issuable upon the exercise of warrants and 4,039 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

(13) Amount includes 4,039 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

(14) Amount includes 4,039 restricted stock units granted pursuant to the Dynegy LTIP, which vest on May 21, 2014.

 

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SELLING STOCKHOLDER

 

The following table sets forth information as of May 29, 2013 regarding the beneficial ownership of our common stock immediately prior to and as adjusted to give effect to this offering by the selling stockholder.

 

In connection with our Plan, we have filed with the SEC a registration statement on Form S-1 under the Securities Act, of which this prospectus forms a part, to register resales of certain shares of common stock that we issued in connection with our emergence from bankruptcy.

 

The common stock is being registered to permit public sales of the common stock by the selling stockholder. The selling stockholder may offer the common stock for resale from time to time pursuant to this prospectus. However, the selling stockholder is under no obligation to sell any of the common stock offered pursuant to this prospectus.

 

All information with respect to common stock ownership of the selling stockholder has been furnished by or on behalf of the selling stockholder and is as of May 29, 2013. We believe, based on information supplied by the selling stockholder, that except as may otherwise be indicated in the footnotes to the table below, the selling stockholder has sole voting and dispositive power with respect to the common stock reported as beneficially owned by it. Because the selling stockholder may sell all, part or none of the common stock it holds, no estimates can be given as to the number of shares of common stock that the selling stockholder will hold upon termination of any offering made hereby. In addition, the selling stockholder may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, the common stock it holds in transactions exempt from the registration requirements of the Securities Act after the date on which it provided the information set forth on the table below. For purposes of the table below, however, we have assumed that after termination of this offering, none of the shares of common stock offered by this prospectus will be held by the selling stockholder.

 

The following table sets forth the name of the selling stockholder, the number of shares of common stock beneficially owned by it as of May 29, 2013, the number of shares of common stock being offered by it, the number of shares of common stock the selling stockholder will beneficially own if it sells all of the common stock being registered and the selling stockholder’s percentage beneficial ownership of our total outstanding common stock if all of the common stock in the offering is sold. As used in this prospectus, “selling stockholder” includes the successors-in-interest, donees, transferees or others who may later hold the selling stockholder’s interests.

 

Except as provided in the footnotes to the following table and the section titled “Related Party Transactions and Material Relationships with Selling Stockholder,” the selling stockholder has not had any position with, held any office of or had any other material relationship with us or our affiliates during the past three years.

 

Beneficial ownership for the purposes of this table is determined in accordance with the rules and regulations of the SEC. These rules generally provide that a person is the beneficial owner of securities if such person has or shares the power to vote or direct the voting thereof, or to dispose or direct the disposition thereof or has the right to acquire such powers within 60 days. Common stock subject to options or issuable upon exercise of warrants that are currently exercisable or exercisable within 60 days of May 29, 2013 is deemed to be outstanding and beneficially owned by the person holding the options or warrants. These shares, however, are not deemed outstanding for the purposes of computing the percentage ownership of any other person. Percentage of beneficial ownership is based on 100,001,082 shares of common stock outstanding as of May 29, 2013. Except as disclosed in the footnotes to this table, we believe that the stockholder identified in the table below possesses sole voting and investment power over all shares of common stock shown as beneficially owned by the stockholder.

 

All percentages and share amounts are approximate based on current information available to us. The information available to us may be incomplete.

 

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Shares Beneficially Owned Prior to This
Offering (1)

 

Maximum

 

Shares Beneficially Owned 
After This Offering

 

Name

 

Number

 

Percent of Class

 

Number of
Shares Offered

 

Number

 

Percent of
Class

 

Selling Stockholder

 

 

 

 

 

 

 

 

 

 

 

Franklin Advisers, Inc. (2) 

 

32,459,817

 

32.0

%

32,459,817

 

*

 

*

 

 


*    Less than 1%.

 

(1)         Shares shown in the table above include shares held in the beneficial owner’s name or jointly with others, or in the name of a bank, nominee or trustee for the beneficial owner’s account.  The calculation of this percentage assumes the acquisition by the selling stockholder of all shares that may be acquired upon exercise of warrants to purchase shares of common stock.

 

(2)         These shares include 1,533,887 shares issuable on the exercise of the Warrants. Notwithstanding the foregoing, a holder may not exercise any Warrant if it would cause such holder’s beneficial ownership of our common stock and any other of our equity securities on parity (with respect to dividends) with such common stock (when aggregated with that of any of the holder’s affiliates) to require the prior permission (including the expiration of applicable waiting periods) of any governmental or regulatory authority applicable to us, unless we and such holder have made all filings and registrations with, and obtained such permission (including the expiration of any such waiting periods) from, any such governmental and regulatory authorities, as are necessary or advisable.

 

FAV, an indirectly wholly owned subsidiary of FRI, is the beneficial owner of these shares for purposes of Rule 13d-3 under the Exchange Act in its capacity as the investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940 and other accounts.  When an investment management contract (including a sub-advisory agreement) delegates to FAV investment discretion or voting power over the securities held in the investment advisory accounts that are subject to that agreement, FRI treats FAV as having sole investment discretion or voting authority, as the case may be, unless the agreement specifies otherwise. Accordingly, FAV reports for purposes of section 13(d) of the Exchange Act that it has sole investment discretion and voting authority over the securities covered by any such investment management agreement, unless otherwise specifically noted.

 

Edward Perks is a natural person who serves as Senior Vice President of FAV and who, in that capacity, makes voting and investment decisions with respect to the shares deemed beneficially owned by FAV.  FAV’s address is One Franklin Parkway, San Mateo, California 94403.

 

FAV is not a broker-dealer.  Franklin/Templeton Distributors, Inc., Franklin Templeton Financial Services Corp. and Templeton/Franklin Investment Services, Inc. are registered broker-dealers that, together with FAV, are subsidiaries of FRI, but they do not beneficially own any of our shares.  The selling stockholder acquired the unsecured notes, lease guaranty claims and Old Common Stock, which it exchanged for the common stock and Warrants pursuant to the Plan, in the ordinary course of business and, at the time such notes, claims and Old Common Stock were acquired, the selling stockholder had no agreements, plans or understandings, either directly or indirectly, with any person to distribute them.

 

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RELATED PARTY TRANSACTIONS AND MATERIAL RELATIONSHIPS WITH THE SELLING STOCKHOLDER

 

Registration Rights Agreement. We entered into a registration rights agreement (the “Registration Rights Agreement”) with FAV. Pursuant to the Registration Rights Agreement, among other things, we are required to use reasonable best efforts to file within 90 days after the Plan Effective Date a registration statement on any permitted form that qualifies (the “Shelf”), and is available for, the resale of “Registrable Securities”, as defined below, with the SEC in accordance with and pursuant to Rule 415 promulgated under the Securities Act. Registrable Securities are shares of our common stock, par value $0.01 per share issued or issuable on or after the Plan Effective Date to any of the original parties to the Registration Rights Agreement, including, without limitation, upon the conversion of our outstanding Warrants, and any securities paid, issued or distributed in respect of any such new common stock, but excluding shares of common stock acquired in the open market after the Plan Effective Date.

 

At any time prior to the five year anniversary of the Plan Effective Date and from time to time after the later of (i) when the Shelf has been declared effective by the SEC and (ii) 210 days after the Plan Effective Date, any one or more holders of Registrable Securities (as defined in the Registration Rights Agreement) may request to sell all or any portion of their Registrable Securities in an underwritten offering, provided that such holder or holders will be entitled to make such demand only if the total offering price of the Registrable Securities to be sold in such offering is reasonably expected to exceed 5% of the market value of our then issued and outstanding common stock or the total offering price is reasonably expected to exceed $250 million. We are not obligated to effect more than two such underwritten offerings during any period of twelve consecutive months after the Plan Effective Date and are not obligated to effect such an underwritten offering within 120 days after the pricing of a previous underwritten offering. In addition, holders of Registrable Securities may request to sell all or any portion of their Registrable Securities in a non-underwritten offering by providing notice to the Company no later than two business days (or in certain circumstances five business days) prior to the expected date of such an offering, subject to certain exceptions provided for in the Registration Rights Agreement.

 

When we propose to offer shares in an underwritten offering whether for our own account or the account of others, holders of Registrable Securities will be entitled to request that their Registrable Securities be included in such offering, subject to specific exceptions.

 

Upon Dynegy becoming a well-known seasoned issuer, we are required to promptly register the sale of all of the Registrable Securities under an automatic shelf registration statement, and to cause such registration statement to remain effective thereafter until there are no longer Registrable Securities.

 

The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as minimums, blackout periods and, if a registration is for an underwritten offering, limitations on the number of shares to be included in the underwritten offering may be imposed by the managing underwriter. Registrable Securities shall cease to constitute Registrable Securities upon the earliest to occur of: (i) the date on which such securities are disposed of pursuant to an effective registration statement under the Securities Act; (ii) the date on which such securities are disposed of pursuant to Rule 144 (or any successor provision) promulgated under the Securities Act; (iii) with respect to the Registrable Securities held by any Holder (as defined in the Registration Rights Agreement), any time that such Holder Beneficially Owns (as defined in Rule 13d-3 under the Exchange Act) Registrable Securities representing less than 1% of the then outstanding new common stock and is permitted to sell such Registrable Securities under Rule 144(b)(1); and (iv) the date on which such securities cease to be outstanding.

 

The foregoing description of the Registration Rights Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Registration Rights Agreement attached hereto as Exhibit 10.1.

 

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Pursuant to the Plan, our Board has seven members who were selected by a committee of representatives from certain creditor groups, including FAV and certain of its clients. Mr. Kuersteiner, one of the directors that the committee selected, was a former employee of FRI. Mr. Kuersteiner is no longer affiliated with FRI or the Franklin Entities and is not their representative on our Board.

 

On the Plan Effective Date and in accordance with the terms of the Plan, former creditors received distributions of our new common stock as well as a cash payment. The former holders of the Old Common Stock also received distributions of new common stock and the Warrants. Unsecured notes and lease guaranty claims beneficially owned by one or more clients of FAV were exchanged for the new common stock pursuant to the Plan. Such liabilities were cancelled and annulled under the Plan. In addition, certain of those clients received the Warrants on account of the administrative claim held by those clients, as former holders of Old Common Stock, which was extinguished, cancelled and discharged on the effective date of the Plan. The selling stockholder and such clients received the common stock and Warrants not with a view to distribute. At the time of the acquisition of the unsecured notes and lease guaranty claims and Old Common Stock, none of the selling stockholder, its clients or affiliates had any agreement or understanding, directly or indirectly, with any person to distribute such securities.

 

FAV is not a broker-dealer.  Franklin/Templeton Distributors, Inc., Franklin Templeton Financial Services Corp. and Templeton/Franklin Investment Services, Inc. are registered broker-dealers that, together with FAV, are subsidiaries of FRI, but they do not beneficially own any of our shares.  The selling stockholder acquired the unsecured notes, lease guaranty claims and Old Common Stock, which it exchanged for the common stock and Warrants pursuant to the Plan, in the ordinary course of business and, at the time such notes, claims and Old Common Stock were acquired, the selling stockholder had no agreements, plans or understandings, either directly or indirectly, with any person to distribute them.

 

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DESCRIPTION OF CAPITAL STOCK

 

The following summary of the terms of our capital stock is not meant to be complete and is qualified in its entirety by reference to our third amended and restated certificate of incorporation, our fourth amended and restated bylaws and the provisions of applicable law. Copies of our third amended and restated certificate of incorporation and our fourth amended and restated bylaws are filed as exhibits to our Current Report on Form 8-K filed with the SEC on October 4, 2012 and incorporated herein by reference.

 

Authorized Capital Stock upon Emergence

 

We have the authority to issue a total of 440,000,000 shares of capital stock, consisting of:

 

·                  420,000,000 shares of common stock; and

 

·                  20,000,000 shares of preferred stock.

 

Common Stock

 

The rights, preferences and privileges of holders of our common stock are subject to, and may be adversely affected by, the rights of the holders of shares of any series of our preferred stock which we may designate and issue in the future.

 

Dividend Rights.  Subject to the rights of holders of preferred stock of any series that may be issued from time to time, and as otherwise provided by the third amended and restated certificate of incorporation, holders of common stock shall be entitled to receive such dividends and other distributions in cash, stock of any corporation or of our property as may be declared by the Board from time to time out of assets or funds of Dynegy legally available for dividends and other distributions, and shall share equally on a per share basis in all such dividends and other distributions.

 

Liquidation Rights.  In the event of any liquidation, dissolution or winding up of Dynegy, the holders of our common stock will be entitled to share in the net assets of Dynegy available after the payment of all debts and other liabilities and subject to the prior rights of any outstanding class of our preferred stock.

 

Preemptive Rights.  Pursuant to our third amended and restated certificate of incorporation, the holders of our common stock have no preemptive rights.

 

Conversion Rights.  Shares of our common stock are not convertible.

 

Voting Rights.  Subject to the rights of the holders of any series of our preferred stock, each outstanding share of our common stock is entitled to one vote on all matters submitted to a vote of stockholders.

 

Board of Directors. Holders of common stock do not have cumulative voting rights with respect to the election of directors. At any meeting to elect directors by holders of our common stock, the presence, in person or by proxy, of the holders of a majority of the voting power of shares of capital stock then outstanding shall constitute a quorum for such election. Directors shall be elected by a plurality of the votes of the shares present and entitled to vote on the election of directors, except for directors whom the holders of preferred stock have the right to elect, if any.

 

Warrants to Purchase Common Stock

 

Pursuant to the Plan, Dynegy issued Warrants to purchase shares of new common stock to holders of shares of its Old Common Stock, which were cancelled pursuant to the Plan.  The Warrants became exercisable at any time after the date of issuance and have an exercise

 

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price of $40.00 per share. Each of the Warrants expires five years after the date of issuance. The Warrants provide for a cashless exercise by the Warrant holder. The exercise price of the Warrants and the number of shares issuable upon exercise of the Warrants are subject to adjustment upon certain events including: stock subdivisions, combinations, splits, stock dividends, capital reorganizations, or capital reclassifications of common stock and in connection with certain distributions of cash, assets or securities. The Warrants are not redeemable.

 

Preferred Stock

 

Under the terms of our third amended and restated certificate of incorporation, the Board is authorized to issue from time to time up to an aggregate of 20,000,000 shares of preferred stock and to fix or alter the designations, preferences, rights and any qualifications, limitations or restrictions of the shares of each series, including the dividend rights, dividend rates, conversion rights, voting rights, rights and terms of redemption (including sinking fund provisions), redemption price or prices, liquidation preferences and the number of shares constituting any series. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions. If the Board decides to issue shares of preferred stock to persons supportive of current management, this could render it more difficult or discourage an attempt to obtain control of Dynegy by means of a merger, tender offer, proxy contest or otherwise. Authorized but unissued shares of preferred stock also could be used to dilute the stock ownership of persons seeking to obtain control of Dynegy. To the extent required by 11 U.S.C. § 1123(a)(6), Dynegy is prohibited from issuing shares of nonvoting equity securities (within the meaning of such statute).

 

Certain Anti-Takeover Effects

 

Provisions of Delaware Law.  We are a Delaware corporation. In our third amended and restated certificate of incorporation, we elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (“DGCL”) regulating corporate takeovers. In general, Section 203 prohibits Delaware corporations, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

 

·                  the transaction is approved by the Board before the date the interested stockholder attained that status;

 

·                  upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

 

·                  on or after such time the business combination is approved by the Board and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

 

Under certain circumstances, Section 203 makes it more difficult for a person who would be an “interested stockholder” to effect various business combinations with a corporation for a three-year period. However, Section 203 is not applicable to us.

 

Advance Notice Procedures.  Our fourth amended and restated bylaws establish an advance notice procedure for stockholder proposals to be brought before an annual meeting of stockholders, including proposed nominations of persons for election to the Board. Stockholders at an annual meeting will only be able to consider proposals or nominations specified in the notice of meeting or brought before the meeting by or at the direction of the Board or by a stockholder who was a stockholder of record on the record date for the meeting, who is entitled to vote at the meeting and who has given our corporate secretary timely written notice, in proper form, of the stockholder’s intention to bring that business before the meeting. Although the bylaws will not give the Board the power to approve or disapprove stockholder nominations of candidates or proposals regarding other business to be conducted at a special or annual meeting, the bylaws may have the effect of precluding the

 

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conduct of certain business at a meeting if the proper procedures are not followed or may discourage or deter a potential acquiror from conducting a solicitation of proxies to elect its own slate of directors or otherwise attempting to obtain control of the company.

 

Action by Written Consent; Special Meetings of Stockholders.  Our fourth amended and restated bylaws provide that stockholder action can be taken at an annual or special meeting of stockholders or by written consent in lieu of a meeting. Our third amended and restated certificate of incorporation and the bylaws provide that, except as otherwise required by law, special meetings of the stockholders can only be called by the chairman of the board, the chief executive officer, the president, a majority of the Board, or the holders of at least 20 percent of all the outstanding shares entitled to vote on the matter for which the meeting is being held. The Board may postpone or reschedule any meeting previous scheduled by the chairman of the Board, the Board, chief executive officer, or president.

 

Authorized but Unissued Shares.  Our authorized but unissued shares of common stock and preferred stock will be available for future issuance without stockholder approval, subject to the rules and regulations of the NYSE or any applicable exchange. These additional shares may be utilized for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares of common stock and preferred stock could render more difficult or discourage an attempt to obtain control of a majority of our common stock by means of a proxy contest, tender offer, merger or otherwise.

 

Transfer Agent and Registrar

 

Computershare Shareholder Services LLC is the transfer agent and registrar for our common stock.

 

Listing of Our Common Stock

 

Currently, our common stock is listed on the NYSE under the trading symbol “DYN.”

 

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SHARES ELIGIBLE FOR FUTURE SALE

 

Future sales of substantial amounts of our common stock in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. No prediction can be made as to the effect, if any, future sales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time.

 

Sale of Restricted Shares

 

As of May 29, 2013, we had 100,001,082 shares of common stock outstanding (excluding the shares underlying the Warrants). Except as set forth below, all shares of our common stock outstanding after this offering will be freely tradable without restriction or further registration under the Securities Act unless held by one of our “affiliates,” as that term is defined in Rule 144 under the Securities Act.  Unless otherwise registered under the Securities Act, sales of shares of our common stock by affiliates will be subject to the volume limitations and other restrictions set forth in Rule 144.

 

Common Stock and Warrants Issued in Reliance on Section 1145 of the Bankruptcy Code

 

We relied on Section 1145(a)(1) and (2) to exempt from the registration requirements of the Securities Act the offer and sale of our common stock, as well as the Warrants. Section 1145(a)(1) exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. Section 1145(a)(2) exempts the offer of securities through and the sale of any securities upon the exercise of any warrant, option, right to subscribe or conversion privilege issued under Section 1145(a)(1), such as the shares of our common stock issuable upon exercise of the Warrants, from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. 99,999,196 shares of our common stock issued pursuant to the Plan, the Warrants and the 15,606,936 shares of our common stock issuable upon exercise of such Warrants may be resold without registration unless the seller is an “underwriter” with respect to those securities. Section 1145(b)(1) defines an “underwriter” as any person who:

 

·                  purchases a claim against, an interest in, or a claim for an administrative expense against the debtor, if that purchase is with a view to distributing any security received in exchange for such a claim or interest;

 

·                  offers to sell securities offered under the Plan for the holders of those securities;

 

·                  offers to buy those securities from the holders of the securities, if the offer to buy is (i) with a view to distributing those securities; and (ii) under an agreement made in connection with the Plan, the completion of the Plan, or with the offer or sale of securities under the Plan; or

 

·                  is an “affiliate” of the issuer.

 

To the extent a person is deemed to be an “underwriter,” resales by such person would not be exempted by Section 1145 from registration under the Securities Act or other applicable law. Those persons would, however, be permitted to sell our common stock or other securities without registration if they are able to comply with the provisions of Rule 144, as described further below.

 

Rule 144

 

As noted above, persons deemed “underwriters” under Section 1145 may be permitted to sell our common stock without registration if they comply with the provisions of Rule 144. Commencing on April 1, 2013, assuming we remain current in our reporting obligations under the Exchange Act, and commencing on October 1, 2013, if we do not, these securities may be sold under Rule 144 subject in the case of holders that are affiliates to restrictions on volume and manner of sale. In general, under Rule 144 a person (or persons whose

 

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shares are aggregated) will be entitled to sell in any three-month period a number of shares that does not exceed the greater of: (i) 1% of the number of shares of our common stock then outstanding or (ii) the average weekly trading volume of our common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of sale is filed with the SEC. Sales pursuant to Rule 144 are subject to requirements relating to manner of sale, notice and availability of current public information about us. A person (or persons whose shares are aggregated) who is not deemed to be an affiliate of ours during the three months preceding the sale, and who has beneficially owned restricted securities for at least one year, is entitled to sell such shares without regard to the limitations and requirements described above.

 

Stock Options and Other Stock Awards

 

The Plan contemplates the adoption of a new management incentive plan under which shares of our common stock, or options or other awards to purchase shares of common stock, can be issued to our directors, management and other employees. Under the Dynegy LTIP, 6,084,576 shares of common stock have been reserved for issuance, and as of May 29, 2013, we have awarded 969,741 stock options and 817,554 restricted stock units to certain of our employees and non-employee directors. On October 25, 2012 we filed a registration statement on Form S-8 covering all of the shares of common stock reserved for issuance under the Dynegy LTIP, and such shares will be freely tradable in the public market as soon as issued subject to certain limitations applicable to affiliates and any restrictions applicable to the vesting of awards.

 

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PLAN OF DISTRIBUTION

 

We are registering 32,459,817 shares of our common stock for possible sale by the selling stockholder. Unless the context otherwise requires, as used in this prospectus, “selling stockholder” includes the selling stockholder named in the table above and donees, pledgees, transferees or other successors-in-interest selling shares received from the selling stockholder as a gift, pledge, partnership distribution or other transfer after the date of this prospectus.

 

The selling stockholder may offer and sell all or a portion of the shares covered by this prospectus from time to time, in one or more or any combination of the following transactions:

 

·                  on the NYSE, in the over-the-counter market or on any other national securities exchange on which our shares are listed or traded;

 

·                  in exchange distributions in accordance with the applicable exchange rules;

 

·                  in privately negotiated transactions;

 

·                  in underwritten transactions;

 

·                  in block trades in which a broker-dealer will attempt to sell the offered shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

 

·                  through purchases by a broker-dealer as principal and resale by the broker-dealer for its account pursuant to this prospectus;

 

·                  in ordinary brokerage transactions and transactions in which the broker solicits purchasers;

 

·                  through the writing of options (including put or call options), whether the options are listed on an options exchange or otherwise;

 

·                  through loans or pledges of the securities to a broker-dealer or an affiliate thereof; and

 

·                  by entering into transactions with third parties who may (or may cause others to) issue securities convertible or exchangeable into, or the return of which is derived in whole or in part from the value of, our common stock.

 

The selling stockholder may sell the shares at fixed prices that may be changed, at prices then prevailing or related to the then current market price or at negotiated prices. The offering price of the shares from time to time will be determined by the selling stockholder and, at the time of the determination, may be higher or lower than the market price of our common stock on the NYSE or any other exchange or market.

 

The shares may be sold directly or through broker-dealers acting as principal or agent, or pursuant to a distribution by one or more underwriters on a firm commitment or best-efforts basis. The selling stockholder may also enter into hedging transactions with broker-dealers. In connection with such transactions, broker-dealers of other financial institutions may engage in short sales of our common stock in the course of hedging the positions they assume with the selling stockholder. The selling stockholder may also enter into options or other transactions with broker-dealers or other financial institutions which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction). In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholder or from purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through

 

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dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling stockholder and any underwriters, dealers or agents participating in a distribution of the shares may be deemed to be underwriters within the meaning of the Securities Act, and any profit on the sale of the shares by the selling stockholder and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

 

The selling stockholder may agree to indemnify an underwriter, broker-dealer or agent against certain liabilities related to the selling of the common stock, including liabilities arising under the Securities Act. Under the registration rights agreement, we have agreed to indemnify the selling stockholder against certain liabilities related to the sale of the common stock, including certain liabilities arising under the Securities Act. Under the registration rights agreement, we have also agreed to pay the costs, expenses and fees of registering the shares of common stock; however, the selling stockholder will pay any underwriting discounts or commissions relating to the sale of the shares of common stock in any underwritten offering.

 

The selling stockholder has advised us that it has not entered into any agreements, understandings or arrangements with any underwriters or broker-dealers regarding the sale of its shares. Upon our notification by the selling stockholder that any material arrangement has been entered into with an underwriter or broker-dealer for the sale of shares through a block trade, special offering, exchange distribution, secondary distribution or a purchase by an underwriter or broker-dealer, we will file a supplement to this prospectus, if required, pursuant to Rule 424(b) under the Securities Act, disclosing certain material information, including:

 

·                  the name of the selling stockholder;

 

·                  the number of shares being offered;

 

·                  the terms of the offering;

 

·                  the names of the participating underwriters, broker-dealers or agents;

 

·                  any discounts, commissions or other compensation paid to underwriters or broker-dealers and any discounts, commissions or concessions allowed or re-allowed or paid by any underwriters to dealers;

 

·                  the public offering price; and

 

·                  other material terms of the offering.

 

In addition, upon being notified by the selling stockholder that a donee, pledgee, transferee or other successor-in-interest intends to sell more than 500 shares, we will, to the extent required, promptly file a supplement to this prospectus to name specifically such person as a selling stockholder.

 

The selling stockholder is subject to the applicable provisions of the Exchange Act, and the rules and regulations under the Exchange Act, including Regulation M. This regulation may limit the timing of purchases and sales of any of the shares of common stock offered in this prospectus by the selling stockholder. The anti-manipulation rules under the Exchange Act may apply to sales of shares in the market and to the activities of the selling stockholder and its affiliates. Furthermore, Regulation M may restrict the ability of any person engaged in the distribution of the shares to engage in market-making activities for the particular securities being distributed for a period of up to five business days before the distribution. The restrictions may affect the marketability of the shares and the ability of any person or entity to engage in market-making activities for the shares.

 

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To the extent required, this prospectus may be amended and/or supplemented from time to time to describe a specific plan of distribution. Instead of selling the shares of common stock under this prospectus, the selling stockholder may sell the shares of common stock in compliance with the provisions of Rule 144 under the Securities Act, if available, or pursuant to other available exemptions from the registration requirements of the Securities Act.

 

Under the securities laws of some states, if applicable, the securities registered hereby may be sold in those states only through registered or licensed brokers or dealers. In addition, in some states such securities may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

 

We cannot assure you that the selling stockholder will sell all or any portion of our common stock offered hereby.

 

This offering will terminate on the date that all shares offered by this prospectus have been sold by the selling stockholder.

 

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EXPERTS

 

Ernst & Young LLP, independent registered public accounting firm, has audited the consolidated financial statements and schedules of Dynegy included in its Annual Report on Form 10-K for the year ended December, 31, 2012, as set forth in their report, which is incorporated by reference in this prospectus and elsewhere in the registration statement. Dynegy’s financial statements and schedules are incorporated by reference in reliance on Ernst & Young LLP’s report, given on their authority as experts in accounting and auditing.

 

The audited historical financial statements as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012 of AER included as Annex A of this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

 

LEGAL MATTERS

 

White & Case LLP, New York, New York, will pass upon the validity of the common stock offered in this offering.

 

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ANNEX A: FINANCIAL STATEMENTS RELATING TO AER

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

Index

 

 

Page(s)

 

 

Glossary of Terms and Abbreviations

A-1 - A-2

 

 

Consolidated Financial Statements (Unaudited)

 

 

 

Statement of Operations and Comprehensive Income (Loss)

A-3

 

 

Balance Sheet

A-4

 

 

Statement of Cash Flows

A-5

 

 

Notes to Consolidated Financial Statements

A-6 - A-42

 



Table of Contents

 

GLOSSARY OF TERMS AND ABBREVIATIONS

 

2012 Annual Report - The Ameren Energy Resources Company, LLC audited consolidated financial statements and accompanying notes for the year ended December 31, 2012.

 

Ameren - Ameren Corporation and its subsidiaries on a consolidated basis.  In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

 

Ameren Illinois - Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois, doing business as Ameren Illinois.

 

Ameren Missouri - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri, doing business as Ameren Missouri.

 

AER — Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that operates a merchant electric generation and marketing business in Illinois, including Genco, AERG, and Marketing Company. Medina Valley was a subsidiary of AER until March 14, 2013, when it was distributed from AER to Ameren.

 

AERG - AmerenEnergy Resources Generating Company, an AER subsidiary, that operates a merchant electric generation business in Illinois.

 

ARO - Asset retirement obligations.

 

AMS - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

 

CAIR - Clean Air Interstate Rule.

 

CCR - Coal combustion residuals.

 

CILCO - Central Illinois Light Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric transmission and distribution business, a merchant electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business. CILCO merged with, and into CIPS, which was renamed Ameren Illinois, on October 1, 2010. Immediately after the merger, Ameren Illinois distributed the common stock of AERG to Ameren Corporation.

 

CIPS — Central Illinois Public Service Company, an Ameren Corporation subsidiary which was renamed Ameren Illinois Company in 2010. CIPS’ energy centers were transferred to Genco in 2000.

 

CSAPR - Cross-State Air Pollution Rule.

 

CT - Combustion turbine electric energy center used primarily for peaking capacity

 

Dynegy — Dynegy, Inc.

 

EEI - Electric Energy, Inc., an 80%-owned Genco subsidiary that operates merchant electric generation energy centers and FERC-regulated transmission facilities in Illinois.  The remaining 20% ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.

 

EPA - Environmental Protection Agency, a United States government agency.

 

FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

 

FERC - Federal Energy Regulatory Commission, a United States government agency.

 

GAAP - Generally accepted accounting principles in the United States of America.

 

Genco - Ameren Energy Generating Company, an AER subsidiary that operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI.

 

IPH - Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy, Inc.

 

Marketing Company - Ameren Energy Marketing Company, an AER subsidiary that markets power for Genco, AERG, and EEI.

 

MATS - Mercury and Air Toxics Standards.

 

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Medina Valley - AmerenEnergy Medina Valley Cogen LLC, an AER subsidiary through March 13, 2013, which owned a 40-megawatt natural gas-fired electric energy center. This energy center was sold in February 2012. This company was distributed from AER to Ameren on March 14, 2013.

 

Megawatthour or MWh - One thousand kilowatthours.

 

MISO - Midwest Independent Transmission System Operator, Inc., an RTO. Renamed Midcontinent Independent System Operator, Inc. on April 26, 2013.

 

Moody’s - Moody’s Investors Service Inc., a credit rating agency.

 

MPS - Multi-Pollutant Standard, a compliance alternative within Illinois law covering reductions in emissions of SO2, NOx, and mercury, which Genco, EEI, and AERG elected in 2006.

 

New AER - A limited liability company to be formed as a direct wholly owned subsidiary of AER. New AER will be acquired by IPH and will include substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.

 

NOx - Nitrogen dioxide.

 

NPNS - Normal purchases and normal sales.

 

NSR - New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.

 

OCI - Other comprehensive income (loss) as defined by GAAP.

 

PUHCA 2005 - The Public Utility Holding Company Act of 2005.

 

RFP - Request for proposal.

 

S&P - Standard & Poor’s Ratings Services, a credit rating agency.

 

SO2 - Sulfur dioxide.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Statement of Operations and Comprehensive Income (Loss) (Unaudited)

Three Months Ended March 31, 2013 and 2012

 

(in millions)

 

2013

 

2012

 

 

 

 

 

 

 

Operating revenues

 

$

297

 

$

339

 

Operating expenses

 

 

 

 

 

Fuel

 

169

 

147

 

Purchased power

 

59

 

43

 

Other operations and maintenance

 

55

 

66

 

Asset impairment

 

207

 

628

 

Depreciation and amortization

 

28

 

32

 

Taxes other than income taxes

 

7

 

8

 

Total operating expenses

 

525

 

924

 

Operating loss

 

(228

)

(585

)

Other expense

 

2

 

 

Interest charges

 

21

 

25

 

Loss before income taxes

 

(251

)

(610

)

Income tax benefit

 

(100

)

(247

)

Net loss

 

(151

)

(363

)

Less: Net loss attributable to noncontrolling interest

 

 

(2

)

Net loss attributable to Ameren Energy

 

 

 

 

 

Resources Company, LLC

 

$

(151

)

$

(361

)

 

 

 

 

 

 

Net loss

 

$

(151

)

$

(363

)

Other comprehensive income (loss), net of taxes

 

 

 

 

 

Unrealized net (loss) gain on derivative hedging instruments, net of income taxes (benefit) of $(1) and $24, respectively

 

(1

)

38

 

Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes of $3 and $23, respectively

 

(6

)

(37

)

Pension and other postretirement activity, net of income taxes of $- and $-, respectively

 

 

1

 

Total comprehensive loss, net of taxes

 

(158

)

(361

)

Comprehensive loss attributable to noncontrolling interest

 

 

(2

)

Total comprehensive loss attributable to Ameren

 

 

 

 

 

Energy Resources Company, LLC, net of taxes

 

$

(158

)

$

(359

)

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Balance Sheet (Unaudited)

March 31, 2013 and December 31, 2012

 

(in millions)

 

2013

 

2012

 

 

 

 

 

 

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

25

 

$

25

 

Advances to money pool

 

154

 

40

 

Accounts receivable - trade

 

49

 

47

 

Accounts and note receivable - affiliates

 

18

 

34

 

Unbilled revenue

 

36

 

31

 

Miscellaneous accounts and notes receivable

 

17

 

24

 

Materials and supplies

 

112

 

123

 

Mark-to-market derivative assets

 

82

 

98

 

Other current assets

 

17

 

31

 

Current assets held for sale

 

166

 

364

 

Total current assets

 

676

 

817

 

Property and plant, net

 

2,270

 

2,274

 

Other assets

 

85

 

85

 

Total assets

 

$

3,031

 

$

3,176

 

Liabilities and equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Borrowings from money pool

 

$

296

 

$

298

 

Accounts and wages payable

 

76

 

83

 

Accounts payable - affiliates

 

32

 

35

 

Deposit received from affiliate for pending asset sale

 

100

 

 

Current portion of tax payable - Ameren Illinois

 

6

 

6

 

Taxes accrued

 

19

 

15

 

Mark-to-market derivative liabilities

 

66

 

60

 

Other current liabilities

 

71

 

33

 

Current liabilities held for sale

 

33

 

25

 

Total current liabilities

 

699

 

555

 

Long-term debt, net

 

824

 

824

 

Deferred credits and other liabilities

 

 

 

 

 

Accumulated deferred income taxes, net

 

217

 

349

 

Accumulated deferred investment tax credits

 

2

 

2

 

Notes payable - Ameren

 

425

 

425

 

Tax payable - Ameren Illinois

 

38

 

39

 

Asset retirement obligations

 

103

 

87

 

Accrued pension and other postretirement benefits

 

39

 

40

 

Other deferred credits and liabilities

 

41

 

41

 

Total deferred credits and other liabilities

 

865

 

983

 

Commitments and contingencies (Note 2, 7 and 8)

 

 

 

 

 

Equity

 

 

 

 

 

Common stock, no par value, 10,000 shares authorized — 2,000 shares outstanding

 

 

 

Other paid-in capital

 

1,479

 

1,479

 

Accumulated deficit

 

(856

)

(692

)

Accumulated other comprehensive income

 

12

 

19

 

Total Ameren Energy Resources Company, LLC equity

 

635

 

806

 

Noncontrolling interest

 

8

 

8

 

Total equity

 

643

 

814

 

Total liabilities and equity

 

$

3,031

 

$

3,176

 

 

The accompanying notes are an integral part of these Consolidated financial statements.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Statement of Cash Flows (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(in millions)

 

2013

 

2012

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net loss

 

$

(151

)

$

(363

)

Adjustments to reconcile net loss to net cash provided by operating activities

 

 

 

 

 

Loss on asset impairment

 

207

 

628

 

Net mark-to-market (gain) loss on derivatives

 

15

 

(5

)

Gain on sales of properties

 

(1

)

(10

)

Depreciation and amortization

 

28

 

32

 

Deferred income taxes and investment tax credits, net

 

(86

)

(251

)

Amortization of debt issuance costs and premiums/discounts

 

 

1

 

Other

 

 

11

 

Changes in assets and liabilities

 

 

 

 

 

Receivables

 

16

 

20

 

Materials and supplies

 

17

 

2

 

Accounts and wages payable

 

(14

)

(15

)

Taxes accrued

 

4

 

7

 

Assets, other

 

(3

)

(10

)

Liabilities, other

 

10

 

17

 

Pension and other postretirement benefits

 

(1

)

(1

)

Net cash provided by operating activities

 

41

 

63

 

Cash flows from investing activities

 

 

 

 

 

Capital expenditures

 

(13

)

(36

)

Money pool advances, net

 

(127

)

(34

)

Deposit received from affiliate for pending asset sale

 

100

 

 

Proceeds from sales of properties

 

1

 

17

 

Net cash used in investing activities

 

(39

)

(53

)

Cash flows from financing activities

 

 

 

 

 

Money pool borrowings, net

 

(2

)

(18

)

Net cash used in financing activities

 

(2

)

(18

)

Net change in cash and cash equivalents

 

 

(8

)

Cash and cash equivalents

 

 

 

 

 

Beginning of period

 

25

 

8

 

End of period

 

$

25

 

$

 

 

 

 

 

 

 

Noncash financing activity — Transfer of Medina Valley to Ameren

 

$

(13

)

$

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

1.                                      Summary of Significant Accounting Policies

 

General

AER is a subsidiary of Ameren, a public utility holding company under PUHCA 2005, administered by the FERC.  AER is headquartered in Collinsville, Illinois.  These consolidated financial statements represent the consolidated results of operations, financial position and cash flows of AER.

 

AER is a merchant electric generation and marketing business operating in Illinois.  AER’s principal subsidiaries are Genco, AERG, Medina Valley (through March 13, 2013), and Marketing Company.  Genco has an 80% ownership interest in EEI.  Through the end of 2012, some AMS employees were included within AER’s business services group, which provides back office, controller, pricing, analytical support, engineering services, and selected information technology services for AER and its subsidiaries. On December 31, 2012, the 102 AMS business services group employees were transferred from AMS to either Genco, AERG, or Marketing Company through an internal reorganization.

 

In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which AER is a part. Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, AER estimated, at that time, it was more likely than not that Genco would sell its Elgin energy center for liquidity purposes within two years. This change in assumption resulted in a noncash long-lived asset impairment in the fourth quarter of 2012 relating to the Elgin energy center. AER’s long-lived assets were not classified as held-for-sale as of December 31, 2012, under authoritative accounting guidance as all criteria to qualify for that presentation were not met as of December 31, 2012. Specifically, AER did not consider it probable at December 31, 2012, that a disposition of an energy center would occur within one year.

 

On March 14, 2013, Ameren entered into a transaction agreement to divest its merchant generation business through New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of Genco’s Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. AER determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for held for sale presentation as of March 31, 2013; therefore, the assets and liabilities associated with these gas-fired energy centers were segregated and presented separately as held for sale as of March 31, 2013, and comparatively at December 31, 2012. The operating results of the Elgin, Gibson City, and Grand Tower gas-fired energy centers did not qualify for discontinued operations presentation because AER will continue to sell power into the same markets with its remaining generation assets. See Note 2 - Assets Held for Sale for additional information regarding that presentation.

 

AER’s accounting policies conform to GAAP. The financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in management’s opinion, for a fair presentation of the AER’s results.  The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions.  Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods.  Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the 2012 Annual Report.

 

Basis of Presentation

 

These consolidated financial statements reflect the historical results of operations, financial position, and cash flows of AER for the periods presented. The consolidated statement of operations reflects intercompany expense allocations made to AER by AMS, an Ameren subsidiary that provides support services to Ameren and its subsidiaries, and by other Ameren affiliated entities for certain corporate functions historically provided by these entities during the periods presented. While management considers these allocations to have been made on a reasonable basis, the allocations presented do not necessarily reflect the expenses that would have been incurred had AER operated as a stand-alone business. See Note 7 — Related Party Transactions for further information on expenses allocated to AER. Interest expense shown in the consolidated statements of operations reflects the interest expense associated with the aggregate direct third-party borrowings and interest-bearing amounts due to affiliate borrowings for each period presented. Additionally, the consolidated financial statements include the costs associated with AER’s participation in Ameren’s single-employer pension and postretirement benefit plans. The consolidated financial position, results of operations and cash flows of AER could differ from those that would have resulted had AER operated autonomously or independently of Ameren and its subsidiaries.

 

See Glossary of Terms and Abbreviations at the beginning of this report for a definition of terms and abbreviations used throughout this report.

 

Uncertain Tax Positions

 

The amount of unrecognized tax benefits as of March 31, 2013, was $12 million. The amount of unrecognized tax benefits as of March 31, 2013, that would impact the effective tax rate, if recognized, was $2 million.

 

AER is included in Ameren’s federal income tax return.  Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.

 

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $12 million. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits to increase or decrease. However, AER does not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to AER’s results of operations, financial position, or liquidity.

 

State income tax returns are generally subject to examination for a period of three years after filing of the return. AER does not currently have material state income tax issues under examination,

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

 

Noncontrolling Interest

Noncontrolling interest comprised the 20% of EEI’s net assets not owned by AER. This noncontrolling interest is classified as a component of equity separate from AER’s equity in its consolidated balance sheet. Net income attributable to noncontrolling interest during the first quarter of 2013 was less than $1 million. The balance of the noncontrolling interest on AER’s balance sheet changed by less than $1 million during the three months ended March 31, 2013.

 

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the three months ended March 31, 2013:

 

Balance at December 31, 2012(a)

 

$

94

 

Liabilities incurred

 

 

Liabilities settled

 

(b

)

Accretion

 

2

 

Change in estimates(c)

 

7

 

Balance at March 31, 2013

 

$

103

 

 


(a)              Balance included $7 million in “Other Current Liabilities” on the balance sheet at December 31, 2012.

(b)              Less than $1 million.

(c)               AER changed its estimate related to updated retirement dates for certain CCR storage facilities. See Note 8 — Commitments and Contingencies for additional information.

 

On March 14, 2013, Ameren entered into a transaction agreement to divest its merchant generation business through New AER to IPH. Under the terms of that agreement, Ameren will retain the existing AROs associated with the Meredosia and Hutsonville energy centers, which were estimated at $27 million as of March 31, 2013. AROs associated with the Meredosia and Hutsonville energy centers will continue to be included in “Asset retirement obligations” on AER’s consolidated balance sheet until they are transferred to Ameren prior to the transaction agreement closing. The ARO associated with the Grand Tower energy center was included in “Current liabilities held for sale” as of March 31, 2013, and December 31, 2012. See Note 2 - Assets Held for Sale for information regarding Genco’s sale of the Grand Tower energy center to Medina Valley and the transfer of the Meredosia and Hutsonville energy centers to Medina Valley.

 

Retirement Benefits

AER employees participate in various pension and postretirement plans.  These include plans exclusively for AER employees as well as those in which AER employees participate along with other Ameren employees.  The primary objective of these plans is to provide eligible employees with pension and postretirement health care and life insurance benefits.  The cost of these plans is included or allocated in the accompanying statement of operations.

 

On March 14, 2013, Ameren entered into a transaction agreement to divest its merchant generation business through New AER to IPH. Under the terms of that agreement, Ameren will retain the portion of AER’s pension and postretirement benefit obligations associated with current

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. New AER will retain the pension and other post-retirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These EEI obligations were estimated at $39 million at March 31, 2013. New AER will also retain the $15 million asset relating to the overfunded status of one of EEI’s postretirement plans.

 

As discussed above, employees of AER also participate in Ameren’s defined benefit pension plans that cover other non-AER Ameren employees.  The cost of these benefits allocated to AER was $2 million and $2 million during the three months ended March 31, 2013, and 2012, respectively, and was based on the relative participation of AER employees in these plans.  These costs are included in the consolidated statement of operations within “Other operations and maintenance” expenses.  AER’s “Other operations and maintenance” expenses also included pension costs of AMS employees working on behalf of AER, which totaled $1 million and $1 million during the three months ended March 31, 2013, and 2012, respectively.  Similarly, employees of AER also participate in Ameren’s postretirement healthcare and life insurance plans that cover other non-AER Ameren employees.  The cost of these benefits allocated to AER was less than $1 million during the three months ended March 31, 2013, and 2012, and was based on the relative participation of AER employees in these plans.  These costs are included in the consolidated statement of operations within “Other operations and maintenance” expenses.  AER’s “Other operations and maintenance” expenses also included postretirement costs of AMS employees working on behalf of AER, which totaled less than $1 million during the three months ended March 31, 2013, and 2012.

 

The “Accrued pension and other postretirement benefits” liability as of March 31, 2013, and December 31, 2012, included in these financial statements does not include the unfunded liabilities associated with Ameren’s pension and other postretirement benefit plans.  The “Accrued pension and other postretirement benefits” line only includes the unfunded liabilities associated with EEI plans.  The balance sheet line item “Accounts payable — affiliates” included $13 million and $12 million associated with the net payable to Ameren Corporation for the obligations of AER employees that participated in Ameren’s single-employer pension and postretirement plans as of March 31, 2013, and December 31, 2012, respectively.

 

The EEI Plans section below only relates to EEI pension and postretirement benefit plans and does not include information relating to Ameren pension and postretirement benefit plans.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

EEI Plans

The following table presents the components of EEI’s net periodic pension cost for the three months ended March 31, 2013, and 2012:

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Service cost

 

$

1

 

$

1

 

Interest cost

 

1

 

1

 

Expected return on plan assets

 

(1

)

(1

)

Net periodic pension benefit cost

 

$

1

 

$

1

 

 

The following table presents the components of the net periodic other postretirement benefit cost for the three months ended March 31, 2013, and 2012:

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Service cost

 

$

 

$

1

 

Interest cost

 

1

 

1

 

Expected return on plan assets

 

(1

)

(1

)

Amortization of prior service credit

 

(2

)

 

Amortization of net actuarial loss

 

2

 

1

 

Net periodic postretirement benefit cost

 

$

 

$

2

 

 

Accounting and Reporting Developments

The following is a summary of recently adopted authoritative accounting guidance that could impact AER.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements.  The amended guidance changed the presentation of comprehensive income in the financial statements.  It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements.  This guidance was effective for AER beginning in the first quarter of 2012 with retroactive application required.  The implementation of the amended guidance did not affect results of operations, financial position, or liquidity.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component.  In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes.  The implementation of this amended guidance in the first quarter of 2013 did not affect AER’s results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements.  The only significant amounts reclassified out of accumulated OCI are related to gains and losses on cash flow hedges.  See Note 5 - Derivative Financial Instruments for the required disclosures.

 

Disclosures about Offsetting Assets and Liabilities

In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments.  The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position.  In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions.  The amendments did not affect AER’s results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures.  AER adopted this guidance for the first quarter of 2013.  See Note 5 — Derivative Financial Instruments for the required disclosures.

 

2.                                      Assets Held for Sale

 

Transaction Agreement with IPH

 

On March 14, 2013, Ameren entered into a transaction agreement to divest its merchant generation business through New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) the obligations relating to Ameren’s single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren’s ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER. On March 13, 2013, AER transferred its interest in Medina Valley at carrying value to Ameren.

 

Ameren will retain the portion of AER’s pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. New AER will retain the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These EEI plan obligations are estimated at $39 million at March 31, 2013. New AER will also retain the $15 million asset relating to the overfunded status of one of EEI’s postretirement plans.

 

Ameren will retain AER’s Meredosia and Hutsonville energy centers, which are no longer in

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

operation and had an immaterial property and plant asset balance as of March 31, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of March 31, 2013. All other AROs associated with AER will be assumed by either IPH or the third-party buyer of the Grand Tower Energy Center.  Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be either retained or cancelled by Ameren, without any costs or other liability or obligation to IPH or New AER and its subsidiaries. Ameren will retain Genco’s tax payable to Ameren Illinois, which was $44 million as of March 31, 2013.

 

Ameren’s retention of AER’s liabilities for pension and postretirement benefit obligations relating to Ameren’s plans, the Meredosia and Hutsonville energy centers and those two energy centers’ related AROs, the tax payable to Ameren Illinois, and related deferred tax balances associated with each transferred balance will be accounted for as transactions between entities under common control and transferred at carrying value.

 

In addition, if this transaction is completed, AER expects the tax basis of property, plant and equipment to decrease and deferred tax assets related to federal and state income tax net operating loss carryforwards and income tax credits to decrease with corresponding offsets to equity. The amount of any such decrease is dependent on the value and timing of the New AER divestiture transaction.

 

Genco’s $825 million in aggregate principal amount of senior notes will remain outstanding following the transaction agreement closing and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $70 million of cash to be retained at Genco in addition to the cash proceeds from the sale of put option assets of at least $133 million and an additional $15 million of cash to be retained at Marketing Company.

 

As described in more detail below under “Amended Put Option Agreement, Asset Purchase Agreement and Guaranty” as a condition to the transaction agreement, Genco will receive cash proceeds from the exercise of its option under the March 28, 2012 put option agreement, as amended, for the sale to Medina Valley of the Elgin, Gibson City and Grand Tower gas-fired energy centers in an amount equal to the greater of $133 million or the appraised value of such energy centers.  If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the put option closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the of the amount it paid at the asset purchase agreement closing.  Ameren has commenced a sale process for these energy centers and expects a third-party sale will be completed during 2013.

 

Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of its divestiture of New AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that New AER will be operated in the ordinary course prior to the closing.

 

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.

 

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

 

On March 28, 2012, Genco entered into a put option agreement with AERG, which gave Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin gas-fired energy centers.

 

Prior to the entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Medina Valley paid to Genco an initial payment of $100 million, with an offset to “Deposit received from affiliate for pending asset sale,” in accordance with the terms of the amended put option agreement, asset purchase agreement, and transaction agreement with IPH. That deposit will remain on AER’s balance sheet until the assets and liabilities are transferred to Medina Valley. Genco advanced the initial payment amount received to the non-state-regulated subsidiaries money pool. In connection with the amended put option agreement, Ameren’s guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

 

Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013. Genco and Medina Valley have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired energy centers. At the asset purchase agreement closing, Genco will receive additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial payment of $100 million, for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren has commenced a sale process for these energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained or the transfer of the Elgin, Gibson City, and Grand Tower energy centers cannot be completed, Genco will be required to return to Medina Valley the initial payment received in March 2013.

 

The asset purchase agreement contains customary representations, warranties and covenants of

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.

 

AER determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for held for sale presentation as of March 31, 2013. As of December 31, 2012, these energy centers did not meet the criteria to be classified as held for sale as it was not probable that they would be disposed within one year. To enhance the comparability of these quarterly financial statements, AER has recast its December 31, 2012 balance sheet to reflect the presentation of the Elgin, Gibson City, and Grand Tower energy centers as held for sale at that date. The following table presents the components of assets and liabilities held for sale on AER’s consolidated balance sheet at March 31, 2013, and December 31, 2012:

 

 

 

March 31

 

December 31

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Materials and supplies

 

$

6

 

$

12

 

Mark-to-market derivative assets

 

20

 

4

 

Property and plant, net

 

138

 

348

 

Other assets

 

2

 

 

Total current assets held for sale

 

$

166

 

$

364

 

 

 

 

 

 

 

Accounts and wages payable

 

$

3

 

$

9

 

Taxes accrued

 

3

 

3

 

Mark-to-market derivative liabilities

 

17

 

3

 

Asset retirement obligations

 

10

 

10

 

Total current liabilities held for sale

 

$

33

 

$

25

 

 

As the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers met the held for sale criteria at March 31, 2013, AER evaluated whether any impairment existed by comparing the disposal group’s carrying value to the fair value less cost to sell. The fair value was determined by reference to the amended put option agreement, the asset purchase agreement with Medina Valley, and the transaction agreement with IPH, which AER believes approximates fair value. As a result, AER recorded a pretax charge to earnings of $207 million for the three months ended March 31, 2013, to reflect the impairment of the Elgin, Gibson City and Grand Tower gas-fired energy centers. The impairment recorded during the first quarter of 2013 primarily related to the Gibson City and Grand Tower energy centers as the Elgin energy center was previously impaired under held and used accounting guidance during the fourth quarter of 2012. The loss was recorded as an impairment of “Property and Plant, net” within the components of current assets held for sale shown above and “Asset impairment” in AER’s consolidated statement of operations and comprehensive income (loss). During the three months ended March 31, 2013, AER recorded an $81 million income tax benefit as a result of the impairment.

 

Unobservable inputs were used in determining the estimated fair value of the Elgin, Gibson City, and Grand Tower energy centers’ disposal group. These assets and liabilities are measured at fair

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.

 

Effective with AER’s conclusion in March 2013 that the Elgin, Gibson City, and Grand Tower gas-fired energy centers met the criteria for held for sale presentation, AER suspended recording depreciation on these energy centers.

 

3.                                      Short-term Debt and Liquidity

 

On November 14, 2012, the 2010 Genco Credit Agreement was terminated and not renewed. Should a financing need arise, sources of liquidity include available cash on hand, a return of money pool advances, and money pool borrowings at the discretion of Ameren. On March 14, 2013, Genco amended and exercised its option to sell its three natural gas-fired energy centers to Medina Valley for a purchase price of at least $133 million. With the additional liquidity received through exercising the amended put option agreement, AER’s financing sources are estimated to be adequate to support its operations in 2013. See Note 2 - Assets Held for Sale for additional information regarding the amended put option agreement.

 

Money Pools

AER and its subsidiaries participate in money pool agreements that provide for certain short-term cash and working capital requirements.  Separate money pools are maintained for Ameren’s utility and non-state-regulated entities.  AMS is responsible for the operation and administration of the money pool agreements.

 

Non-state-regulated Subsidiaries

AER has the ability, subject to Ameren parent company authorization through the closing of the transaction agreement with IPH, to access funding from Ameren’s credit agreements and commercial paper programs through a non-state-regulated subsidiary money pool agreement.  The total amount available to AER and other pool participants at any time is reduced by borrowings made by Ameren’s subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources.  The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren’s non-state-regulated activities.  Borrowers receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest.  The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool.  These rates are based on the cost of funds used for money pool advances.  The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the period ended March 31, 2013, was 0.22% (2012 — 0.76%).

 

See Note 7 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by AER for the three months ended March 31, 2013, and 2012.

 

Utility

AER (through AERG) may participate in the utility money pool only as a lender.  There were no utility money pool advances by AERG during the three months ended March 31, 2013, and 2012.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

4.                                      Long-Term Debt

 

Indenture Provisions and Other Covenants

 

Genco is subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.”  The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations.  However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials.

 

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, to make certain principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external third-party indebtedness.  The following table summarizes these ratios for the three months ended and as of March 31, 2013:

 

 

 

Required

 

Actual

 

Genco

 

Ratio

 

Ratio

 

 

 

 

 

 

 

Restricted payment interest coverage ratio(a)

 

> 1.75

 

2.30

 

Additional indebtedness interest coverage ratio(b)

 

> 2.50

 

2.30

 

Additional indebtedness debt-to-capital ratio(b)

 

< 60

%

47

%

 


(a)                 As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.  Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.

(b)                 Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense.  Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.  Other borrowings from third-party external sources are included in the definition of indebtedness and to these incurrence tests.

 

Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

 

As shown in the table above, under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if the interest coverage ratio is less than a specified minimum or if the debt-to-capital ratio is greater than a specified maximum.  During the first quarter of 2013, Genco’s interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and is expected to remain less than this minimum level through at least 2015.  As a result, Genco’s ability to borrow additional funds from external, third-party sources is restricted.  Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool.  However, borrowings from the money pool are subject to Ameren’s control.  If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time.  During 2013, AER will seek to fund operations internally and therefore seek not to rely on financing from Ameren. See Note 2 — Assets Held for Sale for additional information regarding the put option agreement.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

In order for Genco to issue securities in the future, Genco will have to comply with all applicable requirements in effect at the time of any such issuances.

 

Genco’s indenture includes restrictions that prohibit payments of dividends on its common stock.  Specifically, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level.  Based on projections as of March 31, 2013, of operating results and cash flows in 2013 and 2014, Genco did not believe that it would achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending September 30, 2013, March 31, 2014, September 30, 2014, or March 31, 2015. As a result, Genco was restricted from paying dividends as of March 31, 2013, and expects to be unable to pay dividends on our common stock through at least March 31, 2016.

 

Off-Balance-Sheet Arrangements

At March 31, 2013, AER did not have any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business.  Additionally, AER does not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

 

5.                                      Derivative Financial Instruments

 

AER uses derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, and power.  Such price fluctuations may cause the following:

 

·             an unrealized appreciation or depreciation of AER’s contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

·             market values of coal and natural gas inventories that differ from the cost of those commodities in inventory; and

·             actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

 

The derivatives that AER uses to hedge these risks are governed by AER’s risk management policies for forward contracts, futures, options, and swaps.  AER’s net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required.  The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet AER’s requirements.  Contracts AER enters into as part of its risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following table presents open gross commodity contract volumes by commodity type, as of March 31, 2013, and December 31, 2012:

 

 

 

Quantity (in millions)

 

 

 

Accrual & NPNS
Contracts(a)

 

Cash Flow Hedges(b)

 

Other Derivatives(c)

 

Commodity

 

2013

 

2012

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal (in tons)

 

34

 

39

 

(d

)

(d

)

6

 

7

 

Fuel oils (in gallons)(e)

 

(d

)

(d

)

(d

)

(d

)

46

 

52

 

Natural gas (in mmbtu)

 

(d

)

(d

)

(d

)

(d

)

91

 

47

 

Power (in megawatthours)(f)

 

63

 

66

 

5

 

9

 

75

 

34

 

Renewable energy credits

 

1

 

1

 

(d

)

(d

)

(d

)

(d

)

 


(a)         Accrual contracts include commodity contracts that do not qualify as derivatives.  This includes contracts through December 2017, September 2035, and December 2014 for coal, power, and renewable energy credits, respectively, as of March 31, 2013.

(b)         Contracts through December 2016 for power as of March 31, 2013.

(c)          Contracts through December 2015, October 2016, April 2015, and January 2017 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2013. Includes amounts classified as held for sale.

(d)         Not applicable.

(e)          Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(f)           Includes intercompany eliminations.

 

Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies.  See Note 6 - Fair Value Measurements for discussion of AER’s methods of assessing the fair value of derivative instruments.  Many of AER’s physical contracts, such as purchased power contracts, qualify for the NPNS exception to derivative accounting rules.  The revenue or expense recorded in connection with NPNS contracts is recognized at the contract price upon physical delivery.

 

If AER determines that a contract meets the definition of a derivative and is not eligible for the NPNS exception, AER reviews the contract to determine if it qualifies for hedge accounting treatment.  Contracts that qualify for cash flow hedge accounting treatment are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective.  To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of operations and comprehensive income (loss) in the period in which the change occurs.  When the contract is settled or delivered, the net gain or loss is recorded in the statement of operations and comprehensive income (loss).

 

Certain derivative contracts are entered into on a regular basis as part of AER’s risk management program but do not qualify for, or AER does not choose to elect, the NPNS exception or hedge accounting.  Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of operations and comprehensive income (loss) in the period in which the change occurs.

 

A-18



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement.  AER did not elect to adopt this guidance for any eligible commodity contracts.

 

The following table presents the carrying value and balance sheet classification of all derivative instruments as of March 31, 2013, and December 31, 2012:

 

 

 

2013

 

2012

 

Balance Sheet Location

 

 

 

 

 

Derivative assets designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

Power

Mark-to-market derivative assets

 

$

6

 

$

25

 

 

Other assets

 

6

 

14

 

 

Total assets

 

$

12

 

$

39

 

Derivative assets not designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

Coal

Other assets

 

$

1

 

$

1

 

Fuel oils

Mark-to-market derivative assets

 

3

 

3

 

 

Other assets

 

2

 

1

 

Natural gas

Current assets held for sale

 

19

 

4

 

Power

Mark-to-market derivative assets

 

73

 

70

 

 

Current assets held for sale

 

1

 

 

 

Other assets

 

20

 

15

 

 

Total assets

 

$

119

 

$

94

 

Derivative liabilities not designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

Coal

Mark-to-market derivative liabilities

 

$

6

 

$

9

 

 

Other deferred credits and liabilities

 

4

 

4

 

Fuel oils

Mark-to-market derivative liabilities

 

1

 

1

 

 

Other deferred credits and liabilities

 

1

 

1

 

Natural gas

Current liabilities held for sale

 

15

 

3

 

Power

Mark-to-market derivative liabilities

 

59

 

50

 

 

Current liabilities held for sale

 

2

 

 

 

Other deferred credits and liabilities

 

18

 

17

 

 

Total liabilities

 

$

106

 

$

85

 

 

A-19



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI as of March 31, 2013, and December 31, 2012:

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Cumulative gains (losses) deferred in accumulated OCI

 

 

 

 

 

Power derivative contracts(a) 

 

$

35

 

$

47

 

Interest rate derivative contracts (b)

 

(7

)

(7

)

 


(a)         Represents net gains associated with power derivative contracts.  These contracts are a partial hedge of electricity price exposure through December 2016 as of March 31, 2013.  In light of market prices at March 31, 2013, net pretax unrealized gains of $26 million are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.  However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices.

(b)         Includes net losses associated with interest rate swaps at Genco.  The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance.  The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008.  Over the next 12 months, $1.4 million of the loss will be amortized.

 

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction.  Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk.  In all other transactions, AER is exposed to credit risk.  AER’s credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.

 

AER believes that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities.  AER generally enters into the following master trading and netting agreements: (1) International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) North American Energy Standards Board Inc.  Agreement, a standardized contract for the purchase and sale of natural gas.  These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions.  Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

 

Although AER had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts.  The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of March 31, 2013, and December 31, 2012:

 

A-20



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

 

 

 

 

Gross Amounts Not Offset in the
Balance Sheet

 

 

 

 

 

Gross
Amounts
Recognized in
the Balance
Sheet

 

Derivative
Instruments

 

Cash
Collateral
Received/
Posted(a)

 

Net
Amount

 

Assets(b):

 

 

 

 

 

 

 

 

 

2013

Commodity contracts eligible to be offset

 

$

124

 

$

86

 

$

 

$

38

 

 

Commodity contracts not eligible to be offset(c)

 

7

 

 

 

 

 

 

 

 

Total commodity contracts

 

$

131

 

 

 

 

 

 

 

2012

Commodity contracts eligible to be offset

 

$

117

 

$

60

 

$

3

 

$

54

 

 

Commodity contracts not eligible to be offset(c)

 

16

 

 

 

 

 

 

 

 

Total commodity contracts

 

$

133

 

 

 

 

 

 

 

Liabilities(b):

 

 

 

 

 

 

 

 

 

2013

Commodity contracts eligible to be offset

 

$

102

 

$

86

 

$

 

$

16

 

 

Commodity contracts not eligible to be offset(c)

 

4

 

 

 

 

 

 

 

 

Total commodity contracts

 

$

106

 

 

 

 

 

 

 

2012

Commodity contracts eligible to be offset

 

$

84

 

$

60

 

$

 

$

24

 

 

Commodity contracts not eligible to be offset(c)

 

1

 

 

 

 

 

 

 

 

Total commodity contracts

 

$

85

 

 

 

 

 

 

 

 


(a)                                 Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.
(b)
                                 Includes amounts classified as held for sale.
(c)
                                  Commodity contracts not subject to an enforceable master netting arrangement or similar agreement.

 

Concentrations of Credit Risk

In determining its concentrations of credit risk related to derivative instruments, AER reviews its individual counterparties and categorizes each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure as March 31, 2013, and December 31, 2012, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

 

 

Affiliates(a)

 

Coal
Producers

 

Commodity
Marketing
Companies

 

Electric
Utilities

 

Financial
Companies

 

Municipalities/
Cooperatives

 

Oil and Gas
Companies

 

Retail
Companies

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013(b)

 

$

15

 

$

 

$

17

 

$

17

 

$

9

 

$

223

 

$

4

 

$

69

 

$

354

 

2012(b)

 

71

 

3

 

38

 

10

 

13

 

192

 

3

 

85

 

415

 

 


(a)              Primarily comprised of Marketing Company’s exposure to Ameren Illinois.

(b)              Includes amounts classified as held for sale.

 

A-21



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by AER from counterparties and based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements was less than $1million and $3 million at March 31, 2013, and December 31, 2012, respectively. Other collateral used to reduce exposure consisted of letters of credit in the amount of $6 million and $6 million at March 31, 2013, and December 31, 2012, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2013, and December 31, 2012:

 

 

 

Affiliates(a)

 

Coal
Producers

 

Commodity
Marketing
Companies

 

Electric
Utilities

 

Financial
Companies

 

Municipalities/
Cooperatives

 

Oil and Gas
Companies

 

Retail
Companies

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013(b)

 

$

15

 

$

 

$

12

 

$

12

 

$

7

 

$

216

 

$

2

 

$

69

 

$

333

 

2012(b)

 

68

 

1

 

29

 

4

 

11

 

185

 

 

85

 

383

 

 


(a)         Primarily comprised of Marketing Company’s exposure to Ameren Illinois.

(b)         Includes amounts classified as held for sale.

 

Derivative Instruments With Credit Risk-Related Contingent Features

AER’s commodity contracts contain collateral provisions tied to credit ratings. If Ameren or Genco were to experience an adverse change in its credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2013 and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2013 and December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:

 

 

 

Aggregate Fair Value of
Derivative Liabilities(a)

 

Cash
Collateral
Posted

 

Potential Aggregate
Amount of Additional
Collateral Required(b)

 

2013(c)

 

$

124

 

$

10

 

$

103

 

2012(c)

 

130

 

7

 

90

 

 


(a)         Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.

(b)         As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.

(c)          Includes amounts classified as held for sale.

 

A-22



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Cash Flow Hedges

The following table presents the pretax net gain or loss associated with derivative instruments designated as cash flow hedges for the three months ended March 31, 2013, and 2012:

 

 

 

Gain (Loss)
Recognized
in OCI(a)

 

Location of
(Gain) Loss
Reclassified from
Accumulated OCI
into Income(b)

 

(Gain) Loss
Reclassified
from
Accumulated
OCI into
Income(b)

 

Location of
(Gain) Loss
Recognized in
Income(c)

 

Gain (Loss)
Recognized
in Income(c)

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

Power

 

$

(2

)

Operating revenues

 

$

(9

)(d)

Operating revenues

 

$

(16

)

Interest rate(e) 

 

 

Interest charges

 

(f

)

Interest charges

 

 

2012

 

 

 

 

 

 

 

 

 

 

 

Power

 

62

 

Operating revenues

 

(60

)(g)

Operating revenues

 

12

 

Interest rate(e) 

 

 

Interest charges

 

(f

)

Interest charges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(a)                                 Effective portion of gain (loss).

(b)                                 Effective portion of (gain) loss on settlements.

(c)                                  Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d)                                 Income tax for this amount is $3 million and recorded in the income taxes (benefit) line of the statement of operations and comprehensive income (loss).

(e)                                  Represents interest rate swaps settled in prior periods.  The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(f)                                   Less than $1 million.

(g)                                  Income tax for this amount was $23 million and recorded in the income taxes (benefit) line of the statement of operations and comprehensive income (loss).

 

As part of the 2007 Illinois electric settlement agreement and the subsequent Illinois power procurement processes, Ameren Illinois, a subsidiary of Ameren, entered into financial contracts with Marketing Company.  These financial contracts were derivative instruments. They were accounted for as cash flow hedges by Marketing Company. Marketing Company recorded the fair value of the contracts on its balance sheet and the changes to the fair value in OCI. As of December 31, 2012, these contracts had fully expired.

 

Other Derivatives

The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the three months ended March 31, 2013, and 2012:

 

 

 

Location of (Gain) Loss

 

Gain (Loss) Recognized in Income

 

 

 

Recognized in Income

 

2013

 

2012

 

 

 

 

 

 

 

 

 

Coal

 

Operating expenses - fuel

 

$

3

 

$

(4

)

Fuel oils

 

Operating expenses - fuel

 

1

 

5

 

Natural gas

 

Operating expenses - fuel

 

3

 

 

Power

 

Operating revenues

 

(6

)

(8

)

 

 

 

 

$

1

 

$

(7

)

 

A-23



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

6.                            Fair Value Measurements

 

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  AER uses various methods to determine fair value, including market, income, and cost approaches.  With these approaches, AER adopts certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation.  Inputs to valuation can be readily observable, market-corroborated, or unobservable.  AER uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value.  All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

 

Level 1                              Inputs based on quoted prices in active markets for identical assets or liabilities.  Level 1 assets and liabilities are primarily exchange-traded derivatives and assets.

 

Level 2                              Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data.  Level 2 assets and liabilities include certain over-the-counter derivative instruments, including financial power transactions.  Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets.  AER’s development and corroboration process entails obtaining multiple quotes or prices from outside sources.  To derive AER’s forward view to price its derivative instruments at fair value, AER averages the midpoints of the bid/ask spreads.  To validate forward prices obtained from outside parties, AER compares the pricing to recently settled market transactions.  Additionally, a review of all sources is performed to identify any anomalies or potential errors.  Further, AER considers the volume of transactions on certain trading platforms in its reasonableness assessment of the averaged midpoint.  Power derivatives contracts are valued based upon the use of multiple forward prices provided by third parties.  The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

 

Level 3                              Unobservable inputs that are not corroborated by market data.  Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs.  Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable.  AER values Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions.  AER’s development and corroboration process entails obtaining multiple quotes or prices from outside sources.  As a part of AER’s reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

 

AER performs an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements.  Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement.  All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

 

A-24



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended March 31, 2013:

 

 

 

 

 

 

 

 

 

Range

 

 

 

Fair Value

 

Valuation

 

 

 

[Weighted

 

 

 

Assets

 

Liabilities

 

Technique(s)

 

Unobservable Input

 

Average]

 

Level 3 derivative asset and liability - commodity contracts(a)

 

 

 

 

 

Fuel oils

 

$

2

 

$

(1

)

Discounted cash flow

 

Escalation rate(%)(b)

 

.20 - .71 [.55]

 

 

 

 

 

 

 

 

 

Counterparty credit

 

 

 

 

 

 

 

 

 

 

 

risk(%)(c)(d)

 

.26 — 1 [1]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3 — 29 [16]

 

 

 

 

 

 

 

Option model

 

Volatilities(%)(b)

 

14 — 19 [18]

 

Power(e)

 

89

 

(63

)

Option model

 

Volatilities(%)(c)

 

14 — 39 [19]

 

 

 

 

 

 

 

 

 

Average bid/ask

 

 

 

 

 

 

 

 

 

 

 

consensus peak and

 

 

 

 

 

 

 

 

 

 

 

offpeak pricing ($/MWh)(c)

 

24 — 48 [30]

 

 

 

 

 

 

 

Discounted cash flow

 

Average bid/ask

 

 

 

 

 

 

 

 

 

 

 

consensus peak and

 

 

 

 

 

 

 

 

 

 

 

offpeak pricing - forward/

 

 

 

 

 

 

 

 

 

 

 

swaps ($/MWh)(c)

 

17 — 53 [36]

 

 

 

 

 

 

 

 

 

Estimated auction price

 

(3,950) — 5,271

 

 

 

 

 

 

 

 

 

for FTRs ($/MW)(b)

 

[171

]

 

 

 

 

 

 

 

 

Nodal basis ($/MWh)(c)

 

(6) — 1 [(1)]

 

 

 

 

 

 

 

 

 

Counterparty credit

 

 

 

 

 

 

 

 

 

 

 

risk(%)(c)(d)

 

.02 — 100 [2]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3

 

 


(a)              The derivative asset and liability balances are presented net of counterparty credit considerations and includes amounts classified as held for sale.

(b)              Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(c)               Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

(d)              Counterparty credit risk is only applied to counterparties with derivative asset balances.  AER credit risk is only applied to counterparties with derivative liability balances.

(e)               Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2017.

 

A-25



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:

 

 

 

 

 

 

 

 

 

Range

 

 

 

Fair Value

 

Valuation

 

 

 

[Weighted

 

 

 

Assets

 

Liabilities

 

Technique(s)

 

Unobservable Input

 

Average]

 

Level 3 derivative asset and liability - commodity contracts(a)

 

 

 

 

 

 

 

 

 

 

 

Fuel oils

 

$

  1

 

$

  —

 

Discounted cash flow

 

Escalation rate(%)(b)

 

.21 - .68 [.59]

 

 

 

 

 

 

 

 

 

Counterparty credit

 

 

 

 

 

 

 

 

 

 

 

risk(%)(c)(d)

 

.12 - 1 [1]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3 - 31 [20]

 

 

 

 

 

 

 

Option model

 

Volatilities(%)(b)

 

19 - 27 [23]

 

Power(e)

 

117

 

(58

)

Option model

 

Volatilities(%)(c)

 

13 - 38 [26]

 

 

 

 

 

 

 

 

 

Average bid/ask

 

 

 

 

 

 

 

 

 

 

 

consensus peak and

 

 

 

 

 

 

 

 

 

 

 

offpeak pricing ($/MWh)(c)

 

24 - 45 [36]

 

 

 

 

 

 

 

Discounted cash flow

 

Average bid/ask

 

 

 

 

 

 

 

 

 

 

 

consensus peak and

 

 

 

 

 

 

 

 

 

 

 

offpeak pricing - forward/

 

 

 

 

 

 

 

 

 

 

 

swaps ($/MWh)(c)

 

16 - 52 [32]

 

 

 

 

 

 

 

 

 

Estimated auction price

 

(133,787) - 19,671

 

 

 

 

 

 

 

 

 

for FTRs ($/MW)(b)

 

[249]

 

 

 

 

 

 

 

 

 

Nodal basis ($/MWh)(c)

 

(12) - 1 [(1)]

 

 

 

 

 

 

 

 

 

Counterparty credit

 

 

 

 

 

 

 

 

 

 

 

risk(%)(c)(d)

 

.04 - 100 [2]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(a)              The derivative asset and liability balances are presented net of counterparty credit considerations.

(b)              Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(c)               Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

(d)              Counterparty credit risk is only applied to counterparties with derivative asset balances.  AER credit risk is only applied to counterparties with derivative liability balances.

(e)               Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2016.

 

In accordance with applicable authoritative accounting guidance, AER considers nonperformance risk in its valuation of derivative instruments by analyzing the credit standing of its counterparties and considering any counterparty credit enhancements (e.g., collateral).  The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable.  Therefore, AER has factored the impact of its credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities.  Included in AER’s valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings.  AER recorded net losses totaling less than

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

$1 million and $2 million in three months ended March 31, 2013, and 2012, respectively, related to valuation adjustments for counterparty default risk.  At March 31, 2013, and December 31, 2012, the counterparty default risk valuation adjustment related to net derivative assets totaled less than $1 million and less than $1 million, respectively.

 

The following table sets forth, by level within the fair value hierarchy, AER’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2013, and December 31, 2012:

 

Derivative-Commodity
Contracts(a)

 

Quoted Prices in
Active Markets
for

Identical Assets
or Liabilities
(Level 1)

 

Significant
Other

Observable
Inputs
(Level 2)

 

Significant Other
Unobservable
Inputs
 (Level 3)

 

Total

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Coal

 

$

1

 

$

 

$

 

$

1

 

Fuel oils

 

3

 

 

2

 

5

 

Natural gas

 

19

 

 

 

19

 

Power

 

 

17

 

89

 

106

 

 

 

$

23

 

$

17

 

$

91

 

$

131

 

Liabilities

 

 

 

 

 

 

 

 

 

Coal

 

$

10

 

$

 

$

 

$

10

 

Fuel oils

 

1

 

 

1

 

2

 

Natural gas

 

15

 

 

 

15

 

Power

 

 

16

 

63

 

79

 

 

 

$

26

 

$

16

 

$

64

 

$

106

 

 

A-27



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Derivative-Commodity
Contracts(a)

 

Quoted Prices in
Active Markets
for

Identical Assets
or Liabilities
(Level 1)

 

Significant
Other

Observable
Inputs
(Level 2)

 

Significant Other
Unobservable
Inputs
 (Level 3)

 

Total

 

 

 

 

 

 

 

 

 

 

 

2012

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Coal

 

$

1

 

$

 

$

 

$

1

 

Fuel oils

 

3

 

 

1

 

4

 

Natural gas

 

4

 

 

 

4

 

Power

 

 

7

 

117

 

124

 

 

 

$

8

 

7

 

$

118

 

$

133

 

Liabilities

 

 

 

 

 

 

 

 

 

Coal

 

$

13

 

$

 

$

 

$

13

 

Fuel oils

 

2

 

 

 

2

 

Natural gas

 

3

 

 

 

3

 

Power

 

 

9

 

58

 

67

 

 

 

$

18

 

$

9

 

$

58

 

$

85

 

 

 

 

 

 

 

 

 

 

 

 


(a)              The derivative asset and liability balances are presented net of counterparty credit considerations. Balances include amounts classified as held for sale.

 

A-28



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2013, and 2012: 

 

 

 

Net Derivative
Commodity Contracts

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Fuel oils

 

 

 

 

 

Beginning balance at January 1

 

$

1

 

$

1

 

Realized and unrealized gains (losses)

 

 

 

 

 

Included in earnings(a)

 

 

2

 

Total realized and unrealized gains (losses)

 

 

2

 

Transfers out of Level 3

 

 

(1

)

Ending balance at March 31

 

$

1

 

$

2

 

Change in unrealized gains (losses) related to assets/liabilities held at March 31

 

$

 

$

1

 

 

 

 

 

 

 

Power(b)

 

 

 

 

 

Beginning balance at January 1

 

$

59

 

$

234

 

Realized and unrealized gains (losses)

 

 

 

 

 

Included in earnings(a)

 

(1

)

17

 

Included in OCI

 

(18

)

64

 

Total realized and unrealized gains (losses)

 

(19

)

81

 

Purchases

 

4

 

(1

)

Sales

 

(3

)

1

 

Settlements

 

(17

)

(77

)

Transfers out of Level 3

 

2

 

2

 

Ending balance at March 31

 

$

26

 

$

240

 

Change in unrealized gains (losses) related to assets/liabilities held at March 31

 

$

(19

)

$

64

 

 


(a)         Net gains on fuel oil derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues.

(b)         Includes amounts classified as held for sale.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period.  Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges from previous periods.  Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.  For the three months ended March 31, 2013, and 2012, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts.  The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2013, and 2012:

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Transfer out of Level 3/transfers into Level 1

 

$

 

$

(1

)

Transfers out of Level 3/transfers into Level 2

 

2

 

2

 

Net fair value of Level 3 transfers

 

$

2

 

$

1

 

 

AER’s carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy.  Short-term borrowings approximate fair value because of the short-term nature of these instruments.  Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.  The estimated fair value of long-term debt is based on the quoted market prices for same or similar issues for companies with similar credit profiles or on the current rates offered to AER for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

 

The following table presents the carrying amounts and estimated fair values of AER’s long-term debt at March 31, 2013, and December 31, 2012:

 

 

 

2013

 

2012

 

 

 

Carrying

 

 

 

Carrying

 

 

 

 

 

Amount

 

Fair Value

 

Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

$

824

 

$

629

 

$

824

 

$

618

 

 

7.                                      Related Party Transactions

 

AER has engaged in, and may in the future engage in, transactions with Ameren and other non-AER subsidiaries (“affiliates”) in the normal course of business.  These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings.  Transactions between affiliates are reported as intercompany transactions on AER’s financial statements.  See also Note 2 — Assets Held for Sale regarding the

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

divesture of New AER and Genco’s pending sale of the Elgin, Gibson City, and Grand Tower energy centers.  As discussed in Note 1 — Summary of Significant Accounting Policies to the consolidated financial statements, the financial statements reflect significant allocations of the costs of the services provided to AER by Ameren and its subsidiaries on a basis that management believes is appropriate.  The consolidated financial position, results of operations and cash flows of AER could differ from those that would have resulted had AER operated autonomously or independently of Ameren and its subsidiaries.  Below are the material related party agreements. For a discussion of AER’s material related party agreements, see Note 11 — Related Party Transactions in AER’s 2012 Annual Report.

 

Marketing Company Sale of Trade Receivables to Ameren Illinois

In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers’ receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail electric supplier.  Marketing Company sells and Ameren Illinois purchases trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier.  Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions.  As of March 31, 2013, Marketing Company’s receivable from Ameren Illinois for the purchase of trade receivables totaled $9 million.  During the three months ended March 31, 2013, Ameren Illinois purchased $33 million of trade receivables from Marketing Company.

 

Money Pools

See Note 3 — Short-term Debt and Liquidity for discussion of affiliate borrowing arrangements.

 

Parent Guarantees
In the ordinary course of business, Ameren enters into various agreements providing financial assurance to third parties on behalf of AER.  Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through a money pool borrowing will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. See Note 2 — Assets Held for Sale for additional information. At March 31, 2013, Ameren had the following guarantees:

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

·                       $158 million in guarantees outstanding for physically and financially settled power transactions primarily for Marketing Company counterparties.  As of March 31, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren’s estimated exposure for obligations under transactions covered by these guarantees was $26 million at March 31, 2013, which represents the total amount Ameren could be required to fund based on March 31, 2013 market prices.

 

·                       $33 million associated with the guarantee provided by Ameren for Medina Valley on March 14, 2013, relating to the put option agreement between Genco and Medina Valley.  Genco exercised the put option in March 2013 and received an initial payment of $100 million.

 

·                       $65 million provided to two clearing brokers acting as futures commission merchants for the clearing of certain power, natural gas, and fuels commodity transactions for AER. As of March 31, 2013, AER was transitioning from its existing futures commission merchant to a new futures commission merchant. As of May 1, 2013, following completion of this transition, only one guarantee for $25 million is required.

 

·                       $5 million in guarantee to Caterpillar for the asset sale of Medina Valley.

 

The following table presents the impact on AER of related party transactions for the three months ended March 31, 2013, and 2012.  It is based primarily on the agreements discussed above and in Note 11 — Related Party Transactions in AER’s 2012 Annual Report and the money pool arrangements discussed in Note 3 — Short-term Debt and Liquidity in this report.

 

 

 

Income Statement

 

 

 

 

 

Agreement

 

Line Item

 

2013

 

2012

 

 

 

 

 

 

 

 

 

Marketing company agreements with Ameren Illinois

 

Operating revenues

 

$

26

 

$

87

 

 

 

 

 

 

 

 

 

Genco gas transportation agreement with Ameren Missouri

 

Fuel

 

$

(a

)

$

(a

)

Transmission services provided by Ameren

 

Purchased power

 

$

6

 

$

2

 

Illinois and Ameren Transmission

 

 

 

 

 

 

 

Company of Illinois to Marketing Company

 

 

 

 

 

 

 

AMS support services agreement

 

Other operations and maintenance

 

$

8

 

$

11

 

Interest on note payable to Ameren

 

Interest charges

 

$

9

 

$

9

 

Money pool borrowings

 

Interest charges

 

(a

)

1

 

Total interest charges

 

Interest charges

 

$

9

 

$

10

 

 


(a)  Less than $1 million.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

8.                                      Commitments and Contingencies

 

See Note 12 — Commitment and Contingencies in the 2012 Annual report for a listing of leases and other obligations.

 

AER is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money.  AER believes that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Environmental Matters

AER is subject to various environmental laws and regulations enforced by federal, state, and local authorities.  From the beginning phases of siting and development to the ongoing operation of existing or new electric generation and transmission facilities, AER’s activities involve compliance with diverse environmental laws and regulations.  These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling.  Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities.  Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

 

In addition to existing laws and regulations, including the Illinois MPS that applies to AER’s coal-fired energy centers in Illinois, the EPA is developing environmental regulations that will have a significant impact on the electric generating industry.  These regulations could be particularly burdensome for certain companies, including AER, that operate coal-fired energy centers.  Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for fine particulate, SO2, and NOx emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at AER’s energy centers.  The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future.  These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012.  Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years.  Compliance with these environmental laws and regulations could be prohibitively expensive.  If they are, these regulations could require AER to close or to significantly alter the operation of its energy centers, which could have an adverse effect on its results of operations, financial position, and liquidity,

 

A-33



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

including the impairment of long-lived assets.  Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

 

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and AER’s assessment of the potential impacts of the EPA’s proposed regulation for CCR and the MATS as of March 31, 2013.  In addition, the estimates assume that CCR will continue to be regarded as nonhazardous.  The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as AER’s evaluation of those impacts is ongoing.  The estimates could change significantly depending upon a variety of factors including:

 

·             additional or modified federal or state requirements;

·             further regulation of greenhouse gas emissions;

·             revisions to CAIR or reinstatement of CSAPR;

·             new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

·             additional or new rules governing air pollutant transport;

·             regulations under the Clean Water Act regarding cooling water intake structures or effluent standards;

·             finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;

·             new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;

·             new technology;

·             expected power prices;

·             variations in costs of material or labor; and

·             alternative compliance strategies or investment decisions.

 

 

 

Low

 

High

 

 

 

 

 

 

 

2013

 

$

35

 

$

35

 

2014 — 2017

 

120

 

150

 

2018 — 2022

 

240

 

295

 

Total (a)

 

$

395

 

$

480

 

 


(a)              Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers.

 

The decision to make pollution control equipment investments depends on whether the expected future market prices for power reflects the increased cost for environmental compliance.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

The following sections describe the more significant environmental rules that affect or could affect AER’s operations.

 

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels.  In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR).  The CAIR required generating facilities in 28 states, including Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions.

 

In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule’s flaws, but allowed the CAIR’s cap-and-trade programs to remain effective until they are replaced by the EPA.  In July 2011, the EPA issued the CSAPR as the CAIR replacement.  On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR.  In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR’s emission limits on states.  In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA’s request for rehearing.  In March 2013, the EPA and certain environmental groups filed an appeal of the Circuit Court’s remand of CSAPR to the Supreme Court.  The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

 

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units.  Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place.  The MATS do not require a specific control technology to achieve the emission reductions.  The MATS will apply to each unit at a coal-fired power plant; however, in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant.  Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

 

Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent.  States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard.  Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions.  Compliance with the rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted.  AER is currently evaluating the new standard while the state of Illinois develops its attainment plan.

 

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone.  The EPA is required to revisit these standards for ozone again in 2013.  The state of Illinois will be required to develop an attainment plan to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

requirements for power plants by 2020.  AER continues to assess the impacts of these new standards.

 

In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below.  The Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance.  The Illinois Pollution Control Board’s order also included the following provisions:

 

·                       A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at the Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

 

·                       A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact AER’s ability to make the Meredosia energy center available for any parties that may be interested in repowering one of AER’s units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.

 

As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS.  AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. See Note 2 — Assets Held for Sale for additional information.

 

Under the MPS, AER is required to reduce mercury, NOx and SO2 emissions with declining limits starting in 2009 for mercury and in 2010 for NOx and SO2.  The final NOx limit became effective in 2012.  The final mercury limit will become effective in 2015 and the final SO2 limit will become effective by the end of 2019.  The Illinois Pollution Control Board’s September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER’s energy centers.  To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NOx, and SO2.  AER has installed three scrubbers at two of its energy centers.  Two additional scrubbers are being constructed at the Newton energy center.  AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations, and compliance technologies, among other factors.

 

Environmental compliance costs could be prohibitive at some of AER’s energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

 

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR.  Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations.  The CAIR uses the acid rain program’s allowances for SO2 emissions and created

 

A-36



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

annual and ozone season NOx allowances.  AER expects to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.

 

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change.  Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances.  As a result of AER’s fuel portfolio, its emissions of greenhouse gases vary among its energy centers, but coal-fired power plants are significant sources of CO2.

 

In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment.  In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011.  As a result of these actions, AER is required to consider the emissions of greenhouse gases in any air permit application.

 

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants.  The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal.  Currently, AER’s energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions.  The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to address greenhouse gas emissions.  New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold.  The extent to which the Tailoring Rule could have a material impact on AER’s energy centers depends upon how the state of Illinois applies the EPA’s guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers.  In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the Circuit Court’s decision upholding the Tailoring Rule.

 

Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants.  This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of our existing energy centers.  AER anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive.  A final rule is expected in 2013.  Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.

 

A-37



 

Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force AER as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues.  As a result, mandatory limits could have a material adverse impact on our results of operations, financial position, and liquidity.

 

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change.  In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v.  Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including AER’s energy centers, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage.  The case has been appealed to the appellate court.

 

The impact on AER of future initiatives related to greenhouse gas emissions and global climate change is unknown.  Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required.  Since these initiatives continue to evolve, their impact on AER’s coal-fired energy centers and its customers’ costs is unknown, but they could result in significant increases in AER’s capital expenditures and operating costs.  The compliance costs could be prohibitive at some of AER’s energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

 

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications.  The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

 

Commencing in 2005, AER received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act.  The requests sought detailed operating and maintenance history data with respect to AER’s coal-fired energy centers.  In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act.  The EPA contends that projects performed in 1997, 2006, and 2007 at Genco’s Newton energy center violated federal law.  AER believes its defenses to the allegations described in the Notice of Violation are meritorious.  AER included $4 million in “Other current liabilities” on its consolidated balance sheet as of March 31, 2013, relating to this loss contingency.  AER is unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation.

 

Ultimate resolution of these matters could have a material adverse impact on AER’s future results of operations, financial position, and liquidity.  A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties.  AER is unable to predict the ultimate resolution of these matters or the costs that might be incurred.

 

A-38



 

Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling.  Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant’s intake screens or to reduce intake velocity to a specified level.  The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system.  The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter.  All coal-fired and combined cycle energy centers with cooling water systems are subject to this proposed rule.  The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards.  AER is currently evaluating the proposed rule, and its assessment of the proposed rule’s impacts is ongoing.  Therefore, AER cannot predict at this time the capital or operating costs associated with compliance.  The proposed rule, if adopted, could have an adverse effect on AER’s results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.

 

In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s multi-option proposed rule would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain contaminants in waste water discharges from power plants. If enacted as proposed, AER would be subject to the revised limitations beginning July 1, 2017, but no later than July 1, 2022. AER is reviewing the proposed rule and evaluating its impact on AER’s operations if enacted as proposed. The EPA expects to finalize the rule in 2014.

 

Environmental Claims

Several of AER’s facilities were transferred by Ameren’s rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003.  As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental contamination at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley.  The agreements will also specify that all environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers will no longer be indemnified by Ameren Illinois.  See Note 2 — Held for Sale for additional information.

 

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems.  In April 2013, AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds.  The rulemaking process could take up to two years to complete. Genco changed its ARO fair value estimates relating to its ash ponds to revise their expected settlement dates.

 

A-39



 

Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Ash Management

There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR.  In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers.  Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste.  As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners.  Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations.  The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and intended to align this proposal with the CCR rules proposed in May 2010.  Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements.  AER is currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered.  AER is also evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

 

Asbestos-related Litigation

Former Ameren Illinois energy centers are now owned by AER. As a part of the transfer of ownership of the Ameren Illinois energy centers, Ameren Illinois contractually agreed to indemnify AER for liabilities associated with asbestos-related claims arising or existing from activities prior to the Genco transfer in 2000 and AERG transfer in 2003. The plant transfer agreements between Ameren Illinois and both Genco and AERG will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The amended agreements will provide that Ameren Illinois will continue to retain asbestos exposure related-liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after it takes ownership of New AER. Any asbestos-related claims arising from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, which there are currently none, will be retained by Ameren. See Note 2 - Held for Sale for additional information.

 

EEI was not included in the plant transfer agreements with Ameren Illinois discussed above. As of March 31, 2012, five asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

 

A-40



 

Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit.  In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final.  During the second quarter of 2010, AER began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to its generation operations.  The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits.  In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois’ position that EEI did not qualify for the manufacturing exemption it used during 2010.  EEI is challenging the state of Illinois’ position.  In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue.  AER does not believe that it is probable that the state of Illinois will prevail and therefore has not recorded a charge to earnings for the loss contingency.  From the second quarter of 2010 through December 31, 2011, AER claimed manufacturing exemptions and credits of $27 million, which represents the maximum potential tax liability, excluding any penalties assessed or interest accrued.

 

AER did not claim any additional manufacturing exemptions or credits in 2012 and does not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue.  AER is reserving the right to apply for applicable refunds at a later date.

 

Ameren will retain responsibility for this contingent liability after the divestiture of New AER is completed.

 

Medina Valley Asset Sale

In February 2012, AER completed the sale of the Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement were met.  AER recognized a $10 million pretax gain from this sale.  In October 2012, the buyer of the Medina Valley energy center asserted that AER has not met all the terms of the sale agreement.  During the first quarter of 2013, AER concluded it was no longer probable it will receive the additional $1 million associated with this sale and therefore expensed the receivable amount.

 

9.                                      Asset Impairments

 

Asset Impairments on the statement of operations and comprehensive income (loss) for the three months ended March 31, 2013, and 2012 were $207 million and $628 million, respectively. See Note 2 — Assets Held for Sale for information regarding the March 31, 2013 impairment. The impairments did not result in a violation of any debt covenants or counterparty agreements.

 

AER evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  Whether an 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, AER would recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.

 

AER experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices.

 

A-41



 

Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended March 31, 2013, and 2012

 

(dollars in millions)

 

In addition, environmental regulations have resulted in significant investment requirements over the same time frame.  During the first quarter of 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR.  As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012.  The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of the Newton energy center scrubber project, caused AER to evaluate, during the first quarter of 2012, whether the carrying values of its coal-fired energy centers were recoverable.  The carrying value of AERG’s Duck Creek energy center’s exceeded its estimated undiscounted future cash flows.  As a result, AER recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of that energy center to its estimated fair value during the first quarter of 2012.

 

Key assumptions used in the determination of estimated undiscounted cash flows of AER’s long-lived assets tested for impairment included the forward price projections for energy and fuel costs, the expected life of the energy center, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate, were used to estimate the fair value of the long-lived assets of the Duck Creek energy center. The fair value estimate of the long-lived assets of the Duck Creek energy center was based on the income approach, which considers discounted future cash flows. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.

 

After the impairment of the Elgin, Gibson City, and Grand Tower energy centers in the first quarter of 2013, AER believed the carrying value of its energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion.  However, under the applicable accounting guidance, an asset is not deemed impaired, and no impairment loss is recognized, unless the asset’s carrying value exceeds the estimated undiscounted future cash flows, even if the carrying value of the asset exceeds estimated fair value. AER could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets as a result of factors outside its control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of AER’s energy centers, and also as a result of factors that may be within its control, such as a  failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

 

A-42



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

Index

 

 

 

Page(s)

 

 

 

Glossary of Terms and Abbreviations

 

A-43 – 44

 

 

 

Independent Auditor’s Report

 

A-45

 

 

 

Consolidated Financial Statements

 

 

 

 

 

Statement of Operations and Comprehensive Income (Loss)

 

A-46

 

 

 

Balance Sheet

 

A-47

 

 

 

Statement of Cash Flows

 

A-48

 

 

 

Statement of Equity

 

A-49

 

 

 

Notes to Financial Statements

 

A-50 – A-109

 



Table of Contents

 

GLOSSARY OF TERMS AND ABBREVIATIONS

 

Ameren - Ameren Corporation and its subsidiaries on a consolidated basis.  In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

 

Ameren Illinois - Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois, doing business as Ameren Illinois.

 

Ameren Missouri - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri, doing business as Ameren Missouri.

 

AER - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that operates a merchant electric generation and marketing business in Illinois, including Genco, AERG, Marketing Company and Medina Valley through March 13, 2013.  Medina Valley was distributed from AER to Ameren on March 14, 2013.  On October 1, 2010, AERG stock was distributed to Ameren, which then contributed it to AER, thereby making AERG a subsidiary of AER.

 

AERG - AmerenEnergy Resources Generating Company, a CILCO subsidiary until October 1, 2010, that operates a merchant electric generation business in Illinois.  On October 1, 2010, AERG stock was distributed to Ameren and subsequently contributed by Ameren to AER, which resulted in AERG becoming a subsidiary of AER.

 

AFS - Ameren Energy Fuels and Services Company, an AER subsidiary that procured fuel and natural gas and managed the related risks for Ameren prior to January 1, 2011.  Effective January 1, 2011, the functions previously performed by AFS were assumed by Ameren Missouri, Ameren Illinois and AER.

 

ARO - Asset retirement obligations.

 

ATXI - Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets.

 

AMS - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

 

CAIR - Clean Air Interstate Rule.

 

CCR - Coal combustion residuals.

 

CILCO - Central Illinois Light Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric transmission and distribution business, a merchant electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business. CILCO merged with, and into CIPS, which was renamed Ameren Illinois, on October 1, 2010. Immediately after the merger, Ameren Illinois distributed the common stock of AERG to Ameren Corporation.

 

CIPS — Central Illinois Public Service Company, an Ameren Corporation subsidiary which was renamed Ameren Illinois Company in 2010. CIPS’ energy centers were transferred to Genco in 2000.

 

CSAPR - Cross-State Air Pollution Rule.

 

CT - Combustion turbine electric energy center used primarily for peaking capacity.

 

EEI - Electric Energy, Inc., an 80%-owned Genco subsidiary that operates merchant electric generation energy centers and FERC-regulated transmission facilities in Illinois.  The remaining 20% ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.

 

EPA - Environmental Protection Agency, a United States government agency.

 

ERISA - Employee Retirement Income Security Act of 1974, as amended.

 

FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

 

FERC - Federal Energy Regulatory Commission, a United States government agency.

 

GAAP - Generally accepted accounting principles in the United States of America.

 

A-43



Table of Contents

 

Genco - Ameren Energy Generating Company, an AER subsidiary that operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI.

 

IEIMA - Illinois Energy Infrastructure Modernization Act, an Illinois law that established a performance-based formula process for determining electric delivery service rates.  Ameren Illinois elected to participate in this regulatory framework in 2012, which will require it to make incremental capital expenditures to modernize its electric distribution system over a ten-year period, to meet performance standards, and to create jobs in Illinois, among other things.

 

IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.

 

IPH - Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy, Inc.

 

Marketing Company - Ameren Energy Marketing Company, an AER subsidiary that markets power for Genco, AERG, and EEI.

 

MATS - Mercury and Air Toxics Standards.

 

Medina Valley - AmerenEnergy Medina Valley Cogen LLC, an AER subsidiary through March 13, 2013, which owned a 40-megawatt natural gas-fired electric energy center.  This energy center was sold in February 2012.  This company was distributed from AER to Ameren on March 14, 2013.

 

MW - Megawatt.

 

Megawatthour or MWh - One thousand kilowatthours.

 

MISO - Midwest Independent Transmission System Operator, Inc., an RTO. Renamed Midcontinent Independent System Operator, Inc., on April 26, 2013.

 

Moody’s - Moody’s Investors Service Inc., a credit rating agency.

 

MPS - Multi-Pollutant Standard, a compliance alternative within Illinois law covering reductions in emissions of SO2, NOx, and mercury, which Genco, EEI, and AERG elected in 2006.

 

New AERA limited liability company to be formed as a direct wholly owned subsidiary of AER. New AER will be acquired by IPH and will include substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.

 

NOX - Nitrogen dioxide.

 

NPNS - Normal purchases and normal sales.

 

NSR - New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.

 

OCI - Other comprehensive income (loss) as defined by GAAP.

 

PPA - Pension Protection Act of 2006.

 

PUHCA 2005 — The Public Utility Holding Company Act of 2005.

 

RFP - Request for proposal.

 

S&P - Standard & Poor’s Ratings Services, a credit rating agency.

 

SO2 - Sulfur dioxide.

 

A-44



Table of Contents

 

Independent Auditor’s Report

 

To the Board of Directors and Shareholders of Ameren Corporation:

 

We have audited the accompanying consolidated financial statements of Ameren Energy Resources Company, LLC (a subsidiary of Ameren Corporation) and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), of equity and of cash flows for each of the three years in the period ended December 31, 2012.

 

Management’s Responsibility for the Consolidated Financial Statements

 

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

 

Auditor’s Responsibility

 

Our responsibility is to express an opinion on the consolidated financial statements based on our audits.  We conducted our audits in accordance with auditing standards generally accepted in the United States of America and in accordance with the auditing 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 consolidated financial statements are free from material misstatement.

 

An audit includes performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements.  The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error.  In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the consolidated financial statements in order to design 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.  Accordingly, we express no such opinion.  An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.  We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

 

Opinion

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ameren Energy Resources Company, LLC and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

 

/s/ PricewaterhouseCoopers LLP

 

 

PricewaterhouseCoopers LLP

 

 

St. Louis, Missouri

May 6, 2013

 

A-45



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Statement of Operations and Comprehensive Income (Loss)

Years Ended December 31, 2012, 2011 and 2010

 

(in millions)

 

 

 

2012

 

2011

 

2010

 

Operating revenues

 

 

 

 

 

 

 

Electric

 

$

1,360

 

$

1,600

 

$

1,694

 

Other

 

 

 

7

 

Total operating revenues

 

1,360

 

1,600

 

1,701

 

Operating expenses

 

 

 

 

 

 

 

Fuel

 

655

 

702

 

692

 

Purchased power

 

201

 

231

 

225

 

Other operations and maintenance

 

259

 

281

 

299

 

Impairment and other charges

 

698

 

37

 

589

 

Depreciation and amortization

 

108

 

143

 

147

 

Taxes other than income taxes

 

25

 

24

 

27

 

Total operating expenses

 

1,946

 

1,418

 

1,979

 

Operating income (loss)

 

(586

)

182

 

(278

)

Other income and expenses

 

 

 

 

 

 

 

Miscellaneous income

 

1

 

1

 

3

 

Miscellaneous expense

 

1

 

1

 

2

 

Total other income

 

 

 

1

 

Interest charges

 

95

 

105

 

133

 

Income (loss) before income taxes

 

(681

)

77

 

(410

)

Income taxes (benefit)

 

(278

)

35

 

2

 

Net income (loss)

 

(403

)

42

 

(412

)

Less: Net income (loss) attributable to noncontrolling interest

 

(7

)

1

 

3

 

Net income (loss) attributable to Ameren Energy Resources Company, LLC

 

$

(396

)

$

41

 

$

(415

)

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(403

)

$

42

 

$

(412

)

Other comprehensive income (loss), net of taxes

 

 

 

 

 

 

 

Unrealized net gain on derivative hedging instruments, net of income taxes of $24, $18, and $40, respectively

 

43

 

26

 

57

 

Reclassification adjustments for derivative gains included in net income, net of income taxes of $82, $74, and $71, respectively

 

(143

)

(108

)

(102

)

Pension and other postretirement activity, net of income taxes (benefit) of $28, $(18), and $(1), respectively

 

40

 

(26

)

(6

)

Total comprehensive (loss), net of taxes

 

(463

)

(66

)

(463

)

Comprehensive income (loss) attributable to noncontrolling interest

 

1

 

(4

)

2

 

Total comprehensive (loss) attributable to Ameren Energy Resources Company, LLC, net of taxes

 

$

(464

)

$

(62

)

$

(465

)

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Balance Sheet

December 31, 2012 and 2011

 

(in millions)

 

 

 

2012

 

2011

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

25

 

$

8

 

Advances to money pool

 

40

 

74

 

Accounts receivable — trade

 

47

 

48

 

Accounts and note receivable — affiliates

 

34

 

32

 

Unbilled revenue

 

31

 

39

 

Miscellaneous accounts and notes receivable

 

24

 

21

 

Materials and supplies

 

135

 

165

 

Mark-to-market derivative assets

 

102

 

65

 

Mark-to-market derivative assets — Ameren Illinois

 

 

200

 

Other current assets

 

31

 

11

 

Total current assets

 

469

 

663

 

Property and plant, net

 

2,622

 

3,279

 

Other assets

 

85

 

87

 

Total assets

 

$

3,176

 

$

4,029

 

Liabilities and equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Borrowings from money pool

 

$

298

 

$

348

 

Accounts and wages payable

 

92

 

101

 

Accounts payable — affiliates

 

35

 

38

 

Current portion of tax payable — Ameren Illinois

 

6

 

8

 

Taxes accrued

 

18

 

19

 

Mark-to-market derivative liabilities

 

63

 

39

 

Other current liabilities

 

33

 

28

 

Total current liabilities

 

545

 

581

 

Long-term debt, net

 

824

 

824

 

Deferred credits and other liabilities

 

 

 

 

 

Accumulated deferred income taxes, net

 

349

 

635

 

Accumulated deferred investment tax credits

 

2

 

3

 

Notes payable — Ameren

 

425

 

425

 

Tax payable — Ameren Illinois

 

39

 

56

 

Asset retirement obligations

 

97

 

97

 

Accrued pension and other postretirement benefits

 

40

 

92

 

Other deferred credits and liabilities

 

41

 

39

 

Total deferred credits and other liabilities

 

993

 

1,347

 

Commitments and contingencies (Notes 11, 12 and 14)

 

 

 

 

 

Equity

 

 

 

 

 

Common stock, no par value, 10,000 shares authorized — 2,000 shares outstanding

 

 

 

Other paid-in capital

 

1,479

 

1,479

 

Accumulated deficit

 

(692

)

(296

)

Accumulated other comprehensive income

 

19

 

87

 

Total Ameren Energy Resources Company, LLC equity

 

806

 

1,270

 

Noncontrolling interest

 

8

 

7

 

Total equity

 

814

 

1,277

 

Total liabilities and equity

 

$

3,176

 

$

4,029

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Statement of Cash Flows

Years Ended December 31, 2012, 2011 and 2010

 

(in millions)

 

 

 

2012

 

2011

 

2010

 

Cash flows from operating activities

 

 

 

 

 

 

 

Net income (loss)

 

$

(403

)

$

42

 

$

(412

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities

 

 

 

 

 

 

 

Impairment and other charges

 

698

 

37

 

589

 

Net mark-to-market (gain) loss on derivatives

 

35

 

11

 

(11

)

Gain on sales of properties

 

(11

)

(12

)

(5

)

Depreciation and amortization

 

108

 

145

 

165

 

Amortization of debt issuance costs and premium/discounts

 

4

 

5

 

8

 

Deferred income taxes and investment tax credits, net

 

(268

)

53

 

(3

)

Other

 

13

 

2

 

6

 

Changes in assets and liabilities

 

 

 

 

 

 

 

Receivables

 

3

 

43

 

85

 

Materials and supplies

 

32

 

(1

)

59

 

Accounts and wages payable

 

(1

)

(13

)

(44

)

Taxes accrued

 

(1

)

 

 

Assets, other

 

(2

)

5

 

(23

)

Liabilities, other

 

(18

)

(51

)

(42

)

Pension and other postretirement benefits

 

2

 

(2

)

4

 

Net cash provided by operating activities

 

191

 

264

 

376

 

Cash flows from investing activities

 

 

 

 

 

 

 

Capital expenditures

 

(178

)

(152

)

(101

)

Money pool advances, net

 

34

 

(49

)

48

 

Proceeds from sale of properties

 

22

 

52

 

20

 

Other

 

(2

)

 

 

Net cash used in investing activities

 

(124

)

(149

)

(33

)

Cash flows from financing activities

 

 

 

 

 

 

 

Transfers from parent, net

 

 

44

 

25

 

Capital issuance costs

 

 

 

(6

)

Credit facility borrowings, net

 

 

(100

)

100

 

Money pool borrowings, net

 

(50

)

262

 

19

 

Notes payable — affiliates

 

 

(320

)

(281

)

Redemptions of long-term debt

 

 

 

(200

)

Net cash used in financing activities

 

(50

)

(114

)

(343

)

Net change in cash and cash equivalents

 

17

 

1

 

 

Cash and cash equivalents

 

 

 

 

 

 

 

Beginning of year

 

8

 

7

 

7

 

End of year

 

$

25

 

$

8

 

$

7

 

Cash paid (refunded) during the year

 

 

 

 

 

 

 

Interest (net of $13, $3 and $6, capitalized, respectively)

 

$

89

 

$

97

 

$

102

 

Income taxes, net

 

(9

)

(15

)

30

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Consolidated Statement of Equity

Years Ended December 31, 2012, 2011 and 2010

 

(in millions)

 

 

 

2012

 

2011

 

2010

 

Common Stock

 

$

 

$

 

$

 

Other paid-in capital

 

 

 

 

 

 

 

Beginning of year

 

1,479

 

1,468

 

1,463

 

Transfers from parent (a)

 

 

11

 

5

 

Other paid-in capital, end of year

 

1,479

 

1,479

 

1,468

 

Retained earnings (accumulated deficit)

 

 

 

 

 

 

 

Beginning of year

 

(296

)

(337

)

78

 

Net income (loss) attributable to Ameren Energy Resources Company, LLC

 

(396

)

41

 

(415

)

Accumulated deficit, end of year

 

(692

)

(296

)

(337

)

Accumulated other comprehensive income

 

 

 

 

 

 

 

Derivative financial instruments, beginning of year

 

124

 

206

 

251

 

Change in derivative financial instruments

 

(100

)

(82

)

(45

)

Derivative financial instruments, end of year

 

24

 

124

 

206

 

Deferred retirement benefit costs, beginning of year

 

(37

)

(16

)

(11

)

Change in deferred retirement benefit costs

 

32

 

(21

)

(5

)

Deferred retirement benefit costs, end of year

 

(5

)

(37

)

(16

)

Total accumulated other comprehensive income, end of year

 

19

 

87

 

190

 

Total Ameren Energy Resources Company, LLC equity

 

$

806

 

$

1,270

 

$

1,321

 

Noncontrolling interest

 

 

 

 

 

 

 

Beginning of year

 

7

 

11

 

9

 

Net income (loss) attributable to noncontrolling interest holder

 

(7

)

1

 

3

 

Other comprehensive income (loss) attributable to noncontrolling interest holder

 

8

 

(5

)

(1

)

End of year

 

8

 

7

 

11

 

Total equity

 

$

814

 

$

1,277

 

$

1,332

 

 


(a)         Includes noncash transfers related to entity reorganizations of $ -, $(1), and $(52), respectively, as well as $32 accrued capital contribution from Ameren at December 31, 2010, received in January 2011.

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

1.                            Nature of Operations and Basis of Presentation

 

Company

 

AER is a subsidiary of Ameren, a public utility holding company under PUHCA 2005, administered by the FERC.  AER is headquartered in Collinsville, Illinois.  These consolidated financial statements represent the consolidated results of operations, financial position and cash flows of AER and its subsidiaries as of and for the years ended December 31, 2012, and 2011. For the year ended December 31, 2010, these financial statements are prepared on a combined basis, as if all legal entities, which comprised AER as of October 1, 2010, when AERG was contributed to AER from an Ameren subsidiary, had been part of AER at the beginning of 2010. All references herein to “consolidated” financial statements refer to the consolidated financial statements as of and for the years ended December 31, 2012 and 2011, and the combined financial statements for the year ended December 31, 2010.

 

AER is a merchant electric generation and marketing business operating in Illinois.  AER’s principal subsidiaries are Genco, AERG, Medina Valley (through March 13, 2013), and Marketing Company.  Genco has an 80% ownership interest in EEI.  Through the end of 2012, some AMS employees were included within AER’s business services group, which provides back office, controller, pricing, analytical support, engineering services, and selected information technology services for AER and its subsidiaries. On December 31, 2012, the 102 AMS business services group employees were transferred from AMS to either Genco, AERG, or Marketing Company through an internal reorganization.  Similarly, AFS had a business services group through December 31, 2010, that procured fuel commodities and managed the related risks of those commodities. On January 1, 2011, AER-related services previously performed by AFS were transferred to Marketing Company. Operationally, AER’s energy centers generated 25.7 million megawatthours, 29.1 million megawatthours, and 29.6 million megawatthours during 2012, 2011, and 2010, respectively.

 

In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which AER is a part.  Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, AER estimated, at that time, it was more likely than not that Genco would sell its Elgin energy center for liquidity purposes within two years.  This change in assumption resulted in a noncash long-lived asset impairment charge during the fourth quarter of 2012 relating to the Elgin energy center.  See Note 13 — Impairment and Other Charges for additional information about the first and fourth quarter of 2012 impairments.  AER’s long-lived assets were not classified as held-for-sale under authoritative accounting guidance as all criteria to qualify for that presentation were not met as of December 31, 2012.  Specifically, AER did not consider it probable at December 31, 2012, that a disposition of an energy center would occur within one year.

 

On March 14, 2013, Ameren entered into a transaction agreement to divest its merchant generation business through New AER to IPH.  Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of Genco’s Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval.  Both March 2013 transactions are regarded as subsequent events to the accompanying December 31, 2012 consolidated financial statements.  On March 14, 2013, Medina Valley was transferred out of AER and became a direct subsidiary of Ameren.  See Note 14 — Subsequent Events for additional information.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Basis of Presentation

 

These consolidated financial statements reflect the historical results of operations, financial position, and cash flows of AER for the periods presented.  The consolidated statement of operations reflects intercompany expense allocations made to AER by AMS, an Ameren subsidiary that provides support services to Ameren and its subsidiaries, and by other Ameren affiliated entities for certain corporate functions historically provided by these entities during the periods presented.  While management considers these allocations to have been made on a reasonable basis, the allocations presented do not necessarily reflect the expenses that would have been incurred had AER operated as a stand-alone business.  See Note 11 - Related Party Transactions for further information on expenses allocated to AER.  Interest expense shown in the consolidated statements of operations reflects the interest expense associated with the aggregate direct third-party borrowings and interest-bearing amounts due to affiliate borrowings for each period presented.  Additionally, the consolidated financial statements include the costs associated with AER’s participation in Ameren’s single-employer pension and postretirement benefit plans.  The consolidated financial position, results of operations and cash flows of AER could differ from those that would have resulted had AER operated autonomously or independently of Ameren and its subsidiaries.

 

See the Glossary of Terms and Abbreviations at the beginning of this report for a definition of terms and abbreviations used throughout this report.

 

2.                            Summary of Significant Accounting Policies

 

The AER financial statements were prepared on a consolidated basis.  All significant intercompany transactions have been eliminated.  All tabular dollar amounts are in millions, unless otherwise indicated.

 

AER’s accounting policies conform to GAAP.  The financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in management’s opinion, for a fair presentation of the Company’s results.  The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions.  Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods.  Actual results could differ from those estimates.

 

Cash and Cash Equivalents

 

Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Materials and Supplies

 

Materials and supplies are recorded at the lower of cost or market.  Cost is determined using the average-cost method.  Materials and supplies are capitalized as inventory when purchased and then expensed when used or capitalized when installed as plant assets, as appropriate.  The following table presents a breakdown of materials and supplies at December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Fuel (a)

 

$

78

 

$

102

 

Other materials and supplies

 

57

 

63

 

 

 

$

135

 

$

165

 

 


(a)         Consists of coal, natural gas, and oil.

 

Property and Plant

 

AER capitalizes the cost of additions to, and betterments of, units of property and plant.  The cost includes labor, material, applicable taxes, and overhead.  Interest incurred during construction is capitalized as a cost of AER assets.  Maintenance expenditures are expensed as incurred.  When units of depreciable property are retired in the normal course of business, the original costs, less salvage values, are charged to accumulated depreciation.  Asset removal costs incurred that do not constitute legal obligations are expensed as incurred.  See AROs below and Note 3 - Property and Plant, Net, for additional information.

 

Depreciation

 

Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property.  The provision for depreciation in 2012, 2011 and 2010 generally ranged from 2% to 4% of the average depreciable cost.

 

Goodwill and Intangible Assets

 

Goodwill

 

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired.  AER goodwill related to the acquisition of AERG and Medina Valley in 2003, as well as the acquisition of an additional 20% EEI ownership interest in 2004.  AER conducted an interim goodwill impairment test in the third quarter of 2010.  That test resulted in the impairment of all of AER’s goodwill.  See Note 13 — Impairment and Other Charges for additional information.

 

Intangible Assets

 

AER classifies emission allowances and renewable energy credits as intangible assets.  AER evaluates intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.  See Note 13 — Impairment and Other Charges for additional information including the intangible asset impairments recorded in 2011 and 2010.  The book value of AER’s emission allowances and renewable credits were $2 million and less than $1 million recorded in “Other assets” on the balance sheet at December 31, 2012, and 2011, respectively.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations.  Amortization expense recorded in connection with the usage of emission allowances and renewable energy credits, net of gains from emission allowance sales, was less than $1 million, $3 million, and $21 million during the years ended December 31, 2012, 2011, and 2010, respectively.

 

Impairment of Long-Lived Assets

 

AER evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  Whether an 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, AER recognizes an impairment charge equal to the carrying value of the assets in excess of estimated fair value.  In the period in which AER determines an asset meets the held for sale criteria, AER records an impairment charge to the extent the book value exceeds its fair value less cost to sell.  During 2012, 2011, and 2010, AER recorded pretax long-lived asset impairment charges of $698 million, $26 million and $101 million, respectively, to reduce the carrying value of certain energy centers to their estimated fair values.  See Note 13 - Impairment and Other Charges and Note 14 — Subsequent Events for additional information.

 

Environmental Costs

 

Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated.  Estimated environmental expenditures are regularly reviewed and updated.  Generally, costs are expensed.  If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.  For additional information, see Note 12 - Commitments and Contingencies.

 

Unamortized Debt Discount, Premium, and Expense

 

Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.

 

Revenue

 

Operating Revenues

 

AER records operating revenue for electricity when it is delivered to customers.  AER accrues an estimate of electric revenues for service rendered but unbilled at the end of each accounting period.

 

Trading Activities

 

AER presents the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues - Electric and Other.  See Note 7 - Derivative Financial Instruments for additional information.

 

Accounting for MISO Transactions

 

MISO-related purchase and sale transactions are recorded using settlement information provided by MISO.  These purchase and sale transactions are accounted for on a net hourly position.  AER records net purchases in a single hour in Operating Expenses - Purchased Power and net sales in a single hour in Operating Revenues - Electric in its statements of operations.  On occasion, prior-

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof.  In these cases, AER recognizes expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated, and AER recognizes revenues once the resettlement is received.

 

Stock-Based Compensation

 

Ameren sponsors a long-term incentive plan for eligible employees in which AER employees participate.  The plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.  Stock-based compensation cost is measured at the grant date based on the fair value of the award.  AER recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period.  AER recognized compensation expense of $5 million, $4 million, and $3 million for the years ended December 31, 2012, 2011, and 2010, respectively, and a related tax benefit of $2 million, $1 million and $1 million for the years ended December 31, 2012, 2011, and 2010, respectively.  The pretax compensation expense is included in the consolidated statement of operations within “Other operation and maintenance” expenses.

 

Income Taxes

 

AER is party to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities.  The tax allocation agreement specifies that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax.  Any net benefit attributable to the Parent is reallocated to other members.  That allocation is treated as a contribution of capital to the party receiving the benefit and is reflected in other paid-in capital in the statement of equity.

 

Income taxes are presented on a separate return basis as if AER were a stand-alone entity.  Historically, AER operations have been included in the Ameren consolidated tax return.  Current income taxes were assumed to be settled with Ameren through equity in the period the related income taxes were recorded.  AER uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance.  Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes.  These deferred tax assets and liabilities are calculated based on statutory tax rates.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Investment tax credits used on tax returns for prior years have been deferred for financial reporting purposes; the credits are being amortized over the useful lives of the related investment.  Deferred income taxes were recorded to reflect the temporary difference between the tax and financial reporting treatment of by the deferred investment tax credit.  See Note 10 - Income Taxes.

 

Noncontrolling Interest

 

AER’s noncontrolling interest comprises the 20% of EEI’s net assets not owned by AER.  This noncontrolling interest is classified as a component of equity separate from AER’s equity in its consolidated balance sheet.

 

Asset Retirement Obligations

 

Authoritative accounting guidance requires AER to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the carrying value of the related long-lived asset.  In subsequent periods, AER is required to make adjustments to AROs based on changes in the estimated fair values of the obligations.  Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset.  Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect AER’s estimates of fair value.  AER has recorded AROs for retirement costs associated with asbestos removal, ash ponds, and river structures.  Also see Note 14 - Subsequent Events for additional information regarding AROs.

 

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Balance at beginning of year

 

$

102

 

$

109

 

Liabilities incurred

 

2

 

(a)

 

Liabilities settled

 

(5

)

(3

)

Accretion

 

6

 

7

 

Change in estimates(b)

 

(1

)

(11

)

Balance at end of year(c)

 

$

104

 

$

102

 

 


(a)              Less than $1 million.

(b)              During 2011, AER changed its estimates for retirement costs of its asbestos removal, river structures, and ash ponds.

(c)               Balance included $7 million and $5 million in “Other current liabilities” on the consolidated balance sheet at December 31, 2012, and 2011, respectively.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Medina Valley

 

In February 2012, AER completed the sale of its Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if all the terms of the sale agreement have been met.  AER recognized a $10 million pretax gain from this sale.  In October 2012, the buyer of the Medina Valley energy center asserted that AER has not met all the terms of the sale agreement.  AER is evaluating the buyer’s claim.  During the first quarter of 2013, AER concluded it was no longer probable it would receive the additional $1 million associated with this sale and thus expensed the receivable during the three months ended March 31, 2013.

 

Other Asset Sales

 

In May 2012, AER completed the sale of a building for cash proceeds of $1 million.  AER recognized a $1 million pretax loss from this sale.

 

In the third quarter of 2012, AER completed various sales of land around its Duck Creek energy center for cash proceeds of $4 million.  AER recognized a $2 million pretax gain from these sales.

 

In 2011, AER sold additional property and assets for cash proceeds of $4 million, which resulted in pretax gains of $4 million.

 

In June 2010, Genco completed the sale of 25% of its Columbia CT energy center to the city of Columbia, Missouri.  Genco received cash proceeds of $18 million and recognized a $5 million pretax gain from the sale.  In June 2011, Genco completed the sale of its remaining interest in the Columbia CT energy center to the city of Columbia, Missouri.  Genco received cash proceeds of $45 million and recognized an $8 million pretax gain from the sale.

 

Each of the pre-tax gains and losses discussed above were recorded within “Other operations and maintenance” expenses on the consolidated statement of operations.

 

Employee Separation and Benefit Plan Events

 

In each of the past three years, AER initiated separation programs to reduce positions under the terms and benefits consistent with its standard management separation program.  AER recorded pretax charges related to these programs of $1 million, $4 million, and $4 million in 2012, 2011 and 2010, respectively.  The 2012 and 2010 charges were recorded in “Other operations and maintenance” expense in the consolidated statement of operations. The 2012 separation program occurred at EEI, where the reduction in employees resulted in a curtailment of the EEI pension and postretirement benefit plans. See Note 9 — Retirement Benefits for additional information. The 2011 charge related to the closure of the Meredosia and Hutsonville energy centers and was recorded in “Impairment and other charges” in the consolidated statement of operations.  See Note 13 — Impairment and Other Charges for additional information.

 

Cancelled Capital Projects

 

AER recorded a pretax charge to earnings of $11 million to write off capitalized costs related to projects that were cancelled in 2012.  The charge was recorded in “Other Operations and Maintenance” expense in the consolidated statement of operations.  These projects included studies related to the installations of scrubbers at certain AER energy centers.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Accounting and Reporting Developments

 

The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact AER.

 

Disclosures about Fair Value Measurements

 

In May 2011, FASB issued additional authoritative guidance regarding fair value measurements.  The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards.  The amendments did not affect AER’s results of operations, financial position, or liquidity, as this guidance only requires additional disclosures.  AER adopted this guidance for the first quarter of 2012.  See Note 8 — Fair Value Measurements for the required additional disclosures.

 

Presentation of Comprehensive Income

 

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements.  The amended guidance changed the presentation of comprehensive income in the financial statements.  It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements.  This guidance was effective for AER beginning in the first quarter of 2012 with retroactive application required.  The implementation of the amended guidance did not affect results of operations, financial position, or liquidity.

 

In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component.  In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes.  The amendments will not affect AER’s results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements.  AER adopted this guidance for the first quarter of 2013.

 

Disclosures about Offsetting Assets and Liabilities

 

In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments.  The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position.  In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions.  The amendments will not affect AER’s results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures.  AER adopted this guidance for the first quarter of 2013.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

3.                            Property and Plant, Net

 

The following table presents property and plant, net, at December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Property and plant, at original cost

 

$

3,713

 

$

4,620

 

Less: Accumulated depreciation and amortization

 

(1,388

)

(1,559

)

 

 

2,325

 

3,061

 

Construction work in progress

 

297

 

218

 

Property and plant, net

 

$

2,622

 

$

3,279

 

 

Accrued capital expenditures were $4 million and $16 million at December 31, 2012, and 2011, respectively, which represent noncash investing activity excluded from the statements of cash flows.

 

4.                            Short-Term Debt and Liquidity

 

The liquidity needs of AER are typically supported through the use of available cash and short-term intercompany borrowings at the discretion of Ameren.  See Note 5 - Long-Term Debt for information regarding restrictions under Genco’s indenture that do not allow Genco to borrow additional funds from external third-party sources if its interest coverage ratio is less than a specified minimum or its debt-to-capital ratio is greater than a specified maximum.  Also see Note 14 - Subsequent Events for information regarding Genco’s amended put option agreement and Ameren’s divestiture of AER.

 

Genco 2010 Credit Agreement

 

On November 14, 2012, Genco’s $500 million multiyear senior unsecured revolving credit facility (the “Genco 2010 Credit Agreement”) was terminated and not renewed.  Should a financing need arise, sources of liquidity include available cash on hand, a return of money pool advances, and money pool borrowings at the discretion of Ameren.  On March 14, 2013, Genco amended and exercised its option to sell three of its natural gas-fired energy centers to Medina Valley for a purchase price of at least $133 million.  With the additional liquidity received through exercising the amended put option agreement, AER’s financing sources are estimated to be adequate to support our operations in 2013.  See Note 11 - Related Party Transactions and Note 14 - Subsequent Events for additional information regarding the amended put option agreement, the asset purchase agreement between Genco and Medina Valley, and Ameren’s divestiture of New AER.

 

The following table summarizes the borrowing activity and relevant interest rates under the 2010 Genco Credit Agreement, prior to its termination, for the years ended December 31, 2012, and 2011:

 

Genco 2010 Credit Agreement ($500 million) (Terminated)

 

2012

 

2011

 

Average daily borrowings outstanding

 

$

 

$

41

 

Outstanding credit facility borrowings at period-end

 

 

 

Weighted-average interest rate

 

%

2.30

%

Peak credit facility borrowings

 

$

 

$

100

 

Peak interest rate

 

%

2.31

%

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Money Pools

 

AER and its subsidiaries participate in money pool agreements that provide for certain short-term cash and working capital requirements.  Separate money pools are maintained for Ameren’s utility and non-state-regulated entities.  AMS is responsible for the operation and administration of the money pool agreements.

 

Non-state-regulated Subsidiaries

 

AER has the ability, subject to Ameren parent company authorization, to access funding from Ameren’s credit agreements and commercial paper programs through a non-state-regulated subsidiary money pool agreement.  The total amount available to AER and other pool participants at any time is reduced by borrowings made by Ameren’s subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources.  The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren’s non-state-regulated activities.  Borrowers receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest.  The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool.  These rates are based on the cost of funds used for money pool advances.  The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2012, was 0.61% (2011 — 0.77% and 2010 — 0.77%).

 

See Note 11 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by AER for the years ended December 31, 2012, 2011 and 2010.

 

Utility

 

AER (through AERG) may participate in the utility money pool only as a lender.  There were no utility money pool advances by AERG during the years ended December 31, 2012, 2011 and 2010.

 

5.                            Long-Term Debt

 

The following table presents long-term debt outstanding as of December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

Genco

 

 

 

 

 

Unsecured notes

 

 

 

 

 

Senior notes Series F 7.95% due 2032

 

$

275

 

$

275

 

Senior notes Series H 7.00% due 2018

 

300

 

300

 

Senior notes Series I 6.30% due 2020

 

250

 

250

 

Total long-term debt, gross

 

825

 

825

 

Less: Unamortized discount and premium

 

(1

)

(1

)

Less: Maturities due within one year

 

 

 

Long-term debt, net

 

$

824

 

$

824

 

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Indenture Provisions and Other Covenants

 

Genco is subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.”  The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations.  However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials.

 

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, to make certain principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external third-party indebtedness.  The following table summarizes these ratios for the 12 months ended and as of December 31, 2012:

 

 

 

Required

 

Actual

 

Genco

 

Ratio

 

Ratio

 

Restricted payment interest coverage ratio(a)

 

>1.75

 

2.60

 

Additional indebtedness interest coverage ratio(b)

 

>2.50

 

2.60

 

Additional indebtedness debt-to-capital ratio(b)

 

<60

%

44

%

 


(a)                        As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.  Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.

(b)                        Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense.  Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.  Other borrowings from third-party external sources are included in the definition of indebtedness and to these incurrence tests.

 

Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

 

As shown in the table above, under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if the interest coverage ratio is less than a specified minimum or if the debt-to-capital ratio is greater than a specified maximum.  During the first quarter of 2013, Genco’s interest coverage ratio fell to a level less than the specified minimum level required for external borrowings, and is expected to remain less than this minimum level through at least 2015.  As a result, Genco’s ability to borrow additional funds from external, third-party sources is restricted.  Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool.  However, borrowings from the money pool are subject to Ameren’s control.  If an intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool would be dependent on consideration by Ameren of the facts and circumstances existing at that time.  During 2013, AER will seek to fund operations internally and therefore seek not to rely on financing from Ameren. See Note 14 — Subsequent Events for information on the transaction that occurred in March 2013, which could impact AER’s liquidity.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

In order for Genco to issue securities in the future, Genco will have to comply with all applicable requirements in effect at the time of any such issuances.

 

Genco’s indenture includes restrictions that prohibit payments of dividends on its common stock.  Specifically, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level.  Based on projections as of December 31, 2012 of operating results and cash flows in 2013 and 2014, Genco did not believe that it would achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014.  As a result, Genco was restricted from paying dividends as of December 31, 2012, and expects to be unable to pay dividends in 2013, 2014, and 2015.  No dividends were paid in 2012, 2011, or 2010.

 

Off-Balance-Sheet Arrangements

 

At December 31, 2012, AER did not have any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business.  Additionally, AER does not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

 

6.                           Other Income and Expenses

 

The following table presents Other Income and Expenses for the years ended December 31, 2012, 2011 and 2010:

 

 

 

2012

 

2011

 

2010

 

Miscellaneous income

 

 

 

 

 

 

 

Interest and dividend income

 

$

1

 

$

1

 

$

3

 

Total miscellaneous income

 

$

1

 

$

1

 

$

3

 

Miscellaneous expense

 

 

 

 

 

 

 

Other

 

$

1

 

$

1

 

$

2

 

Total miscellaneous expense

 

$

1

 

$

1

 

$

2

 

 

7.                            Derivative Financial Instruments

 

AER uses derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, and power.  Such price fluctuations may cause the following:

 

·                       an unrealized appreciation or depreciation of AER’s contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

·                       market values of coal and natural gas inventories that differ from the cost of those commodities in inventory; and

·                       actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The derivatives that AER uses to hedge these risks are governed by AER’s risk management policies for forward contracts, futures, options, and swaps.  AER’s net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required.  The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet AER’s requirements.  Contracts AER enters into as part of its risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

 

The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:

 

 

 

Quantity (in millions)

 

 

 

Accrual & NPNS
Contracts(a)

 

Cash Flow Hedges(b)

 

Other Derivatives(c)

 

Commodity

 

2012

 

2011

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal (in tons)

 

39

 

31

 

 

(d)

 

(d)

7

 

 

(d)

Fuel oils (in gallons)(e)

 

 

(d)

 

(d)

 

(d)

 

(d)

52

 

36

 

Natural gas (in mmbtu)

 

 

(d)

 

(d)

 

(d)

 

(d)

47

 

8

 

Power (in megawatthours)(f)

 

66

 

61

 

9

 

17

 

34

 

30

 

Renewable energy credits

 

1

 

1

 

 

(d)

 

(d)

 

(d)

 

(d)

 


(a)

Accrual contracts include commodity contracts that do not qualify as derivatives.  This includes contracts through December 2017, September 2035, and December 2014 for coal, power, and renewable energy credits, respectively, as of December 31, 2012.

(b)

Contracts through December 2016 for power, as of December 31, 2012.

(c)

Contracts through December 2015, October 2016, April 2015, and December 2016 for coal, fuel oils, natural gas, and power, respectively, as of December 31, 2012.

(d)

Not applicable.

(e)

Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.

(f)

Includes intercompany eliminations.

 

Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies.  See Note 8 - Fair Value Measurements for discussion of AER’s methods of assessing the fair value of derivative instruments.  Many of AER’s physical contracts, such as purchased power contracts, qualify for the NPNS exception to derivative accounting rules.  The revenue or expense recorded in connection with NPNS contracts is recognized at the contract price upon physical delivery.

 

If AER determines that a contract meets the definition of a derivative and is not eligible for the NPNS exception, AER reviews the contract to determine if it qualifies for hedge accounting treatment.  Contracts that qualify for cash flow hedge accounting treatment are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective.  To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of operations and comprehensive income (loss) in the period in which the change occurs.  When the contract is settled or delivered, the net gain or loss is recorded in the statement of operations and comprehensive income (loss).

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Certain derivative contracts are entered into on a regular basis as part of AER’s risk management program but do not qualify for, or AER does not choose to elect, the NPNS exception or hedge accounting.  Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of operations and comprehensive income (loss) in the period in which the change occurs.

 

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement.  AER did not elect to adopt this guidance for any eligible commodity contracts.

 

The following table presents the carrying value and balance sheet classification of all derivative instruments as of December 31, 2012, and 2011:

 

 

 

Balance Sheet Location

 

2012

 

2011

 

Derivative assets designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

 

 

Power

 

Mark-to-market derivative assets

 

$

25

 

$

8

 

 

 

Mark-to-market derivative assets - Ameren Illinois

 

 

142

 

 

 

Other assets

 

14

 

15

 

 

 

Total assets

 

$

39

 

$

165

 

Derivative assets not designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

 

 

Coal

 

Other assets

 

$

1

 

$

 

Fuel oils

 

Mark-to-market derivative assets

 

3

 

11

 

 

 

Other assets

 

1

 

3

 

Natural gas

 

Mark-to-market derivative assets

 

4

 

3

 

Power

 

Mark-to-market derivative assets

 

70

 

43

 

 

 

Mark-to-market derivative assets - Ameren Illinois

 

 

58

 

 

 

Other assets

 

15

 

22

 

 

 

Total assets

 

$

94

 

$

140

 

Derivative liabilities not designated as hedging instruments

 

 

 

 

 

Commodity contracts

 

 

 

 

 

 

 

Coal

 

Mark-to-market derivative liabilities

 

$

9

 

$

 

 

 

Other deferred credits and liabilities

 

4

 

 

Fuel oils

 

Mark-to-market derivative liabilities

 

1

 

1

 

 

 

Other deferred credits and liabilities

 

1

 

 

Natural gas

 

Mark-to-market derivative liabilities

 

3

 

4

 

Power

 

Mark-to-market derivative liabilities

 

50

 

34

 

 

 

Other deferred credits and liabilities

 

17

 

20

 

 

 

Total liabilities

 

$

85

 

$

59

 

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI as of December 31, 2012 and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Cumulative gains (losses) deferred in accumulated OCI:

 

 

 

 

 

Power derivative contracts(a) 

 

$

47

 

$

19

 

Power derivative contracts - affiliates(b) 

 

 

187

 

Interest rate derivative contracts (c)(d) 

 

(7

)

(8

)

 


(a)         Represents net gains associated with power derivative contracts.  These contracts are a partial hedge of electricity price exposure through December 2016 as of December 31, 2012.  In light of market prices at December 31, 2012, net pretax unrealized gains of $32 million are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.  However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices.

(b)         Represents net gains associated with power derivative contracts with affiliates.  These contracts were a partial hedge of electricity price exposure and fully expired as of December 31, 2012.

(c)          Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002.  The swaps covered the first 10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in June 2002.  The balance of the gain was fully amortized as of December 31, 2012.  The carrying value at December 31, 2011 was less than $1 million.

(d)         Includes net losses associated with interest rate swaps at Genco.  The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance.  The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008.  The carrying value at December 31, 2012 and 2011 was a loss of $8 million and $9 million, respectively.  Over the next 12 months, $1.4 million of the loss will be amortized.

 

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction.  Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk.  In all other transactions, AER is exposed to credit risk.  AER’s credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.

 

AER believes that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities.  AER generally enters into the following master trading and netting agreements: (1) International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) North American Energy Standards Board Inc.  Agreement, a standardized contract for the purchase and sale of natural gas.  These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions.  Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Concentrations of Credit Risk

 

In determining its concentrations of credit risk related to derivative instruments, AER reviews its individual counterparties and categorizes each counterparty into one of eight groupings according to the primary business in which each engages.  The following table presents the maximum exposure as of December 31, 2012 and 2011 if counterparty groups were to completely fail to perform on contracts by grouping.  The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

 

 

Affiliates(a)

 

Coal
Producers

 

Commodity
Marketing
Companies

 

Electric
Utilities

 

Financial
Companies

 

Municipalities/
Cooperatives

 

Oil and Gas
Companies

 

Retail
Companies

 

Total

 

2012

 

$

71

 

$

3

 

$

38

 

$

10

 

$

13

 

$

192

 

$

3

 

$

85

 

$

415

 

2011

 

275

 

2

 

4

 

12

 

57

 

194

 

3

 

87

 

634

 

 


(a)              Primarily comprised of Marketing Company’s exposure to Ameren Illinois.

 

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements.  Collateral includes both cash collateral and other collateral held.  The amount of cash collateral held by AER from counterparties and based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements was $3 million, and less than $1 million at December 31, 2012, and 2011, respectively.  Other collateral used to reduce exposure consisted of letters of credit in the amount of $6 million, and $8 million at December 31, 2012, and 2011, respectively.  The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of December 31, 2012, and 2011:

 

 

 

Affiliates(a)

 

Coal
Producers

 

Commodity
Marketing
Companies

 

Electric
Utilities

 

Financial
Companies

 

Municipalities/
Cooperatives

 

Oil and Gas
Companies

 

Retail
Companies

 

Total

 

2012

 

$

68

 

$

1

 

$

29

 

$

4

 

$

11

 

$

185

 

$

 

$

85

 

$

383

 

2011

 

273

 

 

3

 

6

 

43

 

187

 

2

 

86

 

600

 

 


(a)              Primarily comprised of Marketing Company’s exposure to Ameren Illinois.

 

Derivative Instruments With Credit Risk-Related Contingent Features

 

AER’s commodity contracts contain collateral provisions tied to credit ratings.  If Ameren or Genco were to experience an adverse change in its credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required.  The following table presents, as of December 31, 2012, and 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral required to be posted with counterparties.  The additional

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2012 and 2011, respectively, and (2) those counterparties with rights to do so requested collateral:

 

 

 

Aggregate Fair Value of
Derivative Liabilities(a)

 

Cash
Collateral
Posted

 

Potential Aggregate
Amount of Additional
Collateral Required(b)

 

2012

 

$

130

 

$

7

 

$

90

 

2011

 

134

 

9

 

121

 

 


(a)              Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.

(b)              As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.

 

Cash Flow Hedges

 

The following table presents the pretax net gain or loss associated with derivative instruments designated as cash flow hedges for the years ended December 31, 2012, 2011, and 2010:

 

 

 

Gain (Loss)
Recognized
in OCI(a)

 

Location of (Gain)
Loss Reclassified
from Accumulated
OCI into Income(b)

 

(Gain) Loss
Reclassified
from
Accumulated
OCI into
Income(b)

 

Location of
(Gain) Loss
Recognized
in Income(c)

 

Gain (Loss)
Recognized
in Income(c)

 

2012

 

 

 

 

 

 

 

 

 

 

 

Power

 

$

67

 

Operating revenues - electric

 

$

(226

)

Operating revenues - electric

 

$

33

 

Interest rate(d) 

 

 

Interest charges

 

1

 

Interest charges

 

 

2011

 

 

 

 

 

 

 

 

 

 

 

Power

 

$

44

 

Operating revenues - electric

 

$

(182

)

Operating revenues - electric

 

$

(10

)

Interest rate(d) 

 

 

Interest charges

 

(e

)

Interest charges

 

 

2010

 

 

 

 

 

 

 

 

 

 

 

Power

 

97

 

Operating revenues - electric

 

(173

)

Operating revenues - electric

 

(3

)

Interest rate(d) 

 

 

Interest charges

 

(e

)

Interest charges

 

 

 


(a)         Effective portion of gain (loss).

(b)         Effective portion of (gain) loss on settlements.

(c)          Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d)         Represents interest rate swaps settled in prior periods.  The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(e)          Less than $1 million.

 

As part of the 2007 Illinois electric settlement agreement and the subsequent Illinois power procurement processes, Ameren Illinois, a subsidiary of Ameren, entered into financial contracts

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

with Marketing Company.  These financial contracts were derivative instruments.  They were accounted for as cash flow hedges by Marketing Company.  Marketing Company recorded the fair value of the contracts on its balance sheet and the changes to the fair value in OCI.  As of December 31, 2012, these contracts had fully expired.  See Note 11 - Related Party Transactions for additional information on these financial contracts.

 

Other Derivatives

 

The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012, and 2011:

 

 

 

Location of (Gain) Loss

 

Gain (Loss) Recognized in Income

 

 

 

Recognized in Income

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Coal

 

Operating expenses - Fuel

 

$

(12

)

$

––

 

$

––

 

Fuel oils

 

Operating expenses - Fuel

 

(11

)

(1

)

9

 

Natural gas

 

Operating expenses - Fuel

 

2

 

2

 

(1

)

Power

 

Operating revenues - Electric

 

(47

)

(2

)

6

 

 

 

 

 

$

(68

)

$

(1

)

$

14

 

 

8.                            Fair Value Measurements

 

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  AER uses various methods to determine fair value, including market, income, and cost approaches.  With these approaches, AER adopts certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation.  Inputs to valuation can be readily observable, market-corroborated, or unobservable.  AER uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value.  All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Level 1                              Inputs based on quoted prices in active markets for identical assets or liabilities.  Level 1 assets and liabilities are primarily exchange-traded derivatives and assets.

 

Level 2                              Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data.  Level 2 assets and liabilities include certain over-the-counter derivative instruments, including financial power transactions.  Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets.  AER’s development and corroboration process entails obtaining multiple quotes or prices from outside sources.  To derive AER’s forward view to price its derivative instruments at fair value, AER averages the midpoints of the bid/ask spreads.  To validate forward prices obtained from outside parties, AER compares the pricing to recently settled market transactions.  Additionally, a review of all sources is performed to identify any anomalies or potential errors.  Further, AER considers the volume of transactions on certain trading platforms in its reasonableness assessment of the averaged midpoint. Power derivatives contracts are valued based upon the use of multiple forward prices provided by third parties.  The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

 

Level 3                              Unobservable inputs that are not corroborated by market data.  Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs.  Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company.  AER values Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions.  AER’s development and corroboration process entails obtaining multiple quotes or prices from outside sources.  As a part of AER’s reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

 

AER performs an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements.  Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement.  All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:

 

 

 

 

 

 

 

 

 

 

 

Range

 

 

 

Fair Value

 

Valuation

 

 

 

[Weighted

 

 

 

Assets

 

Liabilities

 

Technique(s)

 

Unobservable Input

 

Average]

 

Level 3 derivative asset and liability - commodity contracts(a)

 

 

 

 

 

Fuel oils

 

$

1

 

$

 

Discounted cash flow

 

Escalation rate(%)(b)

 

.21 - .68 [.59]

 

 

 

 

 

 

 

 

 

Counterparty credit risk(%)(c)(d)

 

.12 - 1 [1]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3 - 31 [20]

 

 

 

 

 

 

 

Option model

 

Volatilities(%)(b)

 

19 - 27 [23]

 

Power(e)

 

117

 

(58

)

Option model

 

Volatilities(%)(c)

 

13 - 38 [26]

 

 

 

 

 

 

 

 

 

Average bid/ask consensus peak and offpeak pricing - forward/swaps ($/MWh)(c)

 

24 - 45 [36]

 

 

 

 

 

 

 

Discounted cash flow

 

Average bid/ask consensus peak and offpeak pricing - forward/swaps ($/MWh)(c)

 

16 - 52 [32]

 

 

 

 

 

 

 

 

 

Estimated auction price

 

(133,787) - 19,671

 

 

 

 

 

 

 

 

 

for FTRs ($/MW)(b)

 

[249]

 

 

 

 

 

 

 

 

 

Nodal basis ($/MWh)(c)

 

(12) - 1 [(1)]

 

 

 

 

 

 

 

 

 

Counterparty credit risk(%)(c)(d)

 

.04 - 100 [2]

 

 

 

 

 

 

 

 

 

AER credit risk(%)(c)(d)

 

3

 

 


(a)              The derivative asset and liability balances are presented net of counterparty credit considerations.

(b)              Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(c)               Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.

(d)              Counterparty credit risk is only applied to counterparties with derivative asset balances.  AER credit risk is only applied to counterparties with derivative liability balances.

(e)               Power valuations utilize visible third party pricing evaluated by month for peak and off-peak demand through 2016.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

In accordance with applicable authoritative accounting guidance, AER considers nonperformance risk in its valuation of derivative instruments by analyzing the credit standing of its counterparties and considering any counterparty credit enhancements (e.g., collateral).  The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable.  Therefore, AER has factored the impact of its credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities.  Included in AER’s valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings.  AER recorded net losses totaling less than $1 million, net losses totaling $2 million, and net gains of less than $1 million in 2012, 2011 and 2010, respectively, related to valuation adjustments for counterparty default risk.  At December 31, 2012, and 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled less than $1 million and $18 million, respectively.

 

The following table sets forth, by level within the fair value hierarchy, AER’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2012, and 2011:

 

Derivative-Commodity
Contracts(a)

 

Quoted
Prices in

Active
Markets for

Identical
Assets

or Liabilities
(Level 1)

 

Significant
Other

Observable
Inputs
(Level 2)

 

Significant Other
Unobservable
Inputs
(Level 3)

 

Total

 

2012

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Coal

 

$

1

 

$

 

$

 

$

1

 

Fuel oils

 

3

 

 

1

 

4

 

Natural gas

 

4

 

 

 

4

 

Power

 

 

7

 

117

 

124

 

Total

 

$

8

 

$

7

 

$

118

 

$

133

 

Liabilities

 

 

 

 

 

 

 

 

 

Coal

 

$

13

 

$

 

$

 

$

13

 

Fuel oils

 

2

 

 

 

2

 

Natural gas

 

3

 

 

 

3

 

Power

 

 

9

 

58

 

67

 

Total

 

$

18

 

$

9

 

$

58

 

$

85

 

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Derivative-Commodity
Contracts(a)

 

Quoted
Prices in

Active
Markets for

Identical
Assets

or Liabilities
(Level 1)

 

Significant
Other

Observable
Inputs
(Level 2)

 

Significant Other
Unobservable
Inputs
(Level 3)

 

Total

 

2011

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Fuel oils

 

$

13

 

$

 

$

1

 

$

14

 

Natural gas

 

3

 

 

 

3

 

Power

 

 

1

 

287

 

288

 

Total

 

$

16

 

$

1

 

$

288

 

$

305

 

Liabilities

 

 

 

 

 

 

 

 

 

Fuel oils

 

$

1

 

$

 

$

 

$

1

 

Natural gas

 

4

 

 

 

4

 

Power

 

 

1

 

53

 

54

 

Total

 

$

5

 

$

1

 

$

53

 

$

59

 

 


(a)         The derivative asset and liability balances are presented net of counterparty credit considerations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2012, and 2011:

 

 

 

Net Derivative Commodity
Contracts

 

 

 

2012

 

2011

 

Fuel oils

 

 

 

 

 

Beginning balance at January 1

 

$

1

 

$

23

 

Realized and unrealized gains (losses)

 

 

 

 

 

Included in earnings(a)

 

 

15

 

Total realized and unrealized gains

 

 

15

 

Purchases

 

 

1

 

Settlements

 

 

(26

)

Transfers into Level 3

 

1

 

 

Transfers out of Level 3

 

(1

)

(12

)

Ending balance at December 31

 

$

1

 

$

1

 

Change in unrealized gains (losses) related to assets/liabilities held at December 31

 

$

 

$

(7

)

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

 

 

Net Derivative Commodity
Contracts

 

 

 

2012

 

2011

 

Power

 

 

 

 

 

Beginning balance at January 1

 

$

234

 

$

385

 

Realized and unrealized gains (losses)

 

 

 

 

 

Included in earnings(a)

 

30

 

76

 

Included in OCI

 

63

 

(14

)

Total realized and unrealized gains

 

93

 

62

 

Purchases

 

8

 

36

 

Sales

 

2

 

(22

)

Settlements

 

(279

)

(226

)

Transfers into Level 3

 

 

1

 

Transfers out of Level 3

 

1

 

(2

)

Ending balance at December 31

 

$

59

 

$

234

 

Change in unrealized gains (losses) related to assets/liabilities held at December 31

 

$

(17

)

$

(1

)

 


(a)         Net gains and losses on fuel oil derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.

 

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period.  Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges from previous periods.  Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.  For the years ended December 31, 2012 and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts.  The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 2012 and 2011:

 

 

 

2012

 

2011

 

Transfers into Level 3/transfers out of Level 1

 

$

1

 

$

 

Transfers into Level 3/transfers out of Level 2

 

 

1

 

Transfer out of Level 3/transfers into Level 1

 

(1

)

(12

)

Transfers out of Level 3/transfers into Level 2

 

1

 

(2

)

Net fair value of Level 3 transfers

 

$

1

 

$

(13

)

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

AER’s carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy.  Short-term borrowings approximate fair value because of the short-term nature of these instruments.  Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.  The estimated fair value of long-term debt is based on the quoted market prices for same or similar issues for companies with similar credit profiles or on the current rates offered to AER for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

 

The following table presents the carrying amounts and estimated fair values of AER’s long-term debt at December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

 

 

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

 

Long-term debt

 

$

824

 

$

618

 

$

824

 

$

839

 

 

9.                            Retirement Benefits

 

AER employees participate in various pension and postretirement plans.  These include plans exclusively for AER employees as well as those in which AER employees participate along with other Ameren employees.  The primary objective of these plans is to provide eligible employees with pension and postretirement health care and life insurance benefits.  The cost of these plans is included or allocated in the accompanying statement of operations.

 

As discussed above, employees of AER also participate in Ameren’s defined benefit pension plans that cover other non-AER Ameren employees.  The cost of these benefits allocated to AER was $7 million, $6 million and $7 million in 2012, 2011 and 2010, respectively, and was based on the relative participation of AER employees in these plans.  These costs are included in the consolidated statement of operations within “Other operations and maintenance” expenses.  AER’s “Other operations and maintenance” expenses also include pension costs of AMS employees working on behalf of AER, which totaled $4 million, $3 million and $3 million for 2012, 2011, and 2010, respectively.  Similarly, employees of AER also participate in Ameren’s postretirement healthcare and life insurance plans that cover other non-AER Ameren employees.  The cost of these benefits allocated to AER was less than $1 million, $1 million and $1 million in 2012, 2011 and 2010, respectively, and was based on the relative participation of AER employees in these plans.  These costs are included in the consolidated statement of operations within “Other operations and maintenance” expenses.  AER’s “Other operations and maintenance” expenses also include postretirement costs of AMS employees working on behalf of AER, which totaled less than $1 million for each of the years 2012, 2011, or 2010.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The “Accrued pension and other postretirement benefits” liability as of December 31, 2012 and 2011 included in these financial statements does not include the unfunded liabilities associated with Ameren’s pension and other postretirement benefit plans. That “Accrued pension and other postretirement benefits” line only includes the unfunded liabilities associated with the EEI plans.  The balance sheet line item “Accounts payable — affiliates” includes $12 million and $11 million associated with the net payable to Ameren Corporation for the obligations of AER employees that participate in Ameren’s single-employer pension and postretirement plans as of December 31, 2012 and 2011, respectively.

 

EEI employees and retirees participate in EEI’s single-employer pension and other post retirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc.  EEI’s other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc.  The EEI Plans section below only relates to EEI pension and postretirement benefit plans and does not include information relating to Ameren pension and postretirement benefit plans.

 

EEI Plans

 

EEI has a defined benefit pension plan that covers all EEI employees.  Benefits under the plan reflect each employee’s compensation, years of service, and age at retirement. The plan’s assets are invested primarily in bond and equity funds with a trust company.

 

EEI accounts for pension plan activity pursuant to authoritative accounting guidance related to employers’ accounting for pensions.  The PPA affected the manner in which companies administer their pension plans. This legislation increased the funding target for qualified plans, increased the level of retirement benefit security over time and reduced the financial exposure of the Pension Benefit Guaranty Corporation, among other things. Pension contributions are actuarially determined under the PPA.

 

EEI provides certain life insurance and health care benefits for substantially all retired employees.  EEI has various welfare postretirement health care plans, which pay stated percentages of most necessary medical expenses incurred by retirees after subtracting payments by Medicare and after a stated deductible has been met.  Retired employees are eligible for certain postretirement benefits in accordance with plan documents. EEI reserves the right to amend or modify the plan documents, in whole or in part, at any time.

 

EEI records its expense for postretirement benefits other than pensions during each employee’s years of service in accordance with authoritative accounting guidance related to employers’ accounting for postretirement benefits other than pensions.

 

Defined benefit pension and other postretirement plan accounting guidance requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, as an asset or liability in their balance sheets and to recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

EEI manages plan assets in accordance with the “prudent investor” guidelines contained in the ERISA.  EEI’s goal is to earn the highest possible return on plan assets consistent with its tolerance for risk. EEI delegates investment management to specialists in each asset class and, where appropriate, provides the investment manager with specific guidelines, which include allowable and/or prohibited investment types. EEI regularly monitors manager performance and compliance with investment guidelines.

 

The expected return on plan assets for EEI’s pension and postretirement benefit plans 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 and volatility of the various asset classes.  Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolio was developed and adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

 

EEI’s pension plan is funded in compliance with income tax regulations and federal funding requirements. EEI expects to contribute to the pension fund the minimum required contribution under ERISA and the PPA.  From time to time, EEI may decide to contribute more than the minimum required contribution if necessary to achieve certain objectives, such as avoiding benefit restrictions under the PPA.

 

EEI is unable to predict what the future returns will be on the investments, as well as future discount rate levels and the resulting impact on the pension and postretirement benefit expense levels and funding.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Pension Plan

 

AER recognizes the underfunded position of EEI’s pension plan as a liability in its balance sheet with offsetting entries to accumulated OCI. The following table presents the changes in EEI’s pension benefit obligation and plan assets for the years ended December 31, 2012 and 2011: 

 

 

 

2012

 

2011

 

Accumulated benefit obligation at end of year

 

$

99

 

$

92

 

Change in benefit obligation

 

 

 

 

 

Net projected benefit obligation, prior measurement date

 

$

101

 

$

85

 

Service cost

 

2

 

2

 

Interest cost

 

4

 

5

 

Actuarial loss

 

7

 

14

 

Benefits paid

 

(10

)

(5

)

Plan amendments(a)

 

(6

)

 

Plan curtailments(b)

 

2

 

 

Projected benefit obligation, measurement date

 

100

 

101

 

Fair value of plan assets, prior measurement date

 

62

 

58

 

Change in plan assets

 

 

 

 

 

Actual return on plan assets

 

7

 

1

 

Employer contributions to plan

 

7

 

8

 

Benefits paid

 

(10

)

(5

)

Fair value of plan assets, measurement date

 

66

 

62

 

Funded status - deficiency of plan assets over projected benefit obligation

 

$

(34

)

$

(39

)

 


(a)              EEI’s pension plan was amended in 2012 to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees form a traditional, final pay formula to a cash balance formula.

(b)              EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension plan.

 

The following table presents a reconciliation of amounts recognized in the consolidated balance sheets at December 31, 2012 and 2011 related to EEI’s pension plan:

 

 

 

2012

 

2011

 

Prior service cost

 

$

3

 

$

(2

)

Net actuarial loss

 

(31

)

(30

)

Accumulated OCI

 

(28

)

(32

)

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents the changes recognized in OCI for the years ended December 31, 2012, and 2011 related to EEI’s pension plan:

 

 

 

2012

 

2011

 

New prior service cost

 

$

(6

)

$

 

Net loss arising during the period

 

3

 

18

 

Amortization of net actuarial loss

 

(2

)

(1

)

Prior service credit

 

1

 

 

Total recognized in OCI

 

$

(4

)

$

17

 

Total recognized in net periodic benefit cost and OCI

 

$

1

 

$

20

 

 

The estimated prior service (cost) credit and net loss to be amortized from accumulated OCI into net periodic benefit cost over the next fiscal year for the pension plan is less than $1 million and $(2) million, respectively.

 

EEI selects the discount rate using the results of applying a discount rate yield curve model to the expected cash flows from its pension plan.  The yield curve is based on the spot rates that are equivalent to the yields of high-quality, noncallable bonds that have at least $250 million of outstanding issue.  Each year’s projected cash flow is discounted at the spot rate for that year taken from the yield curve.  The single rate that produces the same present value as the discounted cash flows can be referenced in selecting the discount rates for the plans.

 

The following table presents the weighted-average assumptions used to determine EEI’s pension benefit obligations at December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

Discount rate

 

4.00

%

4.50

%

Rate of compensation increase

 

5.97

%

3.98

%

Measurement date

 

December 31, 2012

 

December 31, 2011

 

 

The following table presents the weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31, 2012, 2011 and 2010 related to EEI’s pension plan:

 

 

 

2012

 

2011

 

2010

 

Discount rate

 

 

(a)

5.45

%

5.75

%

Expected long-term rate of return on plan assets

 

8.00

%

8.00

%

8.00

%

Rate of compensation increase

 

3.98

%

3.98

%

3.98

%

Measurement date

 

December 31, 2011

 

December 31, 2010

 

December 31, 2009

 

 


(a)

Used a 4.5% discount rate from January through August. After the curtailment in August, used a 3.5% discount rate for remainder of year.

 

A-77



Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents the components of EEI’s net periodic pension cost for the years ended December 31, 2012, 2011 and 2010:

 

 

 

2012

 

2011

 

2010

 

Service cost

 

$

2

 

$

2

 

$

2

 

Interest cost

 

4

 

5

 

4

 

Expected return on plan assets

 

(5

)

(5

)

(4

)

Amortization of net loss

 

2

 

1

 

 

Effect of curtailment

 

2

 

 

 

Net periodic pension benefit cost

 

$

5

 

$

3

 

$

2

 

 

The following table presents the weighted-average asset allocations for the EEI pension plan as of December 31, 2012 and 2011 by asset category:

 

 

 

Target

 

Plan Assets

 

 

 

Allocation

 

2012

 

2011

 

Equity securities

 

60

%

59

%

60

%

Debt securities

 

40

 

38

 

40

 

Cash

 

 

3

 

 

 

 

100

%

100

%

100

%

 

EEI contributed $7 million to the pension plan during 2012.  EEI anticipates contributing $11 million to the pension plan in 2013.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents expected benefit payments related to the EEI pension plan, which reflect expected future service, as appropriate, that are expected to be paid as of December 31, 2012:

 

Years 

 

 

 

2013

 

$

7

 

2014

 

7

 

2015

 

7

 

2016

 

8

 

2017

 

8

 

2018—2022

 

38

 

 

The following table presents EEI’s pension plan assets measured at fair value on a recurring basis as of December 31, 2012 and 2011. All of EEI’s pension assets were classified as Level 2 in the fair value hierarchy.

 

 

 

2012

 

2011

 

Cash and equivalents

 

$

2

 

$

 

Equity securities

 

 

 

 

 

U.S. Large Capitalization

 

22

 

21

 

U.S. Small Capitalization

 

12

 

11

 

International

 

5

 

5

 

Debt securities

 

 

 

 

 

Bonds

 

25

 

25

 

 

 

$

66

 

$

62

 

 

Investments in EEI’s pension and postretirement benefit plans were stated at fair value as of December 31, 2012 and 2011. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Postretirement Plans

 

The following table presents the changes in EEI’s postretirement benefit (other than pension) obligation and plan assets for the years ended December 31, 2012, and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Benefit obligation, prior measurement date

 

$

112

 

$

83

 

Service cost

 

2

 

2

 

Interest cost

 

4

 

5

 

Actuarial loss

 

16

 

25

 

Benefits and expenses paid

 

(4

)

(3

)

Plan amendments(a)

 

(75

)

 

Plan curtailment(b)

 

(1

)

 

Benefit obligation, measurement date

 

54

 

112

 

Fair value of plan assets, prior measurement date

 

60

 

61

 

Actual return on plan assets

 

6

 

2

 

Benefits paid

 

(4

)

(3

)

Fair value of plan assets, measurement date

 

62

 

60

 

Funded status — surplus (deficiency) of plan assets over projected benefit obligation

 

$

8

(c)

$

(52

)

 


(a)       EEI’s management and union-represented postretirement medical benefit plans were amended in 2012 to adjust for moving to a Medicare Advantage plan.

 

(b)       EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its management postretirement benefits plan.

 

(c)        The Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. was over-funded by $14 million as of December 31, 2012, which was included in AER’s balance sheet in “Other assets”.

 

The following table presents a reconciliation of amounts recognized in the consolidated balance sheets as of December 31, 2012 and 2011:

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Prior service credit

 

$

73

 

$

 

Net actuarial loss

 

(57

)

(48

)

Accumulated OCI

 

16

 

(48

)

 

The estimated prior service credit and net loss to be amortized from accumulated OCI into net periodic benefit costs over the next fiscal year for the EEI postretirement plan is $8 million and ($5 million), respectively.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents the changes recognized in OCI for the years ended December 31, 2012, and 2011 related to EEI’s postretirement plans:

 

 

 

2012

 

2011

 

New prior service cost

 

$

(75

)

$

 

Net loss arising during the period

 

12

 

28

 

Amortization of prior service credit

 

2

 

2

 

Amortization of net loss

 

(3

)

(2

)

Total recognized in OCI

 

$

(64

)

$

28

 

Total recognized in net periodic benefit cost and OCI

 

$

61

 

$

30

 

 

The following table presents the components of the net periodic other postretirement benefit cost for the years ended December 31, 2012, 2011 and 2010:

 

 

 

2012

 

2011

 

2010

 

Service cost

 

$

2

 

$

2

 

$

1

 

Interest cost

 

4

 

5

 

4

 

Expected return on plan assets

 

(4

)

(5

)

(4

)

Amortization of prior service credit

 

(2

)

(2

)

(2

)

Amortization of net loss

 

4

 

2

 

1

 

Net periodic postretirement benefit cost

 

$

4

 

$

2

 

$

 

 

The following table presents weighted-average assumptions used to determine EEI’s postretirement benefit obligations at the measurement date:

 

 

 

2012

 

2011

 

Discount rate

 

4.00

%

4.50

%

Rate of compensation increase (life insurance benefit)

 

5.08

%

3.98

%

Medical trend

 

 

 

 

 

Trend assumed for next year

 

7.96

%

8.30

%

Ultimate trend rate

 

4.50

%

4.50

%

Year that ultimate trend is reached

 

2027

 

2027

 

Measurement date

 

December 31, 2012

 

December 31, 2011

 

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The following table presents weighted-average assumptions used to determine EEI’s postretirement net periodic benefit cost for the measurement date:

 

 

 

2012

 

2011

 

2010

 

Discount rate

 

 

(a)

5.45

%

5.75

%

Expected long-term rate of return on plan assets - Management

 

6.80

%

6.80

%

6.80

%

Expected long-term rate of return on plan assets - Bargaining unit

 

8.00

%

8.00

%

8.00

%

Rate of compensation increase (life insurance benefit)

 

3.98

%

3.98

%

3.98

%

Medical trend

 

 

 

 

 

 

 

Trend assumed for next year

 

8.30

%

8.65

%

9.00

%

Ultimate trend rate

 

4.50

%

4.50

%

4.50

%

Year that ultimate trend is reached

 

2027

 

2027

 

2027

 

Measurement date

 

December 31, 2011

 

December 31, 2010

 

December 31, 2009

 

 


(a)       Used a 4.5% discount rate from January through August.  Used a 3.5% discount rate in September after a curtailment, and used a 3.7% discount rate after a plan amendment at the end of September through the end of the year.

 

The following table presents the weighted-average asset allocations for EEI’s postretirement benefit plan as of the measurement date, by asset category:

 

 

 

 

 

Plan Assets

 

 

 

Target
Allocation

 

2012

 

2011

 

Equity securities

 

60

%

62

%

59

%

Debt securities

 

40

 

36

 

39

 

Cash

 

 

2

 

2

 

 

 

100

%

100

%

100

%

 

EEI did not contribute to the postretirement plans during 2012, 2011 or 2010 and does not expect to contribute to the postretirement plans during 2013.

 

The following table presents expected benefit payments associated with the EEI postretirement plans, which reflect expected future service, as appropriate, that are expected to be paid as of December 31, 2012:

 

Years 

 

 

 

2013

 

$

2

 

2014

 

3

 

2015

 

3

 

2016

 

3

 

2017

 

3

 

2018—2022

 

14

 

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The estimated cost of these future benefits could be significantly impacted by future changes in health care costs, work force demographics, interest rates, or plan changes.  A 1% increase in the assumed health care cost trend rate each year would increase EEI’s aggregate service and interest costs for 2012 by $1 million and the accumulated postretirement benefit obligation at December 31, 2012, by $7 million.  A 1% decrease in the assumed health care cost trend rate each year would decrease EEI’s aggregate service and interest costs for 2012 by $1 million and the accumulated postretirement benefit obligation at December 31, 2012, by $6 million.

 

The following table presents, utilizing the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the EEI postretirement assets measured at fair value on a recurring basis as of December 31, 2012:

 

 

 

Quoted
Prices in
Active
Markets
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Total Assets

 

Cash and cash equivalents

 

$

 

$

1

 

$

1

 

Equity securities

 

 

 

 

 

 

 

U.S. Large Capitalization

 

32

 

 

32

 

International

 

7

 

 

7

 

Debt securities

 

 

 

 

 

 

 

U.S. Treasury and Agency Securities

 

 

11

 

11

 

Municipal bonds

 

 

5

 

5

 

Corporate bonds

 

 

6

 

6

 

 

 

$

39

 

$

23

 

$

62

 

 

The postretirement plans had no investments classified as Level 3 as of December 31, 2012.

 

The following table presents, utilizing the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the EEI postretirement assets measured at fair value on a recurring basis as of December 31, 2011:

 

 

 

Quoted
Prices in
Active
Markets
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Total Assets

 

Cash and cash equivalents

 

$

 

$

1

 

$

1

 

Equity securities

 

 

 

 

 

 

 

U.S. Large Capitalization

 

29

 

 

29

 

International

 

6

 

 

6

 

Debt securities

 

 

 

 

 

 

 

U.S. Treasury and Agency Securities

 

 

19

 

19

 

Municipal bonds

 

 

4

 

4

 

Corporate bonds

 

 

1

 

1

 

 

 

$

35

 

$

25

 

$

60

 

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The EEI postretirement plans had no investments classified as Level 3 as of December 31, 2011.

 

Ameren Defined Contribution Plan

 

Ameren sponsors a 401(k) plan for eligible employees in which AER employees participate.  The plan allows employees to contribute a portion of their compensation in accordance with specific guidelines.  Ameren matched a percentage of the employee contributions up to certain limits.  Ameren’s matching contributions to the 401(k) specific to AER employees totaled $3 million, $3 million, and $3 million in 2012, 2011, and 2010, respectively.  These costs associated with matching of the employee contributions are included in the consolidated statement of operations within “Other operations and maintenance” expenses.

 

10.                     Income Taxes

 

The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011 and 2010:

 

 

 

2012

 

2011

 

2010

 

Statutory federal income tax rate

 

35

%

35

%

35

%

Increases (decreases) from

 

 

 

 

 

 

 

Nondeductible impairment of goodwill

 

 

 

(37

)

Production activities deduction

 

 

 

2

 

State tax

 

6

 

15

 

 

Reserve for uncertain tax positions

 

 

(5

)

 

Effective income tax rate

 

41

%

45

%

(a)

%

 


(a)         Less than 1%.

 

The following table presents the components of income tax expense (benefit) for the years ended December 31, 2012, 2011 and 2010:

 

 

 

2012

 

2011

 

2010

 

Current taxes

 

 

 

 

 

 

 

Federal

 

$

 

$

(12

)

$

(3

)

State

 

(5

)

(5

)

5

 

Deferred taxes

 

 

 

 

 

 

 

Federal

 

(221

)

32

 

3

 

State

 

(51

)

21

 

(2

)

Deferred investment tax credits, amortization

 

(1

)

(1

)

(1

)

Total income tax expense

 

$

(278

)

$

35

 

$

2

 

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011.  The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025.  This corporate income tax rate increase in Illinois increased income tax expense in 2011 by $6 million.

 

The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2012 and 2011:

 

 

 

2012

 

2011

 

Accumulated deferred income taxes, net (liability) asset

 

 

 

 

 

Plant related

 

$

(434

)

$

(648

)

Purchase accounting

 

(37

)

(63

)

Deferred intercompany tax gain/basis step-up

 

36

 

51

 

Deferred benefit costs

 

10

 

40

 

Asset retirement obligations

 

38

 

38

 

Other

 

49

 

(53

)

Total net accumulated deferred income tax liabilities (a)

 

$

(338

)

$

(635

)

 


(a)         Includes $11 million as “Other current assets” recorded in the consolidated balance sheet at December 31, 2012.

 

AER had federal net operating loss carryforwards of $39 million that will begin to expire in 2028 and federal tax credit carryforwards of $1 million that will begin to expire in 2029 included as components of deferred tax assets at December 31, 2012.

 

Uncertain Tax Positions

 

A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2012, 2011 and 2010, is as follows:

 

 

 

2012

 

2011

 

2010

 

Unrecognized tax benefits at beginning of year

 

$

15

 

$

35

 

$

48

 

Increases based on tax positions prior to current year

 

1

 

1

 

5

 

Decreases based on tax positions prior to current year

 

(3

)

(20

)

(21

)

Increases based on tax positions related to current year

 

 

1

 

3

 

Changes related to settlements with taxing authorities

 

 

(1

)

 

Decreases related to the lapse of statute of limitations

 

(1

)

(1

)

 

Unrecognized tax benefits at end of year

 

$

12

 

$

15

 

$

35

 

Total unrecognized tax benefits that, if recognized, would impact the effective tax rates

 

$

2

 

$

2

 

$

6

 

 

AER recognizes interest expense (income) and penalties accrued on tax liabilities on a pre-tax basis as interest charges (income) or miscellaneous expense in the statements of operations.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2012, 2011 and 2010, is as follows:

 

 

 

2012

 

2011

 

2010

 

Liability for interest at beginning of year

 

$

2

 

$

5

 

$

4

 

Interest charges (income)

 

 

(3

)

1

 

Liability for interest at end of year

 

$

2

 

$

2

 

$

5

 

 

As of December 31, 2012, 2011 and 2010, AER had no amount accrued for penalties with respect to unrecognized tax benefits.

 

AER is included in Ameren’s federal income tax return.  In 2011, a final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $11 million for AER, all of which related to temporary items, and therefore did not impact the effective tax rate.  Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service.  Ameren’s federal income tax return for the year 2011 is currently under examination.

 

It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2010.  This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $12 million.  In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits to increase or decrease.  However, AER does not believe any such increases or decreases, including the decreases from the reasonably possible IRS Appeals Office settlement discussed above, would be material to its results of operations, financial position, or liquidity.

 

State income tax returns are generally subject to examination for a period of three years after filing of the return.  The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.  AER does not currently have material state income tax issues under examination, administrative appeals, or litigation.

 

11.                     Related Party Transactions

 

AER has engaged in, and may in the future engage in, transactions with Ameren and other non-AER subsidiaries (“affiliates”) in the normal course of business.  These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings.  Transactions between affiliates are reported as intercompany transactions on AER’s financial statements.  See Note 14 — Subsequent Events for information regarding the divesture of New AER.  As discussed in Note 1 — Nature of Operations and Basis of Presentation to the consolidated financial statements, the financial statements have been derived from the financial statements of Ameren and reflect significant allocations of the costs of the services provided to AER by Ameren and its subsidiaries on a basis that management believes is appropriate.  The consolidated financial position, results of operations and cash flows of AER could differ from those that would have resulted had AER operated autonomously or independently of Ameren and its subsidiaries.  Below are the material related party agreements.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Put Option Agreement

 

On March 28, 2012, Genco entered into a put option agreement with AERG which gave Genco the option to sell to AERG all, but not less than all, of its Grand Tower, Gibson City, and Elgin gas-fired energy centers.  In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million.  As of December 31, 2012, Genco had not exercised the put option, nor did Genco believe it was more likely than not that it would in 2013.

 

On March 14, 2013, the put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley.  On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval.  See Note 14 — Subsequent Events for additional information regarding this transaction and the amended put option.

 

Capacity Supply Agreements

 

In 2009, Ameren Illinois used a RFP process, administered by the IPA, which is a state government agency that has broad authority to assist in the procurement of electric power for Illinois residential and nonresidential customers, to contract capacity for the period from June 1, 2009, through May 31, 2012.  Marketing Company was a winning supplier in Ameren Illinois’ capacity RFP process.  In April 2009, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $4 million, $9 million, and $8 million for the 12 months ending May 31, 2010, 2011 and 2012, respectively.

 

In 2010, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2010 through May 31, 2013.  Marketing Company was a winning supplier in the capacity RFP process.  In April 2010, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $1 million, $2 million, and $3 million for the 12 months ending May 31, 2011, 2012 and 2013, respectively.

 

In 2011, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2011 through May 31, 2014.  Marketing Company was a winning supplier in the capacity RFP process.  In April 2011, Marketing Company contracted to supply less than $1 million of capacity to Ameren Illinois for the 12 months ending May 31, 2012.

 

In 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012 through May 31, 2015.  Marketing Company was a winning supplier in the capacity RFP process.  In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $4 million for the 12 months ending May 31, 2015.

 

Energy Swaps and Energy Products

 

As part of the 2007 Illinois electric settlement agreement arising out of the end of ten years of frozen rates, Ameren Illinois entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of its round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at then-relevant market prices.  These financial contracts did not include capacity, were not load-following products, and did not involve the physical delivery of energy.  These financial contracts

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

were derivative instruments.  They were accounted for as cash flow hedges by AER.  Consequently, AER recorded the fair value of the contracts on its balance sheet and the changes to the fair value in OCI.  See Note 7 - Derivative Financial Instruments for additional information on these derivatives.

 

In 2009, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011.  Marketing Company was a winning supplier in Ameren Illinois’ energy swap RFP process.  In May 2009, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 80,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2011.

 

In 2010, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2010 through May 31, 2013.  Marketing Company was a winning supplier in the financial energy swap RFP process.  In May 2010, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 924,000 megawatthours at approximately $33 per megawatthour during the 12 months ending May 31, 2011, and for approximately 296,000 megawatthours at approximately $40 per megawatthour during the 12 months ending May 31, 2012.

 

In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products that will settle physically from June 1, 2011, through May 31, 2014.  Marketing Company was a winning supplier in Ameren Illinois’ energy product RFP process.  In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements by which Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,000 megawatthours at approximately $37 per megawatthour during the 12 months ending May 31, 2012, approximately 1,841,000 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2013 and approximately 650,000 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2014.

 

In February 2012, a rate stability procurement for energy products that will settle physically was administered by the IPA for the June 2013 through May 2017 period to meet certain requirements for purchased power related to the IEIMA.  Marketing Company was a winning supplier in Ameren Illinois’ energy product procurement process.  In February 2012, Marketing Company and Ameren Illinois entered into energy product agreements pursuant to which Marketing Company will sell and Ameren Illinois will purchase approximately 3,942,000 megawatthours at approximately $30 per megawatthour during the 12 months ending May 31, 2014, approximately 3,504,000 megawatthours at approximately $32 per megawatthour during the 12 months ending May 31, 2015, and approximately 1,317,000 megawatthours at approximately $34 per megawatthour during the 12 months ending May 31, 2016.  The energy product agreements were based on around-the-clock prices.

 

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Table of Contents

 

Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Marketing Company Sale of Trade Receivables to Ameren Illinois

 

In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers’ receivables relating to Ameren Illinois’ delivery service customers who elected to receive power supply from the alternative retail electric supplier.  Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier.  Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions.  As of December 31, 2012, Marketing Company’s receivable from Ameren Illinois for the purchase of trade receivables totaled $5 million.  For the year ended December 31, 2012, Ameren Illinois purchased $35 million of trade receivables from Marketing Company.

 

Transmission Services Agreement

 

Under a transmission services agreement, Marketing Company acquires transmission services from Ameren Illinois and Ameren Transmission Company of Illinois for certain retail and residential customers.

 

Support Services Agreements

 

Ameren Services provides support services to Ameren subsidiaries, including AER.  The cost of support services, including wages and employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.  Where possible, these costs were billed to AER on a specific identification basis.  Otherwise such expenses were allocated based on allocation factors for the type and nature of cost that was allocated.  AER recorded $44 million, $39 million and $47 million in “Other operations and maintenance” expenses relating to costs allocated to AER for the periods ended December 31, 2012, 2011 and 2010, respectively.

 

AFS provided support services to Ameren subsidiaries through December 31, 2010.  Effective January 1, 2011, AER-related services previously performed by AFS are now performed by Marketing Company.  AER no longer provides similar support services to non-AER affiliates.  AER recorded $7 million in other revenues relating to services AFS provided to affiliates for the year ended December 31, 2010.

 

Transportation Agreement

 

Under a gas transportation agreement, Genco acquired gas transportation service from Ameren Missouri, an affiliate, for its CT located in Columbia, Missouri.  Genco’s remaining interests in this CT were sold in 2011 as discussed in Note 2 - Summary of Significant Accounting Policies.

 

Money Pools

 

See Note 4 — Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Intercompany Borrowings

 

On May 1, 2005, Genco issued to Ameren Illinois an amended and restated subordinated promissory note in the principal amount of $249 million with an interest rate of 7.125% per year.  Genco’s subordinated note payable to Ameren Illinois associated with the transfer in 2000 of Ameren Illinois’ electric generating assets and related liabilities to Genco matured on May 1, 2010.  Interest charges for this note recorded by Genco were $1 million for the year ended December 31, 2010.

 

AER had no outstanding direct borrowings from Ameren of at December 31, 2012 and 2011.  AER recorded interest charges of $2 million and $20 million for Ameren direct borrowings for the year ended December 31, 2011 and 2010, respectively.  In addition, at December 31, 2012 and 2011, AER had a $425 million note payable, due May 15, 2014, with Ameren.  AER recorded interest charges of $38 million, $38 million and $29 million related to this borrowing for the years ended December 31, 2012, 2011, and 2010, respectively.  AER had money pool borrowings, net of advances of $258 million and $274 million at December 31, 2012, and 2011, respectively.  AER recorded interest charges of $2 million, $2 million and $-million for years ended December 31, 2012, 2011, and 2010.

 

Parent Guarantees

 

In the ordinary course of business, Ameren enters into various agreements providing financial assurance to third parties on behalf of AER.  At December 31, 2012, Ameren provided the following guarantees to AER:

 

·                        $189 million in guarantees outstanding for physically and financially settled power transactions primarily for Marketing Company counterparties.  Of these guarantees $161 million expire in 2013, $12 million expire in 2014, and $16 million expire thereafter.  Ameren remains obligated under these guarantees, up to the maximum level included in the respective guarantee agreements, after the guarantee expiration date if transactions between the counterparties were in effect at the expiration of the guarantee agreement.  Consequently, Ameren, guarantees may be extended past the expiration dates listed above depending on the future counterparty transactions.

 

·                        $100 million associated with the guarantee agreement between Ameren and AERG entered into on March 28, 2012, relating to the put option agreement between Genco and AERG.  See Note 14 — Subsequent Events for information about the put option agreement.

 

·                        $50 million guarantees with MISO at December 31, 2012, which related to all of Ameren’s MISO market participants.

 

·                        $5 million guarantee to Caterpillar for the asset sale of Medina Valley, that was completed in 2012.

 

Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions).

 

Collateral Postings

 

Under the terms of the Illinois power procurement agreements entered into through an RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance.  The collateral postings are unilateral, which means only the suppliers are required to post collateral.  Therefore, Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral.  As of December 31, 2012, 2011 and 2010, there were no collateral postings required of Marketing Company related to the Illinois power procurement agreements.  Should collateral postings have been required, they would be funded through borrowings from Ameren.

 

Intercompany Property Sales

 

In 2012, Genco completed the sale of land for cash proceeds of $2 million to ATXI.  Genco recognized a $2 million gain from the sale.

 

During 2011, AFS sold property at cost to Ameren Illinois and Ameren Missouri for $2 million in the aggregate.

 

The following table presents the impact on AER of related party transactions for the years ended December 31, 2012, 2011 and 2010.  It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 - Credit Facility Borrowings and Liquidity.

 

Agreement

 

Income Statement Line
Item

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Marketing company agreements with Ameren Illinois

 

Electric revenues

 

$

311

 

$

232

 

$

233

 

Genco gas sales to distribution companies

 

Electric revenues

 

 

 

1

 

AFS support services agreement

 

Other revenues

 

 

 

 

7

 

Total operating revenues

 

 

 

$

311

 

$

232

 

$

241

 

Genco gas transportation agreement with Ameren Missouri

 

Fuel

 

$

1

 

$

1

 

$

1

 

Transmission services provided by Ameren Illinois and Ameren Transmission Company of Illinois to Marketing Company

 

Purchased power

 

$

16

 

$

11

 

$

10

 

AMS support services agreement

 

Other operations and maintenance

 

$

44

 

$

39

 

$

47

 

Interest on note payable to Ameren Illinois

 

Interest charges

 

$

 

$

 

$

1

 

Interest on note payable to Ameren

 

Interest charges

 

38

 

40

 

49

 

Money pool borrowings

 

Interest charges

 

2

 

2

 

 

Total interest charges

 

Interest charges

 

$

40

 

$

42

 

$

50

 

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

12.                     Commitments and Contingencies

 

AER is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money.  AER believes that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Leases

 

AER leases various facilities, office equipment, plant equipment, and rail cars under operating leases.  The following table presents AER’s operating lease obligations at December 31, 2012:

 

 

 

Total

 

2013

 

$

13

 

2014

 

12

 

2015

 

12

 

2016

 

12

 

2017

 

11

 

Thereafter

 

75

 

Total

 

$

135

 

 

Total rental expense, included in operating expenses, for the years ended December 31, 2012, 2011 and 2010 was $18 million, $15 million, and $17 million, respectively.

 

Other Obligations

 

To supply a portion of the fuel requirements of AER’s energy centers, AER has entered into various long-term commitments for the procurement of coal and natural gas.  The table below presents AER’s estimated fuel and other commitments at December 31, 2012.  Included in the “Other” column are minimum purchase commitments under contracts for equipment, design and construction at December 31, 2012.

 

 

 

 

 

Natural

 

 

 

 

 

 

 

Coal

 

Gas

 

Other

 

Total

 

2013

 

$

288

 

$

22

 

$

18

 

$

328

 

2014

 

149

 

4

 

8

 

161

 

2015

 

88

 

2

 

 

90

 

2016

 

88

 

 

 

88

 

2017

 

25

 

 

 

25

 

Thereafter

 

32

 

 

 

32

 

Total

 

$

670

 

$

28

 

$

26

 

$

724

 

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Environmental Matters

 

AER is subject to various environmental laws and regulations enforced by federal, state, and local authorities.  From the beginning phases of siting and development to the ongoing operation of existing or new electric generation and transmission facilities, AER’s activities involve compliance with diverse environmental laws and regulations.  These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling.  Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities.  Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

 

In addition to existing laws and regulations, including the Illinois MPS that applies to AER’s coal-fired energy centers in Illinois, the EPA is developing environmental regulations that will have a significant impact on the electric generating industry.  These regulations could be particularly burdensome for certain companies, including AER, that operate coal-fired energy centers.  Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for fine particulate, SO2, and NOx emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at AER’s energy centers.  The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future.  These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012.  Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years.  Compliance with these environmental laws and regulations could be prohibitively expensive.  If they are, these regulations could require AER to close or to significantly alter the operation of its energy centers, which could have an adverse effect on its results of operations, financial position, and liquidity, including the impairment of long-lived assets.  Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and AER’s assessment of the potential impacts of the EPA’s proposed regulation for CCR and the finalized MATS as of December 31, 2012.  In addition, the estimates assume that CCR will continue to be regarded as nonhazardous.  The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as AER’s evaluation of those impacts is ongoing.  The estimates in the table below could change significantly depending upon a variety of factors including:

 

·                       additional or modified federal or state requirements;

·                       further regulation of greenhouse gas emissions;

·                       revisions to CAIR or reinstatement of CSAPR;

·                       new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

·                       additional rules governing air pollutant transport;

·                       regulations under the Clean Water Act regarding cooling water intake structures or effluent standards;

·                       finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;

·                       new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;

·                       new technology;

·                       expected power prices;

·                       variations in costs of material or labor; and

·                       alternative compliance strategies or investment decisions.

 

 

 

Low

 

High

 

2013

 

$

35

 

$

35

 

2014 - 2017

 

120

 

150

 

2018 - 2022

 

240

 

295

 

Total(a)

 

$

395

 

$

480

 

 


(a)         Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers

 

The decision to make pollution control equipment investments depends on whether the expected future market price for power reflects the increased cost for environmental compliance.

 

The following sections describe the more significant environmental rules that affect or could affect AER’s operations.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Clean Air Act

 

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels.  In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR).  The CAIR required generating facilities in 28 states, including Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions.

 

In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule’s flaws, but allowed the CAIR’s cap-and-trade programs to remain effective until they are replaced by the EPA.  In July 2011, the EPA issued the CSAPR as the CAIR replacement.  On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR.  In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR’s emission limits on states.  In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA’s request for rehearing.  In March 2013, the EPA and certain environmental groups filed an appeal of the Circuit Court’s remand of CSAPR to the Supreme Court.  The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.

 

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units.  Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place.  The MATS do not require a specific control technology to achieve the emission reductions.  The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant.  Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

 

Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent.  States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard.  Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions.  Compliance with the rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted.  AER is currently evaluating the new standard while the state of Illinois develops its attainment plan.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone.  The EPA is required to revisit these standards for ozone again in 2013.  The state of Illinois will be required to develop an attainment plan to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020.  AER continues to assess the impacts of these new standards.

 

In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below.  The Illinois Pollution Control Board approved AER’s proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance.  The Illinois Pollution Control Board’s order also included the following provisions:

 

·                       A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at the Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

·                       A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact AER’s ability to make the Meredosia energy center available for any parties that may be interested in repowering one of AER’s units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.

 

As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS.  AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. See Note 14 — Subsequent Events for additional information.

 

Under the MPS, AER is required to reduce mercury, NOx and SO2 emissions with declining limits starting in 2009 for mercury and in 2010 for NOx and SO2.  The final NOx limit became effective in 2012.  The final mercury limit will become effective in 2015 and the final SO2 limit will become effective by the end of 2019.  The Illinois Pollution Control Board’s September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER’s energy centers.  To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NOx, and SO2.  AER has installed three scrubbers at two of its energy centers.  Two additional scrubbers are being constructed at the Newton energy center.  AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.

 

Environmental compliance costs could be prohibitive at some of AER’s energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Emission Allowances

 

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR.  Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations.  The CAIR uses the acid rain program’s allowances for SO2 emissions and created annual and ozone season NOx allowances.  AER expects to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.

 

Global Climate Change

 

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change.  Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances.  As a result of AER’s fuel portfolio, its emissions of greenhouse gases vary among its energy centers, but coal-fired power plants are significant sources of CO2.

 

In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment.  In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011.  As a result of these actions, AER is required to consider the emissions of greenhouse gases in any air permit application.

 

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants.  The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal.  Currently, AER’s energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions.  The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to address greenhouse gas emissions.  New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold.  The extent to which the Tailoring Rule could have a material impact on AER’s energy centers depends upon how the state of Illinois applies the EPA’s guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers.  In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants.  This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of our existing energy centers.  AER anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive.  A final rule is expected in 2013.  Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.

 

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force AER as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues.  As a result, mandatory limits could have a material adverse impact on our results of operations, financial position, and liquidity.

 

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change.  In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v.  Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including AER’s energy centers, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage.  The case has been appealed to the appellate court.

 

The impact on AER of future initiatives related to greenhouse gas emissions and global climate change is unknown.  Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required.  Since these initiatives continue to evolve, their impact on AER’s coal-fired energy centers and its customers’ costs is unknown, but they could result in significant increases in AER’s capital expenditures and operating costs.  The compliance costs could be prohibitive at some of AER’s energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

 

NSR and Clean Air Litigation

 

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications.  The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

 

Commencing in 2005, AER received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act.  The requests sought detailed operating and maintenance history data with respect to AER’s coal-fired energy centers.  In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act.  The EPA contends that projects performed in 1997, 2006, and 2007 at Genco’s Newton energy center violated federal law.  AER believes its defenses to the allegations described in the Notice of Violation are meritorious.  AER included $4 million in “Other current liabilities” on its consolidated balance sheet as of December 31, 2012, relating to this loss contingency.  AER is unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Ultimate resolution of these matters could have a material adverse impact on AER’s future results of operations, financial position, and liquidity.  A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties.  AER is unable to predict the ultimate resolution of these matters or the costs that might be incurred.

 

Clean Water Act

 

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling.  Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant’s intake screens or to reduce intake velocity to a specified level.  The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system.  The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter.  All coal-fired and combined cycle energy centers with cooling water systems are subject to this proposed rule.  The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards.  AER is currently evaluating the proposed rule, and its assessment of the proposed rule’s impacts is ongoing.  Therefore, AER cannot predict at this time the capital or operating costs associated with compliance.  The proposed rule, if adopted, could have an adverse effect on AER’s results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.

 

In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning and gasification of fuels.  The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments.  The EPA’s multi-option proposed rule would prohibit effluent discharges of certain, but not all, waste streams. If enacted as proposed, AER would be subject to the revised limitations beginning July 1, 2017 but no later than July 1, 2022. AER is reviewing the proposed rule and evaluating its impact on AER’s operations. The EPA expects to finalize the rule in 2014.

 

Environmental Claims

 

Former Ameren Illinois energy centers are now owned by AER. As part of the transfer of ownership of the Ameren Illinois energy centers, Ameren Illinois contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental contamination at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH.  The agreements will provide that Medina Valley will assume all environmental liabilities associated with the Meredosia and Hutsonville energy centers.  The agreements will also provide that all environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers will no longer be indemnified by Ameren Illinois.  See Note 14 - Subsequent Events for additional information on the transaction agreement with IPH.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems.  In April 2013, AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds.  The rulemaking process could take up to two years to complete.

 

Ash Management

 

There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR.  In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers.  Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste.  As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners.  Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations.  The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam-electric generating units would apply to ash pond and CCR management and intended to align this proposal with the CCR rules proposed in May 2010.  Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements.  AER is currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered.  AER is also evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

 

Asbestos-Related Litigation

 

Former Ameren Illinois energy centers are now owned by AER.  As a part of the transfer of ownership of the Ameren Illinois energy centers, Ameren Illinois contractually agreed to indemnify AER for liabilities associated with asbestos-related claims arising or existing from activities prior to the Genco transfer in 2000 and AERG transfer in 2003.  The plant transfer agreements between Ameren Illinois and both Genco and AERG and will be amended as part of the transaction agreement for Ameren to divest New AER to IPH.  The amended agreements will provide that Ameren Illinois will continue to retain asbestos exposure related-liabilities for claims arising or existing from activities prior to the transfer of ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after it takes ownership of New AER. Any asbestos-related claims arising from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren. See Note 14 - Subsequent Events for additional information on the transaction agreement.

 

EEI was not included in the plant transfer agreements with Ameren Illinois discussed above. As of December 31, 2012, five asbestos-related lawsuits were pending against EEI.  The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Illinois Sales and Use Tax Exemptions and Credits

 

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit.  In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final.  During the second quarter of 2010, AER began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to its generation operations.  The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits.  In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois’ position that EEI did not qualify for the manufacturing exemption it used during 2010.  EEI is challenging the state of Illinois’ position.  In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue.  AER does not believe that it is probable that the state of Illinois will prevail and therefore has not recorded a charge to earnings for the loss contingency.  From the second quarter of 2010 through December 31, 2011, AER claimed manufacturing exemptions and credits of $27 million, which represents the maximum potential tax liability, excluding any penalties assessed or interest accrued.

 

AER did not claim any additional manufacturing exemptions or credits in 2012 and does not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue.  AER is reserving the right to apply for applicable refunds at a later date.

 

Ameren will retain responsibility for this contingent liability after the divestiture of New AER is completed.

 

13.                     Impairment and Other Charges

 

The following table summarizes the pretax charges recognized in the “Impairment and other charges” on the statement of operations for the years ended December 31, 2012, 2011, and 2010:

 

 

 

2012

 

2011

 

2010

 

Long-Lived Assets and Related Charges

 

$

698

 

$

35

 

$

101

 

Goodwill

 

 

 

420

 

Emission Allowances

 

 

2

 

68

 

Total

 

$

698

 

$

37

 

$

589

 

 

The impairment and other charges did not result in a violation of any debt covenants or counterparty agreements.  Each of the impairment charges is discussed separately below.

 

Long-Lived Assets

 

AER evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  Whether an 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, AER would recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.

 

AER has experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices.  In addition, environmental regulations have resulted in significant investment requirements over the same time frame.  During the first quarter of 2012, the observable market price for power

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR.  As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012.  The sharp decline in the market price of power in the first quarter of 2012 and the related impact on electric margins, as well as the deceleration of construction of the Newton energy center scrubber project, caused AER to evaluate, during the first quarter of 2012, whether the carrying values of its coal-fired energy centers were recoverable.  The carrying value of AERG’s Duck Creek energy center exceeded its estimated undiscounted future cash flows.  As a result, AER recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of that energy center to its estimated fair value during the first quarter of 2012.

 

Ameren, AER’s parent company, is increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential, and is specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks.  Ameren has sought to have AER fund its operations internally and not rely on financing from Ameren.  In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, before the end of the previously estimated useful lives of AER’s long-lived assets.  In consideration of this determination, AER began planning to reduce, and ultimately eliminate, its reliance on Ameren’s financial support and shared services support.

 

Ameren’s December 2012 decision that it intended to, and it was probable that it would, reduce and ultimately eliminate its financial support and shared services support provided to AER, caused AER to evaluate, during the fourth quarter of 2012, whether the carrying values of AER’s energy centers were recoverable.  Based on the expectation of reduced financial support from Ameren, together with existing power market conditions and cash flow requirements, Genco estimated it would more likely than not need liquidity from an asset sale to support its operations before the put option agreement was due to expire on March 28, 2014.  As a result of the expectation at that time that it was more likely than not that Genco would sell the Elgin energy center for liquidity purposes, the Elgin energy center’s carrying value exceeded its estimated undiscounted future cash flows.  Accordingly, AER recorded a noncash pretax impairment charge of $70 million to reduce the carrying value of the Elgin energy center to its estimated fair value.  The estimated undiscounted future cash flows for AER’s other energy centers exceeded their carrying values and therefore were unimpaired.  Under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values.

 

AER will continue to monitor the market price for power and the related impact on electric margin, its liquidity needs, and other events or changes in circumstances that indicate that the carrying value of its energy centers may not be recoverable as compared to their undiscounted cash flows.  AER could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted future cash flows no longer exceed carrying values for long-lived assets.  This may occur either as a result of factors outside AER’s control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of AER’s energy centers, and also as a result of factors that may be within AER’s control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell its energy centers.  As of December 31, 2012, the carrying value of AER’s property and plant, net, was $2.6 billion.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

After the impairment of the Duck Creek energy center in the first quarter of 2012, AER believed the carrying value of its energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. However, under the applicable accounting guidance, an asset is not deemed impaired, and no impairment loss is recognized, unless the asset’s carrying value exceeds the estimated undiscounted future cash flows, even if the carrying value of the asset exceeds estimated fair value. AER could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets as a result of factors outside its control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of AER’s energy centers, and also as a result of factors that may be within its control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

 

In December 2011, Genco ceased operations of its Meredosia and Hutsonville energy centers.  As a result, AER recorded a noncash pretax asset impairment charge of $26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values, a $5 million impairment of materials and supplies, and $4 million for severance costs.  See Note 2 - Summary of Significant Accounting Policies for further information regarding severance costs.

 

During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused AER to evaluate if the carrying values of its energy centers were recoverable.  The Meredosia and Medina Valley energy centers’ carrying values exceeded their estimated undiscounted future cash flows.  As a result, during 2010, AER recorded a noncash pretax asset impairment charge of $101 million to reduce the carrying value of the Meredosia and Medina Valley energy centers to their estimated fair values.

 

AER assesses impairment at the energy center level.  Key assumptions used in the determination of estimated undiscounted cash flows of AER’s long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs.  Those same cash flow assumptions were used to estimate the fair value of the Duck Creek energy center during the first quarter of 2012, the Elgin energy center in the fourth quarter of 2012, and the Meredosia and Medina Valley energy centers in the third quarter of 2010.  In the fourth quarter of 2012, the determination of the estimated fair value of the Elgin energy center also included a terminal year earnings multiple assumption.  These assumptions are subject to a high degree of judgment and complexity.  The fair value estimate of these long-lived assets was based on the income approach, which considers discounted cash flows.  The fair value estimate of the Elgin energy center in the fourth quarter of 2012 was based on a combination of the income approach and the market approach, which considers market multiples for similar assets within the electric generation industry.

 

Goodwill

 

Goodwill impairment testing is a two-step process.  The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount.  If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired.  If

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

the carrying amount of the reporting unit exceeds its estimated fair value, a second step is performed to measure the amount of impairment, if any.  The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill.  The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities in a manner similar to a purchase price allocation.  The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill.  If the implied fair value of goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.

 

AER has one reporting unit for goodwill purposes.  During the third quarter of 2010, AER concluded that events had occurred and circumstances had changed which, when considered in the aggregate, indicated that it was more likely than not that the fair value of the AER reporting unit was less than its carrying value.  Such events and circumstances included the sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted.  In July 2010, the EPA issued the proposed CSAPR.  The proposed CSAPR, along with other pending regulations, was expected to result in a significant increase in capital and operations and maintenance expenditures for our energy centers.  Accordingly, AER performed an interim goodwill impairment test as of August 31, 2010.

 

The fair value estimate of the AER reporting unit was based on a combination of the income approach, which considers discounted future cash flows, and the market approach, which considers market comparables within the electric generation industry.  Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year cash flows, and observable industry market multiples.  AER used its best estimates in making these evaluations.  AER considered various factors, including forward price projections for energy and fuel costs, environmental compliance costs, and operating costs.

 

AER’s reporting unit failed step one of the August 31, 2010, interim impairment test, as the reporting unit’s carrying value exceeded its estimated fair value.  Therefore, in order to measure the goodwill impairment in step two, AER estimated the implied fair value of its goodwill.  AER determined that the implied fair value of goodwill was less than the carrying amount of goodwill, indicating that AER’s goodwill was impaired as of August 31, 2010.  Based on the results of step two of the impairment test, AER recorded a noncash impairment charge of $420 million, which represented all of the goodwill assigned to the reporting unit.

 

Intangible Assets

 

AER evaluates emission allowances and renewable energy credits for impairment if events or changes in circumstances indicate that they will not or cannot be used in operations.

 

Prior to 2010, AER expected to use its SO2 emission allowances for ongoing operations.  In July 2010, the EPA issued the proposed CSAPR, which would restrict the use of existing SO2 emission allowances.  As a result, AER no longer expected all of its SO2 emission allowances would be used in operations.  Therefore, during 2010, AER recorded an impairment charge of $68 million to reduce the carrying value of its SO2 emission allowances to its estimated fair value.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

In July 2011, the EPA issued CSAPR, which created new allowances for SO2 and NOx emissions, and restricted the use of pre-existing SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively.  As a result, observable market prices for existing emission allowances declined materially.  Consequently, during 2011, AER recorded a noncash pretax impairment charge of $2 million.

 

Inputs for Fair Value Estimates

 

Both observable and unobservable inputs were used in determining the estimated fair value of AER’s long-lived assets, goodwill, and intangible assets.  These assets are measured at fair value on a nonrecurring basis if triggering events require AER to perform impairment tests, which are Level 3 within the fair value hierarchy.

 

14.                     Subsequent Events

 

Transaction Agreement

 

On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH.  Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) obligations relating to Ameren’s single-employer pension and postretirement benefit plans, (v) and the deferred tax positions associated with Ameren’s ownership of these retained assets and liabilities, to New AER.  IPH will acquire all of the equity interests in New AER.  On March 13, 2013, AER transferred its interest in Medina Valley at carrying value to Ameren.

 

Ameren will retain the portion of AER’s pension and postretirement benefit obligations associated with current and former employees that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan.  New AER will retain the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc.  These EEI plan obligations are estimated at $40 million at December 31, 2012.  New AER will also retain the $14 million asset relating to the overfunded status of one of EEI’s postretirement plans.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Ameren will retain AER’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of December 31, 2012.  Ameren will also retain asset retirement obligations associated with these energy centers, estimated at $27 million as of December 31, 2012.  Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its affiliates, on the other hand, will be either retained or cancelled by Ameren, without any costs or other liability or obligation to IPH or New AER and its subsidiaries.

 

Ameren’s retention of AER’s liabilities for pension and postretirement benefit obligations relating to Ameren’s plans, the Meredosia and Hutsonville energy centers and those two energy centers’ related asset retirement obligations, tax payable to Ameren Illinois, and related deferred tax balances associated with each transferred balance will be accounted for as transactions between entities under common control and transferred at carrying value.

 

In addition, if this transaction is completed, AER expects the tax basis of property, plant and equipment to decrease and deferred tax assets related to federal and state income tax net operating loss carryforwards and income tax credits to decrease with corresponding offsets to equity.  The amount of any such decrease is dependent on the value and timing of the transaction.

 

Genco’s $825 million in aggregate principal amount of senior notes will remain outstanding following the transaction agreement closing and will continue to be solely obligations of Genco.  Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $70 million of cash to be retained at Genco and an additional $15 million of cash to be retained at Marketing Company.

 

As described in more detail below under “Amended Put Option Agreement, Asset Purchase Agreement and Guaranty” as a condition to the transaction agreement, Genco will receive cash proceeds from the exercise of its option under the March 28, 2012 put option agreement, as amended, for the sale to Medina Valley of the Elgin, Gibson City and Grand Tower gas-fired energy centers in an amount equal to the greater of $133 million or the appraised value of such energy centers.  If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the put option closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the of the amount it paid at the asset purchase agreement closing.  Ameren has commenced a sale process for these energy centers and expects a third-party sale will be completed during 2013.

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC.  On April 16, 2013, AER and Dynegy filed with FERC an application for approval of its divestiture of new AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. As a condition to IPH’s obligation to complete the transaction, the Illinois Pollution Control Board must approve the transfer to IPH of AER’s variance related to the Illinois MPS. AER and Dynegy filed a transfer request with the Illinois Pollution Control Board on May 2, 2013. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants.  The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold.  The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that New AER will be operated in the ordinary course prior to the closing.

 

Upon the divestiture of New AER, subject to certain exceptions, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments it makes pursuant to these credit support obligations. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through a money pool borrowing will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced.

 

Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013.  If the closing does not occur on or before March 14, 2014, of the New AER divestiture to IPH subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.

 

Amended Put Option Agreement, Asset Purchase Agreement and Guaranty

 

On March 28, 2012, Genco entered into a put option agreement with AERG, which gave Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin gas-fired energy centers.

 

Prior to the entry into the transaction agreement to divest New AER to IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City and Grand Tower gas-fired energy centers to Medina Valley.  As a result, on March 14, 2013, Medina Valley paid to Genco an initial payment of $100 million in accordance with the terms of the amended put option agreement.  In connection with the amended put option

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

agreement, Ameren’s guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley.

 

Pursuant to the amended put option agreement, Genco and Medina Valley have entered into an asset purchase agreement, dated March 14, 2013.  Genco and Medina Valley will engage three appraisers to conduct a fair market valuation of the Elgin, Gibson City and Grand Tower gasfired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the liabilities associated with the Elgin, Gibson City and Grand Tower gas-fired energy centers transferred to Medina Valley under the terms of the asset purchase agreement.  At the asset purchase agreement closing, Medina Valley will pay Genco additional consideration in an amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City and Grand Tower gas-fired energy centers less the initial payment of $100 million for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City and Grand Tower gas-fired energy centers as a condition to the transaction agreement. Ameren has commenced a sale process for these three gas-fired energy centers and expects a sale to a third-party will be completed during 2013. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amount it paid at the asset purchase agreement closing.

 

The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley.  The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.

 

Based upon the asset purchase agreement, AER will record a pre-tax charge to earnings of $207 million during the three months ended March 31, 2013, to reduce the carrying value of the Elgin, Gibson City and Grand Tower gas-fired energy centers to their estimated fair value less costs to sell.  Beginning with the quarter ended March 31, 2013, AER will classify the Elgin, Gibson City and Grand Tower gas-fired energy centers as held for sale in its consolidated balance sheet and will recast its December 31, 2012 balance sheet to reflect the presentation of these energy centers as held for sale as of December 31, 2012, to enhance the comparability to the March 31, 2013 balance sheet.  The following table shows the reclassifications that will be made to the December 31, 2012 balance sheet within the comparative March 31, 2013 quarterly financial statements:

 

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Ameren Energy Resources Company, LLC

(A subsidiary of Ameren Corporation)

Notes to Consolidated Financial Statements

December 31, 2012, 2011 and 2010

 

(dollars in millions)

 

 

 

December 31

 

 

 

2012

 

Materials and supplies

 

$

12

 

Mark-to-market derivative assets

 

4

 

Property and plant, net

 

348

 

Total current assets held for sale

 

$

364

 

Accounts and wages payable

 

$

9

 

Taxes accrued

 

3

 

Mark-to-market derivative liabilities

 

3

 

Asset retirement obligations

 

10

 

Total current liabilities held for sale

 

$

25

 

 

As of December 31, 2012, the Elgin, Gibson City, and Grand Tower energy centers were not classified as held-for-sale under authoritative accounting guidance as all criteria to qualify for that presentation were not met as of December 31, 2012.  Specifically, AER did not consider it probable at December 31, 2012, that a disposition of an energy center would occur within one year.  Accordingly, these financial statements reflected the balances associated with these energy centers as held and used.

 

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Until             , 2013 (the 25th day after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 



Table of Contents

 

PART II INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.  Other Expenses of Issuance and Distribution.

 

The following table shows the costs and expenses payable in connection with the sale and distribution of the securities being registered.  All amounts except the SEC registration fee are estimated.

 

Amount SEC registration fee

 

$

82,021.28

 

Accounting fees and expenses

 

$

100,000.00

 

Legal fees and expenses

 

$

200,000.00

 

Printing fees and expenses

 

$

100,000.00

 

Total

 

$

482,021.28

 

 

Item 14.  Indemnification of Directors and Officers.

 

Dynegy is incorporated under the laws of the State of Delaware. Section 145 (“Section 145”) of the DGCL provides that a Delaware corporation may indemnify any persons who were, are or are threatened to be made, parties to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation), by reason of the fact that such person is or was an officer, director, employee or agent of such corporation, or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise.  The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his conduct was illegal.  Section 145(b) of the DGCL provides that a Delaware corporation may indemnify officers and directors in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation.  Where an officer, director, employee or agent is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses which such officer or director has actually and reasonably incurred.

 

Section 145(g) of the DGCL provides that a corporation shall have the power to purchase and maintain insurance on behalf of any person who is or was a director or officer of the corporation against any liability asserted against the person in any such capacity, or arising out of the person’s status as such, whether or not the corporation would have the power to indemnify the person against such liability under the provisions of the DGCL.

 

Article 6.1 of Dynegy’s third amended and restated certificate of incorporation provides that a director of Dynegy shall not be personally liable to Dynegy or its stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent such exemption from liability or limitation thereof is not permitted under Delaware law. Article 6.2 of Dynegy’s third amended and restated certificate of incorporation and Article VIII of Dynegy’s fourth amended and restated bylaws provide for indemnification of the officers and directors of Dynegy to the fullest extent permitted by the DGCL. Article 6.3 of Dynegy’s third amended and restated certificate provides that any indemnification will be made in a specific case only as authorized by

 

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Dynegy’s Board, a committee of the Board, independent legal counsel or the stockholders, upon a determination that indemnification is proper in the circumstances because the indemnitee met the applicable standard of conduct set forth in the third amended and restated certificate of incorporation. However, if a current or former director or officer has been successful in the defense of any covered action or proceeding, such person will be indemnified against expenses actually and reasonably incurred.

 

The foregoing is only a general summary of certain aspects of Delaware law and the registrant’s organizational documents dealing with indemnification of directors and officers and does not purport to be complete. It is qualified in its entirety by reference to the applicable provisions of the DGCL and of the registrant’s third amended and restated certificate of incorporation and bylaws.

 

Dynegy has obtained directors’ and officers’ liability insurance, which insures against liabilities that its directors or officers may incur in such capacities.

 

Item 15.  Recent Sales of Unregistered Securities.

 

On the Plan Effective Date, all existing shares of Old Common Stock were cancelled pursuant to the Plan.

 

Pursuant to the Plan, on the Plan Effective Date, Dynegy issued (i) 100,000,000 shares of common stock, and (ii) five-year Warrants to purchase up to 15,606,936 shares of common stock, which, in each case (including shares of common stock issuable upon exercise of such Warrants), based on the Plan and Confirmation Order entered by the Bankruptcy Court on September 10, 2012, are exempt from the registration requirements of the Securities Act, in reliance on Section 1145 of the Bankruptcy Code.

 

Item 16.  Exhibits and Financial Statement Schedules.

 

Reference is made to the Exhibit Index filed as part of this Registration Statement.

 

Item 17.  Undertakings

 

a)                                     The undersigned registrant hereby undertakes:

 

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act;

 

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

 

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

 

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(2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

b)                                     The undersigned hereby undertakes to deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report, to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Exchange Act; and, where interim financial information required to be presented by Article 3 of Regulation S-X is not set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information.

 

c)                                      Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Post-Effective Amendment No. 2 to the registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Houston, State of Texas on May 29, 2013.

 

 

 

DYNEGY INC.

 

 

 

By:

/s/ Robert C. Flexon

 

Name:

Robert C. Flexon

 

Title:

President and Chief Executive Officer

 

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Pursuant to the requirements of the Securities Act of 1933, as amended, this Post-Effective Amendment No. 1 to the registration statement has been signed by the following persons in the capacities and on the dates indicated.

 

Signature/Name

 

Position

 

Date

 

 

 

 

 

*

 

Chairman

 

May 29, 2013

Pat Wood, III

 

 

 

 

 

 

 

 

 

/s/ Robert C. Flexon

 

Director, President and Chief Executive Officer (Principal Executive Officer)

 

May 29, 2013

Robert C. Flexon

 

 

 

 

 

 

 

 

*

 

Executive Vice President and Chief Financial Officer (Principal Financial Officer)

 

May 29, 2013

Clint C. Freeland

 

 

 

 

 

 

 

 

*

 

Vice President and Chief Accounting Officer (Principal Accounting Officer)

 

May 29, 2013

J. Clinton Walden

 

 

 

 

 

 

 

 

*

 

Director

 

May 29, 2013

Hilary E. Ackermann

 

 

 

 

 

 

 

 

 

*

 

Director

 

May 29, 2013

Paul M. Barbas

 

 

 

 

 

 

 

 

 

*

 

Director

 

May 29, 2013

Richard Lee Kuersteiner

 

 

 

 

 

 

 

 

 

*

 

Director

 

May 29, 2013

Jeffrey S. Stein

 

 

 

 

 

 

 

 

 

*

 

Director

 

May 29, 2013

John R. Sult

 

 

 

 

 

* The undersigned, by signing her name hereto, does sign and execute this Post-Effective Amendment No. 1 to the registration statement on Form S-1 pursuant to the Power of Attorney executed by the above-named officers and directors of Dynegy Inc. and filed with the Securities and Exchange Commission on December 10, 2012.

 

 

 

By:

/s/ Heidi D. Lewis

 

 

Name:

Heidi D. Lewis

 

 

 

as Attorney-In-Fact

 

 

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Exhibit Index

 

Exhibit No.

 

Description

2.1

 

Joint Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC and Dynegy Inc., as filed July 12, 2012 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC, filed on July 13, 2012).

2.2

 

Joint Disclosure Statement, as filed July 12, 2012 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC, filed on July 13, 2012).

2.3

 

Chapter 11 Joint Plan of Liquidation, filed December 14, 2012 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 17, 2012).

2.4

 

Disclosure Statement, filed December 14, 2012. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on December 17, 2012).

3.1

 

Third Amended and Restated Certificate of Incorporation of Dynegy Inc. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012).

3.2

 

Fourth Amended and Restated Bylaws of Dynegy Inc. (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012).

****4.1

 

Warrant Agreement dated October 1, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012).

4.2

 

Registration Rights Agreement dated October 1, 2012 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012).

4.3

 

Indenture, dated May 20, 2013, among Dynegy Inc., the Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013).

4.4

 

Registration Rights Agreement, dated May 20, 2013, among Dynegy Inc., the Guarantors (as defined therein), Morgan Stanley and Credit Suisse (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013).

5.1

 

Legal Opinion of White & Case LLP.*

10.1

 

Dynegy Inc. Executive Severance Pay Plan, as amended and restated effective as of January 1, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008).†

10.2

 

First Amendment to the Dynegy Inc. Executive Severance Pay Plan effective as of January 1, 2010 (incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2009 of Dynegy Inc.).†

10.3

 

Second Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of September 20, 2010 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2010 of Dynegy Inc.).†

10.4

 

Third Amendment to the Dynegy Inc. Executive Severance Pay Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2011.).†

10.5

 

Fourth Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of August 8, 2011(incorporated by reference to Exhibit 10. 1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2011 of Dynegy Inc.).†

10.6

 

Dynegy Inc. Executive Change in Control Severance Pay Plan effective April 3, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 8, 2008).†

10.7

 

First Amendment to the Dynegy Inc. Executive Change In Control Severance Pay Plan, dated as of September 22, 2010 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2010 of Dynegy Inc.).†

10.8

 

Second Amendment to the Dynegy Inc. Executive Change In Control Severance Pay Plan, dated March 18, 2013 (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013). †

10.9

 

Dynegy Inc. 2009 Phantom Stock Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009).†

10.10

 

First Amendment to the Dynegy Inc. 2009 Phantom Stock Plan, dated as of July 8, 2011(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).†

10.11

 

Dynegy Inc. Deferred Compensation Plan for Certain Directors, as amended and restated, effective January 1, 2008 (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009).†

10.12

 

Trust under Dynegy Inc. Deferred Compensation Plan for Certain Directors, effective January 1, 2009 (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009).†

10.13

 

Dynegy Inc. Incentive Compensation Plan, as amended and restated effective May 21, 2010

 

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(incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2010)†

10.14

 

Dynegy Inc. 2012 Long Term Incentive Plan dated August 14, 2012 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012).†

10.15

 

Assignment Agreement by and between Dynegy Inc. and Dynegy Operating Company, dated July 5, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 10, 2012).

10.16

 

Employment Agreement between Dynegy Inc. and Robert Flexon dated June 22, 2011(incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).†

10.17

 

Second Amendment to Employment Agreement by and between Dynegy Operating Company and Robert C. Flexon, dated March 18, 2013 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.18

 

Employment Agreement between Dynegy Inc. and Kevin Howell dated June 22, 2011(incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).†

10.19

 

Employment Agreement between Dynegy Inc. and Clint C. Freeland dated June 23, 2011(incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).†

10.20

 

Second Amendment to Employment Agreement by and between Dynegy Operating Company and Clint C. Freeland, dated March 18, 2013 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.21

 

Employment Agreement between Dynegy Inc. and Carolyn J. Burke dated July 5, 2011(incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).††

10.22

 

Second Amendment to Employment Agreement by and between Dynegy Operating Company and Carolyn J. Burke, dated March 18, 2013 (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.23

 

Employment Agreement between Dynegy Inc. and Catherine Callaway dated September 16, 2011 (incorporated by reference to Exhibit 10. 2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2011 of Dynegy Inc.).†

10.24

 

Second Amendment to Employment Agreement by and between Dynegy Operating Company and Catherine B. Callaway, dated March 18, 2013 (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.25

 

Employment Agreement by and among Dynegy Operating Company, Dynegy Inc. and Henry D. Jones (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 12, 2013).

10.26

 

First Amendment to Employment Agreement by and between Dynegy Operating Company and Henry D. Jones, dated March 18, 2013 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.27

 

Form Award Agreement for 2012 Long Term Incentive Program Award-Cash (CEO) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 9, 2012).†

10.28

 

Form Award Agreement for 2012 Long Term Incentive Program Award-Cash (EVP) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 9, 2012).†

10.29

 

Form of Performance Award Agreement (for Managing Directors and Above) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013).†

10.30

 

Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc., filed on November 2, 2012).†

10.31

 

Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc., filed on March 22, 2013).†

10.32

 

Form of Stock Unit Award Agreement—Officers (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc., filed on November 2, 2012).†

10.33

 

Form of Stock Unit Award Agreement—Officers (incorporated by reference to Exhibit 10.1 to the

 

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Current Report on Form 8-K of Dynegy Inc., filed on March 22, 2013).†

10.34

 

Form of Stock Unit Award Agreement—Directors (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc., filed on November 2, 2012).†

10.35

 

Form of Phantom Stock Unit Award Agreement - MD & Above Version (2012 LTIP Awards) (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2012 of Dynegy Inc.).†

10.36

 

Form of Phantom Stock Unit Award Agreement - MD & Above Version (2012 Replacement Shares) (incorporated by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2012 of Dynegy Inc.).†

***10.37

 

Letter of Credit Reimbursement and Collateral Agreement, dated as of August 5, 2011 among Dynegy Power LLC and Barclays Bank PLC (incorporated by reference to Exhibit 10.21 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc.).

10.38

 

Amended and Restated Settlement Agreement dated May 30, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2012).

10.39

 

Contribution Agreement dated June 5, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 11, 2012).

10.40

 

Assignment dated July 5, 2012 by and between Dynegy Inc. and Dynegy Operating Company (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 1, 2012).

 

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10.41

 

First Amendment to the Amended Plan Support Agreement dated July 31, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 10, 2012).

10.42

 

Agreement and Plan of Merger, dated September 28, 2012, by and among Dynegy and DH (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. and DH, filed on October 2, 2012).

10.43

 

Asset Purchase Agreement dated as of December 10, 2012, among Dynegy Danskammer, L.L.C. and ICS NY Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 10, 2012).

10.44

 

Letter Agreement dated December 10, 2012, among Louis Dreyfus Highbridge Energy LLC and Dynegy Roseton, L.L.C. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc., filed December 10, 2012).

10.45

 

Agreed upon form Asset Purchase Agreement dated as of December  , 2012, among LDH U.S. Asset Holdings LLC and Dynegy Roseton, L.L.C. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 18, 2012).

10.46

 

Amended Chapter 11 Joint Plan of Liquidation for Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C. filed January 21, 2013 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 22, 2013).

10.47

 

Amended Disclosure Statement related to the Chapter 11 Joint Plan of Liquidation for Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C. filed January 21, 2013 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 22, 2013).

10.48

 

Transaction Agreement by and between Ameren Corporation and Illinois Power Holdings, LLC, dated as of March 14, 2013 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 15, 2013).

10.49

 

Limited Guaranty, dated March 14, 2013, in favor of Ameren Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 15, 2013).

10.50

 

Credit Agreement, dated as of April 23, 2013, among Dynegy, Inc., as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy, Inc. filed on April 24, 2013).

10.51

 

Guarantee and Collateral Agreement, dated as of April 23, 2013, among Dynegy, Inc., the subsidiaries of the borrower from time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy, Inc. filed on April 24, 2013).

10.52

 

Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013, among Dynegy, Inc., the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto from time to time (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K of Dynegy, Inc. filed on April 24, 2013).

10.53

 

Purchase Agreement, dated May 15, 2013, among Dynegy Inc., the Guarantors (as defined therein), Morgan Stanley and Credit Suisse (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013).

21.1

 

Subsidiaries of Dynegy Inc. (incorporated by reference to Exhibit 21.1 to the Annual Report on Form 10-k of Dynegy Inc., filed on March 14, 2013).

23.1

 

Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.*

23.2

 

Consent of Independent Accountants, PricewaterhouseCoopers LLP.*

23.3

 

Consent of White & Case LLP (included as part of Exhibit 5.1).*

24.1

 

Power of Attorney (incorporated by reference to the signature page to the Registration Statement on form S-1, filed December 10, 2012).

 


*                             Filed herewith.

***               Certain exhibits, attachments or schedules to the exhibits filed herewith were never prepared or used by the parties in connection with the transactions that are the subject of the filed exhibit and therefore no actual exhibit, attachment or schedule exists.

****        Pursuant to a request for confidential treatment, portions of this Exhibit have been redacted and filed separately with the SEC as required by Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

                             Management compensatory plan or arrangement.

 

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