q213aep10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2013
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
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Commission
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Registrants; States of Incorporation;
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I.R.S. Employer
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File Number
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Address and Telephone Number
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Identification Nos.
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1-3525
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AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
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13-4922640
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1-3457
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APPALACHIAN POWER COMPANY (A Virginia Corporation)
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54-0124790
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1-3570
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INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
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35-0410455
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1-6543
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OHIO POWER COMPANY (An Ohio Corporation)
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31-4271000
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0-343
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PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
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73-0410895
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1-3146
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SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
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72-0323455
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1 Riverside Plaza, Columbus, Ohio 43215-2373
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Telephone (614) 716-1000
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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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Yes
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X
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No
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Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
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Yes
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X
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No
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Indicate by check mark whether American Electric Power Company, Inc. 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.
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Large accelerated filer
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X
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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X
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Smaller reporting company
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Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
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Yes
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No
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X
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Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
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Number of shares of common stock outstanding of the registrants as of
July 25, 2013
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American Electric Power Company, Inc.
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486,772,596
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($6.50 par value)
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Appalachian Power Company
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13,499,500
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(no par value)
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Indiana Michigan Power Company
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1,400,000
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(no par value)
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Ohio Power Company
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27,952,473
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(no par value)
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Public Service Company of Oklahoma
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9,013,000
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($15 par value)
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Southwestern Electric Power Company
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7,536,640
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($18 par value)
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2013
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Page
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Number
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Glossary of Terms
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i
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Forward-Looking Information
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iv
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Part I. FINANCIAL INFORMATION
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Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk:
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American Electric Power Company, Inc. and Subsidiary Companies:
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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1
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Condensed Consolidated Financial Statements
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31
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Index of Condensed Notes to Condensed Consolidated Financial Statements
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37
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Appalachian Power Company and Subsidiaries:
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Management’s Narrative Discussion and Analysis of Results of Operations
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86
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Condensed Consolidated Financial Statements
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92
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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98
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Indiana Michigan Power Company and Subsidiaries:
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Management’s Narrative Discussion and Analysis of Results of Operations
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100
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Condensed Consolidated Financial Statements
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105
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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111
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Ohio Power Company and Subsidiary:
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Management’s Narrative Discussion and Analysis of Results of Operations
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113
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Condensed Consolidated Financial Statements
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120
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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126
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Public Service Company of Oklahoma:
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Management’s Narrative Discussion and Analysis of Results of Operations
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128
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Condensed Financial Statements
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132
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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138
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Southwestern Electric Power Company Consolidated:
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Management’s Narrative Discussion and Analysis of Results of Operations
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140
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Condensed Consolidated Financial Statements
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146
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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152
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Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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153
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Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
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220
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Controls and Procedures
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227
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Part II. OTHER INFORMATION
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Item 1.
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Legal Proceedings |
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228
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Item 1A.
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Risk Factors |
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228
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Item 2.
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Unregistered Sales of Equity Securities and Use of Proceeds |
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229
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Item 4.
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Mine Safety Disclosures |
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230
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Item 5.
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Other Information |
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230
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Item 6.
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Exhibits: |
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230
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Exhibit 4 |
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Exhibit 10 |
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Exhibit 12 |
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Exhibit 31(a) |
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Exhibit 31(b) |
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Exhibit 32(a) |
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Exhibit 32(b) |
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Exhibit 95 |
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Exhibit 101.INS |
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Exhibit 101.SCH |
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Exhibit 101.CAL |
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Exhibit 101.DEF |
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Exhibit 101.LAB |
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Exhibit 101.PRE |
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SIGNATURE
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231
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This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
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GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
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Term
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Meaning
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AEGCo
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AEP Generating Company, an AEP electric utility subsidiary.
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AEP or Parent
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American Electric Power Company, Inc., an electric utility holding company.
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AEP Consolidated
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AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
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AEP Credit
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AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
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AEP East Companies
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APCo, I&M, KPCo and OPCo.
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AEP Energy
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AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
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AEPGenCo
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AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation and Marketing segment.
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AEP System
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American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
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AEP Transmission Holding Company
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AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
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AEPSC
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American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
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AEPTCo
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American Electric Power Transmission Company, a wholly-owned subsidiary of AEP Transmission Holding Company.
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AFUDC
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Allowance for Funds Used During Construction.
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AOCI
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Accumulated Other Comprehensive Income.
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APCo
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Appalachian Power Company, an AEP electric utility subsidiary.
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APSC
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Arkansas Public Service Commission.
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BlueStar
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BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
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CAA
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Clean Air Act.
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CLECO
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Central Louisiana Electric Company, a nonaffiliated utility company.
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CO2
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Carbon dioxide and other greenhouse gases.
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Cook Plant
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Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
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CRES
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Competitive Retail Electric Service.
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CSPCo
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Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
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CWIP
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Construction Work in Progress.
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DCC Fuel
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DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
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DHLC
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Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
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EIS
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Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
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ERCOT
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Electric Reliability Council of Texas regional transmission organization.
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ESP
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Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
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ETT
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Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
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FAC
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Fuel Adjustment Clause.
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FASB
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Financial Accounting Standards Board.
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Federal EPA
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United States Environmental Protection Agency.
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FERC
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Federal Energy Regulatory Commission.
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FGD
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Flue Gas Desulfurization or scrubbers.
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FTR
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Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
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GAAP
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Accounting Principles Generally Accepted in the United States of America.
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I&M
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Indiana Michigan Power Company, an AEP electric utility subsidiary.
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IEU
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Industrial Energy Users-Ohio.
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IGCC
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Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
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Interconnection Agreement
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An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
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IRS
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Internal Revenue Service.
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IURC
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Indiana Utility Regulatory Commission.
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KPCo
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Kentucky Power Company, an AEP electric utility subsidiary.
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KPSC
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Kentucky Public Service Commission.
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KWh
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Kilowatthour.
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LPSC
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Louisiana Public Service Commission.
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MISO
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Midwest Independent Transmission System Operator.
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MMBtu
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Million British Thermal Units.
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MPSC
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Michigan Public Service Commission.
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MTM
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Mark-to-Market.
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MW
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Megawatt.
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MWh
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Megawatthour.
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NOx
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Nitrogen oxide.
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Nonutility Money Pool
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Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
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OCC
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Corporation Commission of the State of Oklahoma.
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OPCo
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Ohio Power Company, an AEP electric utility subsidiary.
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OPEB
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Other Postretirement Benefit Plans.
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OTC
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Over the counter.
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PJM
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Pennsylvania – New Jersey – Maryland regional transmission organization.
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PM
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Particulate Matter.
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POLR
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Provider of Last Resort revenues.
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PSO
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Public Service Company of Oklahoma, an AEP electric utility subsidiary.
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PUCO
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Public Utilities Commission of Ohio.
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PUCT
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Public Utility Commission of Texas.
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Registrant Subsidiaries
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AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
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Risk Management Contracts
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Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
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Rockport Plant
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A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
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RTO
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Regional Transmission Organization, responsible for moving electricity over large interstate areas.
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Sabine
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Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
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SEC
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U.S. Securities and Exchange Commission.
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SEET
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Significantly Excessive Earnings Test.
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SIA
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System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
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SNF
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Spent Nuclear Fuel.
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SO2
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Sulfur dioxide.
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SPP
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Southwest Power Pool regional transmission organization.
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SSO
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Standard service offer.
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Stall Unit
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J. Lamar Stall Unit at Arsenal Hill Plant, a 543 MW natural gas unit owned by SWEPCo.
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SWEPCo
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Southwestern Electric Power Company, an AEP electric utility subsidiary.
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TCC
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AEP Texas Central Company, an AEP electric utility subsidiary.
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TNC
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AEP Texas North Company, an AEP electric utility subsidiary.
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Transition Funding
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AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
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Turk Plant
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John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
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Utility Money Pool
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Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
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VIE
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Variable Interest Entity.
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Virginia SCC
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Virginia State Corporation Commission.
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WPCo
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Wheeling Power Company, an AEP electric utility subsidiary.
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WVPSC
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Public Service Commission of West Virginia.
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FORWARD-LOOKING INFORMATION
This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2012 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
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The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
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Inflationary or deflationary interest rate trends.
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Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
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The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
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Electric load, customer growth and the impact of retail competition, particularly in Ohio.
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Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
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Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
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Availability of necessary generating capacity and the performance of our generating plants.
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Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
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Our ability to build or acquire generating capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
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New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.
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Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
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A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
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Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
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Resolution of litigation.
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Our ability to constrain operation and maintenance costs.
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Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
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Prices and demand for power that we generate and sell at wholesale.
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Changes in technology, particularly with respect to new, developing or alternative sources of generation.
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Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
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Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
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Changes in utility regulation, including the implementation of ESPs and the transition to market and the legal separation of generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
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Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate the Interconnection Agreement.
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Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
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Actions of rating agencies, including changes in the ratings of our debt.
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The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
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Accounting pronouncements periodically issued by accounting standard-setting bodies.
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Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
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The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made. AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2012 Annual Report and in Part II of this report.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Corporate Separation, Plant Transfers and Termination of Interconnection Agreement
In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value (NBV) to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.
Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo’s current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests. In December 2012, APCo and KPCo filed requests with their respective commissions for the approval of the plant transfers discussed above. We are currently pursuing cost recovery of these plants in Kentucky and West Virginia and plan to pursue cost recovery in Virginia. In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of OPCo’s generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using our requested date of December 31, 2013. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo strongly contested the petition for rehearing, which remains pending before the FERC. In June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the plant transfer discussed above. The Attorney General was not party to the settlement agreement. If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015. Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the KPSC and WVPSC in July 2013. See the “Plant Transfers” sections of APCo and WPCo Rate Matters and KPCo Rate Matters in Note 3 and the “2013 Kentucky Base Rate Case” section below.
The AEP East Companies also requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors. A decision is pending at the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of Note 3.
Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo. This agreement provides for AEPGenCo to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.
If approved as filed, for any AEPGenCo generation not serving OPCo’s retail load, AEPGenCo’s results of operations will be largely determined by prevailing market conditions effective January 1, 2014. If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.
Ohio Electric Security Plan Filing
2009 – 2011 ESP
In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012. As of June 30, 2013, OPCo’s net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs. Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.
June 2012 – May 2015 Ohio ESP Including Capacity Charge
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As of June 30, 2013, OPCo’s incurred deferred capacity costs balance was $171 million, including debt carrying costs.
As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is expected to provide approximately $500 million of revenue over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.
In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). Depending upon actual customer switching levels and the timing of the auctions, OPCo estimates that these capacity issues could reduce OPCo’s projected future revenues by up to approximately $160 million through May 2015. An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013.
If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing” section of Note 3.
Ohio Customer Choice
In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability Rider collections and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation and Marketing segment which targets retail customers, both within and outside of our retail service territory.
Customer Demand
In comparison to 2012, our weather-normalized retail sales were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively. Our industrial sales declined 5.3% and 5.7%, respectively, partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.
PJM Capacity Market
If corporate separation and asset transfers are approved as filed, AEPGenCo will be subject to the PJM capacity auction prices after May 2015 for the majority of the current OPCo-owned generation assets. Under the previously approved June 2012 – May 2015 ESP, OPCo is allowed to receive revenues through May 2015 for the generation assets from base generation rates and allowed to defer incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The PJM base capacity price for the planning year June 2015 through May 2016 was previously announced as $136.00/MW day. In May 2013, PJM announced the base capacity auction price for the June 2016 through May 2017 planning period would be $59.37/MW day.
Significantly Excessive Earnings Test
In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. See the “Ohio Electric Security Plan Filing” section of Note 3.
U.K. Windfall Tax Decision
In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013.
Turk Plant
SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the “Turk Plant” section of Note 3.
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates.
In December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013. The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo’s next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. A decision from the PUCT is expected in the third quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo’s Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition. See the “2012 Texas Base Rate Case” section of Note 3.
2012 Louisiana Formula Rate Filing
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 3.
2011 Indiana Base Rate Case
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. See the “2011 Indiana Base Rate Case” section of Note 3.
2013 Kentucky Base Rate Case
In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase includes the cost recovery of the pending transfer of the one-half interest in the Mitchell Plant, cost recovery of Big Sandy Plant, Units 1 and 2 and includes requests for recovery of deferrals related to the Big Sandy Plant FGD project and 2012 storm costs. Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above. If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015. If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition. See the “2013 Kentucky Base Rate Case” section of Note 3.
Cook Plant Life Cycle Management Project (LCM Project)
In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.
In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated could be sought for recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a mid-September 2013 proceeding and semi-annual proceedings thereafter. The IURC authorized deferral accounting for I&M’s incurred project costs effective January 2012 to the extent such costs are not reflected in its rates.
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.
LITIGATION
In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report. Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.
ENVIRONMENTAL ISSUES
We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements. We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units. We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.
See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Recovery in Ohio will be dependent upon prevailing market conditions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 MWs are coal-fired. We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities. Based upon our estimates, investments to meet these proposed requirements range from approximately $4 billion to $5 billion through 2020. These amounts include investments to convert some of our coal generation units to natural gas. If natural gas conversion is not completed, the units could be retired sooner than planned.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.
Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following plants or units of plants before or during 2016:
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Generating
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Company
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Plant Name and Unit
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Capacity
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(in MWs)
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APCo
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Clinch River Plant, Unit 3
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|
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235
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|
APCo
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Glen Lyn Plant
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|
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335
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APCo
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Kanawha River Plant
|
|
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400
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|
APCo/OPCo
|
|
Philip Sporn Plant, Units 1-4
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|
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600
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|
I&M
|
|
Tanners Creek Plant, Units 1-3
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|
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495
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|
KPCo
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Big Sandy Plant, Unit 2
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|
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800
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OPCo
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Kammer Plant
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630
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OPCo
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Muskingum River Plant, Units 1-5
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1,440
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OPCo
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Picway Plant
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100
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PSO
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Northeastern Station, Unit 4
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|
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470
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SWEPCo
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Welsh Plant, Unit 2
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528
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Total
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6,033
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As of June 30, 2013, the net book value of all of OPCo’s units above is zero and the net book value including related inventory and CWIP balances of the other plants in the table above was $873 million.
In the second quarter of 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote. As a result, in the second quarter of 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo’s net book value of Muskingum River Plant, Unit 5. We expect to retire the plant no later than 2015. See “Muskingum River Plant, Unit 5” section of Note 5.
In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units. The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:
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Generating
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Company
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Plant Name and Unit
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Capacity
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(in MWs)
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APCo
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Clinch River Plant, Units 1-2
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470
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I&M/AEGCo/KPCo
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Rockport Plant, Units 1-2
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2,620
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I&M
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Tanners Creek Plant, Unit 4
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500
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KPCo
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Big Sandy Plant, Unit 1
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278
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PSO
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Northeastern Station, Unit 3
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460
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Total
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4,328
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As of June 30, 2013, the net book value including related inventory and CWIP balances of the plants in the table above was $1.3 billion.
Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.
Modification of the New Source Review (NSR) Litigation Consent Decree
In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.
The consent decree requires certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019. In January 2013, an agreement to modify the consent decree was reached and filed with the court. The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures. The Federal EPA sought public comments on the modification prior to its entry by the court in May 2013. For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO2 control on both units in 2015 and imposes a declining plant-wide cap on SO2 emissions beginning in 2016.
Rockport Plant Clean Coal Technology Project (CCT Project)
In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both of its units at the Rockport Plant with a Dry Sorbent Injection system. The estimated cost in the application was $285 million, excluding AFUDC. In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s direct ownership share. Hearings at the IURC are scheduled for August 2013. A decision is expected by November 2013. As of June 30, 2013, we have incurred costs of $77 million related to the CCT Project, including AFUDC. If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows. See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.
Flint Creek Plant Environmental Controls
In 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. SWEPCo’s portion of those costs is estimated at $204 million. As of June 30, 2013, SWEPCo has incurred $24 million related to this project, including AFUDC and company overheads. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. See the “Flint Creek Plant Environmental Controls” section of Note 3.
Oklahoma Environmental Compliance Plan
In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) an estimated $210 million of new environmental investment, excluding AFUDC and overheads of $46 million, that will be incurred prior to 2016 at NES Unit 3, (b) accelerated recovery through 2026 of the net book value of NES Units 3 and 4 (combined net book value of the two units is $231 million as of June 30, 2013), (c) an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery in a future rate proceeding.
In January 2013, several parties filed testimony with various recommendations. In March 2013, the OCC granted a stay in this proceeding. In July 2013, the OCC staff filed a motion to lift the stay and dismiss PSO’s environmental compliance plan case without prejudice. A hearing on the motion will be held in August 2013. If this case is dismissed, PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.
If PSO is ultimately not permitted to fully recover its net book value of NES Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. See “Oklahoma Environmental Compliance Plan” section of Note 3.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements.
The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma. The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state. The Arkansas SIP was disapproved and the state is developing a revised submittal. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.
The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2, NOx and lead, and is currently reviewing the NAAQS for ozone. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations. We cannot currently predict the nature, stringency or timing of those requirements.
Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.
Cross-State Air Pollution Rule (CSAPR)
In August 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in March 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances was allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule. A supplemental rule includes Oklahoma in the seasonal NOx program. The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In December 2011, the court granted the motions for stay. In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing. The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.
The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers. We cannot predict the outcome of the pending litigation.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. Revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions, were issued by the Federal EPA in March 2013. The Federal EPA has reopened the public comment period to consider additional changes to the start-up and shut down provisions.
The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods. The compliance time frame remains a serious concern. A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines. We are participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.
Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding. The case is proceeding on the remaining issues and briefing was completed in April 2013.
Regional Haze
In 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality. The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule. PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties. In November 2012, we notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026. The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement. A revised regional haze SIP has been adopted by the State of Oklahoma and submitted to the Federal EPA for review.
CO2 Regulation
In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units. The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel. As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs. The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction. New source performance standards affect units that have not yet received permits. The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit. That case was dismissed because the court determined that no final agency action had yet been taken.
In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013. A proposal was sent to the Office of Management and Budget for interagency review the following week, but the details of the proposal are not known. The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016. In developing this proposal, the President directed the Federal EPA to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.” We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.
In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. A petition for rehearing was filed which the court denied in December 2012. Petitioners filed petitions for further review in the U.S. Supreme Court.
The Federal EPA also finalized a rule in June 2012 that retains the current CO2 emission thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources. The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016. Our generating units are large sources of CO2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.
Coal Combustion Residual Rule
In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The rule contains two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule. In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment. The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash. Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.
Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.
Clean Water Act Regulations
In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. We submitted comments in July 2012. Issuance of a final rule is not expected until November 2013. We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.
In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule was signed in April 2013 with a final rule expected in 2014. The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options. Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans. We will review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted. We plan to submit detailed comments to the Federal EPA.
Climate Change
National public policy makers and regulators in the 11 states we serve have diverse views on climate change. We are currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes. We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.
While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.
Several states have adopted programs that directly regulate CO2 emissions from power plants. The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. We are taking steps to comply with these requirements.
Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. We have been named in one remaining pending lawsuit, which we are defending. It is not possible to predict the outcome of this lawsuit or its impact on our operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” section of Note 4.
Future federal and state legislation or regulations that mandate limits on the emission of CO2 would 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 our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could reduce future net income and cash flows and impact financial condition.
For additional information on climate change, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2012 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
RESULTS OF OPERATIONS
SEGMENTS
Our primary business is the generation, transmission and distribution of electricity. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
Our reportable segments and their related business activities are outlined below:
Utility Operations
| |
·
|
Generation of electricity for sale to U.S. retail and wholesale customers.
|
| |
·
|
Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.
|
Transmission Operations
| |
·
|
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries and transmission joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
|
AEP River Operations
| |
·
|
Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.
|
Generation and Marketing
| |
·
|
Nonregulated generation in ERCOT.
|
| |
·
|
Marketing, risk management and retail activities in ERCOT, PJM and MISO.
|
The table below presents Net Income by segment for the three and six months ended June 30, 2013 and 2012.
| |
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
| |
|
2013
|
|
2012
|
|
2013
|
|
2012
|
| |
|
(in millions)
|
|
Utility Operations
|
$
|
222
|
|
$
|
365
|
|
$
|
571
|
|
$
|
749
|
|
Transmission Operations
|
|
18
|
|
|
8
|
|
|
31
|
|
|
17
|
|
AEP River Operations
|
|
(9)
|
|
|
3
|
|
|
(11)
|
|
|
12
|
|
Generation and Marketing
|
|
4
|
|
|
(5)
|
|
|
11
|
|
|
(6)
|
|
All Other (a)
|
|
104
|
|
|
(8)
|
|
|
101
|
|
|
(19)
|
|
Net Income
|
$
|
339
|
|
$
|
363
|
|
$
|
703
|
|
$
|
753
|
|
(a)
|
While not considered a reportable segment, All Other includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
|
AEP CONSOLIDATED
Second Quarter of 2013 Compared to Second Quarter of 2012
Net Income decreased from $363 million in 2012 to $339 million in 2013 primarily due to:
|
·
|
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
|
|
·
|
The loss of retail customers in Ohio to various CRES providers.
|
|
·
|
A decrease in margins from off-system sales primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins.
|
|
·
|
A decrease due to OPCo's second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
|
|
·
|
A decrease in weather-related usage.
|
|
·
|
An increase in storm-related expenses during the second quarter of 2013.
|
These decreases were partially offset by:
|
·
|
Successful rate proceedings in our various jurisdictions.
|
|
·
|
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
|
|
·
|
The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Net Income decreased from $753 million in 2012 to $703 million in 2013 primarily due to:
|
·
|
The second quarter 2013 impairment of Muskingum River Plant, Unit 5.
|
|
·
|
The loss of retail customers in Ohio to various CRES providers.
|
|
·
|
A decrease in margins from off-system sales primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins.
|
|
·
|
An increase in plant outages during 2013.
|
|
·
|
A decrease in AEP River Operations' 2013 earnings due to weak demand for grain and coal and river conditions in the first quarter of 2013.
|
|
·
|
A decrease due to OPCo's second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
|
|
·
|
A first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
|
These decreases were partially offset by:
|
·
|
Successful rate proceedings in our various jurisdictions.
|
|
·
|
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
|
|
·
|
The deferral of Ohio capacity costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
|
·
|
An increase in weather-related usage in the first quarter of 2013.
|
Our results of operations are discussed below by operating segment.
UTILITY OPERATIONS
We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment. Gross Margin represents total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased electricity.
| |
|
Three Months Ended
|
|
Six Months Ended
|
| |
|
June 30,
|
|
June 30,
|
| |
|
2013
|
|
2012
|
|
2013
|
|
2012
|
| |
|
(in millions)
|
|
Revenues
|
$
|
3,278
|
|
$
|
3,258
|
|
$
|
6,795
|
|
$
|
6,643
|
|
Fuel and Purchased Electricity
|
|
1,130
|
|
|
1,096
|
|
|
2,407
|
|
|
2,365
|
|
Gross Margin
|
|
2,148
|
|
|
2,162
|
|
|
4,388
|
|
|
4,278
|
|
Other Operation and Maintenance
|
|
806
|
|
|
770
|
|
|
1,685
|
|
|
1,525
|
|
Asset Impairments and Other Related Charges
|
|
154
|
|
|
-
|
|
|
154
|
|
|
-
|
|
Depreciation and Amortization
|
|
429
|
|
|
448
|
|
|
835
|
|
|
860
|
|
Taxes Other Than Income Taxes
|
|
213
|
|
|
202
|
|
|
422
|
|
|
413
|
|
Operating Income
|
|
546
|
|
|
742
|
|
|
1,292
|
|
|
1,480
|
|
Interest and Investment Income
|
|
6
|
|
|
2
|
|
|
9
|
|
|
3
|
|
Carrying Costs Income
|
|
8
|
|
|
11
|
|
|
12
|
|
|
31
|
|
Allowance for Equity Funds Used During Construction
|
|
10
|
|
|
20
|
|
|
20
|
|
|
40
|
|
Interest Expense
|
|
(221)
|
|
|
(224)
|
|
|
(447)
|
|
|
(441)
|
|
Income Before Income Tax Expense and Equity
|
|
|
|
|
|
|
|
|
|
|
|
| |
Earnings
|
|
349
|
|
|
551
|
|
|
886
|
|
|
1,113
|
|
Income Tax Expense
|
|
127
|
|
|
186
|
|
|
315
|
|
|
365
|
|
Equity Earnings of Unconsolidated Subsidiaries
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
Net Income
|
$
|
222
|
|
$
|
365
|
|
$
|
571
|
|
$
|
749
|
|
Summary of KWh Energy Sales for Utility Operations
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended
|
|
Six Months Ended
|
| |
|
June 30,
|
|
June 30,
|
| |
2013
|
|
2012
|
|
2013
|
|
2012
|
| |
|
(in millions of KWhs)
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential
|
|
12,630
|
|
|
13,155
|
|
|
28,885
|
|
|
27,954
|
| |
Commercial
|
|
12,553
|
|
|
13,087
|
|
|
24,104
|
|
|
24,353
|
| |
Industrial
|
|
14,601
|
|
|
15,422
|
|
|
28,363
|
|
|
30,069
|
| |
Miscellaneous
|
|
747
|
|
|
779
|
|
|
1,455
|
|
|
1,500
|
|
Total Retail (a)
|
|
40,531
|
|
|
42,443
|
|
|
82,807
|
|
|
83,876
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
9,180
|
|
|
8,620
|
|
|
20,204
|
|
|
17,533
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Total KWhs
|
|
49,711
|
|
|
51,063
|
|
|
103,011
|
|
|
101,409
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Represents energy delivered to distribution customers.
|
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income. In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.
|
Summary of Heating and Cooling Degree Days for Utility Operations
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended
|
|
Six Months Ended
|
| |
|
June 30,
|
June 30,
|
| |
|
2013
|
|
2012
|
|
2013
|
|
2012
|
| |
|
(in degree days)
|
|
Eastern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual - Heating (a)
|
|
167
|
|
|
118
|
|
|
1,985
|
|
|
1,379
|
|
Normal - Heating (b)
|
|
161
|
|
|
165
|
|
|
1,880
|
|
|
1,916
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual - Cooling (c)
|
|
351
|
|
|
401
|
|
|
351
|
|
|
429
|
|
Normal - Cooling (b)
|
|
306
|
|
|
300
|
|
|
310
|
|
|
303
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual - Heating (a)
|
|
54
|
|
|
1
|
|
|
606
|
|
|
348
|
|
Normal - Heating (b)
|
|
18
|
|
|
20
|
|
|
587
|
|
|
601
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual - Cooling (d)
|
|
797
|
|
|
961
|
|
|
867
|
|
|
1,094
|
|
Normal - Cooling (b)
|
|
786
|
|
|
774
|
|
|
848
|
|
|
834
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
|
|
(b)
|
Normal Heating/Cooling represents the thirty-year average of degree days.
|
|
(c)
|
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
|
|
(d)
|
Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.
|
Second Quarter of 2013 Compared to Second Quarter of 2012
| |
|
|
|
|
|
|
|
|
Reconciliation of Second Quarter of 2012 to Second Quarter of 2013
|
|
Net Income from Utility Operations
|
|
(in millions)
|
| |
|
|
|
|
|
|
|
|
Second Quarter of 2012
|
|
|
|
|
$
|
365
|
| |
|
|
|
|
|
|
|
|
Changes in Gross Margin:
|
|
|
|
|
|
|
|
Retail Margins
|
|
|
|
|
|
7
|
|
Off-system Sales
|
|
|
|
|
|
(46)
|
|
Transmission Revenues
|
|
|
|
|
|
13
|
|
Other Revenues
|
|
|
|
|
|
12
|
|
Total Change in Gross Margin
|
|
|
|
|
|
(14)
|
| |
|
|
|
|
|
|
|
Changes in Expenses and Other:
|
|
|
|
|
|
|
|
Other Operation and Maintenance
|
|
|
|
|
|
(36)
|
|
Asset Impairments and Other Related Charges
|
|
|
|
|
|
(154)
|
|
Depreciation and Amortization
|
|
|
|
|
|
19
|
|
Taxes Other Than Income Taxes
|
|
|
|
|
|
(11)
|
|
Interest and Investment Income
|
|
|
|
|
|
4
|
|
Carrying Costs Income
|
|
|
|
|
|
(3)
|
|
Allowance for Equity Funds Used During Construction
|
|
|
|
|
|
(10)
|
|
Interest Expense
|
|
|
|
|
|
3
|
|
Total Change in Expenses and Other
|
|
|
|
|
|
(188)
|
| |
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
|
|
|
59
|
| |
|
|
|
|
|
|
|
|
Second Quarter of 2013
|
|
|
|
|
$
|
222
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
|
·
|
Retail Margins increased $7 million primarily due to the following:
|
| |
·
|
Successful rate proceedings in our service territories which include:
|
| |
|
·
|
An $85 million rate increase for OPCo.
|
| |
|
·
|
A $44 million rate increase for I&M.
|
| |
|
·
|
A $24 million rate increase for SWEPCo.
|
| |
|
|
|
For the rate increases described above, $48 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
|
| |
·
|
A $26 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
| |
These increases were partially offset by:
|
| |
·
|
A $66 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
|
| |
·
|
A $46 million increase in other variable electric generation expenses.
|
| |
·
|
A $35 million decrease due to OPCo's second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
|
| |
·
|
A $28 million decrease in weather-related usage primarily due to 12% and 17% decreases in cooling degree days in our eastern and western regions, respectively.
|
|
·
|
Margins from Off-system Sales decreased $46 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins. The decrease in CRES capacity revenues is partially offset in other expense items below.
|
|
·
|
Transmission Revenues increased $13 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP region. The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
|
|
·
|
Other Revenues increased $12 million primarily due to increases in gains on other miscellaneous sales.
|
Expenses and Other and Income Tax Expense changed between years as follows:
|
·
|
Other Operation and Maintenance expenses increased $36 million primarily due to the following:
|
| |
·
|
A $21 million increase in storm-related expenses.
|
| |
·
|
A $20 million increase in plant outages.
|
| |
·
|
A $19 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins.
|
| |
·
|
A $12 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
|
| |
These increases were partially offset by:
|
| |
·
|
A $13 million decrease in administrative and general expenses.
|
| |
·
|
A $13 million decrease due to expenses recorded in 2012 related to the 2012 sustainable cost reductions program.
|
| |
·
|
A $12 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
|
·
|
Asset Impairments and Other Related Charges increased by $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
|
|
·
|
Depreciation and Amortization expenses decreased $19 million primarily due to the following:
|
| |
·
|
A $26 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
|
| |
·
|
A $15 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
| |
These decreases were partially offset by:
|
| |
·
|
An $11 million increase due to the Turk Plant being placed in service in December 2012.
|
| |
·
|
Overall higher depreciable property balances.
|
|
·
|
Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes as a result of increased capital investments.
|
|
·
|
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to completed construction of the Turk Plant in December 2012.
|
|
·
|
Income Tax Expense decreased $59 million primarily due to a decrease in pretax book income.
|
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
| |
|
|
|
|
|
|
|
|
Reconciliation of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
|
|
Net Income from Utility Operations
|
|
(in millions)
|
| |
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2012
|
|
|
|
|
$
|
749
|
| |
|
|
|
|
|
|
|
|
Changes in Gross Margin:
|
|
|
|
|
|
|
|
Retail Margins
|
|
|
|
|
|
125
|
|
Off-system Sales
|
|
|
|
|
|
(75)
|
|
Transmission Revenues
|
|
|
|
|
|
35
|
|
Other Revenues
|
|
|
|
|
|
25
|
|
Total Change in Gross Margin
|
|
|
|
|
|
110
|
| |
|
|
|
|
|
|
|
Changes in Expenses and Other:
|
|
|
|
|
|
|
|
Other Operation and Maintenance
|
|
|
|
|
|
(160)
|
|
Asset Impairments and Other Related Charges
|
|
|
|
|
|
(154)
|
|
Depreciation and Amortization
|
|
|
|
|
|
25
|
|
Taxes Other Than Income Taxes
|
|
|
|
|
|
(9)
|
|
Interest and Investment Income
|
|
|
|
|
|
6
|
|
Carrying Costs Income
|
|
|
|
|
|
(19)
|
|
Allowance for Equity Funds Used During Construction
|
|
|
|
|
|
(20)
|
|
Interest Expense
|
|
|
|
|
|
(6)
|
|
Equity Earnings of Unconsolidated Subsidiaries
|
|
|
|
|
|
(1)
|
|
Total Change in Expenses and Other
|
|
|
|
|
|
(338)
|
| |
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
|
|
|
50
|
| |
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2013
|
|
|
|
|
$
|
571
|
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
|
·
|
Retail Margins increased $125 million primarily due to the following:
|
| |
·
|
Successful rate proceedings in our service territories which include:
|
| |
|
·
|
A $146 million rate increase for OPCo.
|
| |
|
·
|
A $52 million rate increase for I&M.
|
| |
|
·
|
A $47 million rate increase for SWEPCo.
|
| |
|
·
|
A $21 million rate increase for APCo.
|
| |
|
|
|
For the rate increases described above, $109 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
|
| |
·
|
A $50 million net increase in weather-related usage in our eastern and western regions primarily due to increases of 44% and 74%, respectively, in heating degree days in our eastern and western regions, respectively, partially offset by decreases in cooling degree days of 18% and 21% in our eastern and western regions, respectively.
|
| |
·
|
A $47 million increase due to the deferral of consumables and purchased power as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
| |
These increases were partially offset by:
|
| |
·
|
A $153 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
|
| |
·
|
A $66 million increase in other variable electric generation expenses.
|
| |
·
|
A $35 million decrease due to OPCo's second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
|
|
·
|
Margins from Off-system Sales decreased $75 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues and reduced trading and marketing margins, partially offset by higher physical sales volumes and margins. The decrease in CRES capacity revenues is partially offset in other expense items below.
|
|
·
|
Transmission Revenues increased $35 million primarily due to increased transmission revenues from Ohio customers who have switched to alternative CRES providers and rate increases for customers in the SPP region. The increase in transmission revenues related to CRES providers offsets a portion of the lost revenues included in Retail Margins above.
|
|
·
|
Other Revenues increased $25 million primarily due to increases in gains on other miscellaneous sales.
|
Expenses and Other and Income Tax Expense changed between years as follows:
|
·
|
Other Operation and Maintenance expenses increased $160 million primarily due to the following:
|
| |
·
|
A $45 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins.
|
| |
·
|
A $42 million increase in plant outages during 2013.
|
| |
·
|
A $35 million increase due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
|
| |
·
|
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
|
| |
·
|
A $28 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
|
| |
·
|
A $26 million increase in storm-related expenses primarily in APCo's service territory.
|
| |
These increases were partially offset by:
|
| |
·
|
A $25 million decrease due to an agreement reached to settle an insurance claim in the first quarter of 2013.
|
| |
·
|
A $20 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
|
·
|
Asset Impairments and Other Related Charges increased $154 million due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
|
|
·
|
Depreciation and Amortization expenses decreased $25 million primarily due to the following:
|
| |
·
|
A $53 million decrease as a result of depreciation ceasing on certain Ohio generating plants that were impaired in November 2012.
|
| |
·
|
A $35 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity deferral mechanism.
|
| |
These decreases were partially offset by:
|
| |
·
|
A $22 million increase due to the Turk Plant being placed in service in December 2012.
|
| |
·
|
Overall higher depreciable property balances.
|
|
·
|
Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes as a result of increased capital investments.
|
|
·
|
Carrying Costs Income decreased $19 million primarily due to the following:
|
| |
·
|
A $10 million decrease due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
|
| |
·
|
An $8 million decrease in carrying costs income due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
|
|
·
|
Allowance for Equity Funds Used During Construction decreased $20 million primarily due to completed construction of the Turk Plant in December 2012.
|
|
·
|
Income Tax Expense decreased $50 million primarily due to a decrease in pretax book income partially offset by audit settlements for previous years recorded in 2012 and other book/tax differences which are accounted for on a flow through basis.
|
TRANSMISSION OPERATIONS
Second Quarter of 2013 Compared to Second Quarter of 2012
Net Income from our Transmission Operations segment increased from $8 million in 2012 to $18 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Net Income from our Transmission Operations segment increased from $17 million in 2012 to $31 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.
AEP RIVER OPERATIONS
Second Quarter of 2013 Compared to Second Quarter of 2012
Net Income from our AEP River Operations segment decreased from income of $3 million in 2012 to a loss of $9 million in 2013 primarily due to weak demand for grain and coal.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Net Income from our AEP River Operations segment decreased from income of $12 million in 2012 to a loss of $11 million in 2013 primarily due to weak demand for grain and coal and the 2012 drought which continued to have negative impacts on river conditions in the first quarter of 2013.
GENERATION AND MARKETING
Second Quarter of 2013 Compared to Second Quarter of 2012
Net Income from our Generation and Marketing segment increased from a loss of $5 million in 2012 to income of $4 million in 2013 primarily due to higher trading and marketing margins and increased retail activity.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Net Income from our Generation and Marketing segment increased from a loss of $6 million in 2012 to income of $11 million in 2013 primarily due to higher trading and marketing margins and increased retail activity resulting from our March 2012 acquisition of BlueStar.
ALL OTHER
Second Quarter of 2013 Compared to Second Quarter of 2012
Net Income from All Other increased from a loss of $8 million in 2012 to income of $104 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Net Income from All Other increased from a loss of $19 million in 2012 to income of $101 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.
AEP SYSTEM INCOME TAXES
Second Quarter of 2013 Compared to Second Quarter of 2012
Income Tax Expense decreased $122 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
Income Tax Expense decreased $116 million primarily due to the recognition of the tax benefits associated with the U.K. Windfall Tax decision and a decrease in pre-tax book income, partially offset by audit settlements for previous years recorded in 2012.
FINANCIAL CONDITION
We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
| |
|
June 30, 2013
|
|
December 31, 2012
|
| |
|
(dollars in millions)
|
|
Long-term Debt, including amounts due within one year
|
$
|
17,618
|
|
50.8
|
%
|
|
$
|
17,757
|
|
52.3
|
%
|
|
Short-term Debt
|
|
1,538
|
|
4.4
|
|
|
|
981
|
|
2.9
|
|
|
Total Debt
|
|
19,156
|
|
55.2
|
|
|
|
18,738
|
|
55.2
|
|
|
AEP Common Equity
|
|
15,537
|
|
44.8
|
|
|
|
15,237
|
|
44.8
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt and Equity Capitalization
|
$
|
34,693
|
|
100.0
|
%
|
|
$
|
33,975
|
|
100.0
|
%
|
Our ratio of debt-to-total capital remained unchanged at 55.2% as of December 31, 2012 and June 30, 2013. Short-term debt outstanding increased primarily due to borrowing for our commercial paper program under credit facilities and our common equity increased due to earnings.
Liquidity
Liquidity, or access to cash, is an important factor in determining our financial stability. We believe we have adequate liquidity under our existing credit facilities. As of June 30, 2013, we had $4.5 billion in aggregate credit facility commitments to support our operations. Additional liquidity is available from cash from operations and a receivables securitization agreement. We are committed to maintaining adequate liquidity. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, sale-and-leaseback or leasing agreements or common stock.
Credit Facilities
We manage our liquidity by maintaining adequate external financing commitments. As of June 30, 2013, our available liquidity was approximately $3.4 billion as illustrated in the table below:
| |
|
|
Amount
|
|
|
Maturity
|
| |
|
|
(in millions)
|
|
|
|
|
Commercial Paper Backup:
|
|
|
|
|
|
|
| |
Revolving Credit Facility
|
|
$
|
1,750
|
|
|
June 2016
|
| |
Revolving Credit Facility
|
|
|
1,750
|
|
|
July 2017
|
|
Term Credit Facility
|
|
|
1,000
|
|
|
May 2015
|
|
Total
|
|
|
4,500
|
|
|
|
|
Cash and Cash Equivalents
|
|
|
117
|
|
|
|
|
Total Liquidity Sources
|
|
|
4,617
|
|
|
|
|
Less:
|
AEP Commercial Paper Outstanding
|
|
|
850
|
|
|
|
| |
Letters of Credit Issued
|
|
|
120
|
|
|
|
| |
Draw on Term Credit Facility
|
|
|
200
|
|
|
|
| |
|
|
|
|
|
|
|
|
Net Available Liquidity
|
|
$
|
3,447
|
|
|
|
We have credit facilities totaling $3.5 billion to support our commercial paper program. The credit facilities allow us to issue letters of credit in an amount up to $1.2 billion.
We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The maximum amount of commercial paper outstanding during the first six months of 2013 was $866 million. The weighted-average interest rate for our commercial paper during 2013 was 0.34%.
In February 2013, we entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution. In July 2013, we terminated the $1 billion term credit facility. In July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate the corporate separation of generation assets from transmission and distribution.
Securitized Accounts Receivable
In June 2013, we amended our receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. We amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015.
West Virginia Securitization of Regulatory Assets
In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets. In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs. In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC, which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs. Hearings at the WVPSC are scheduled for July 2013.
Ohio Securitization of Regulatory Assets
In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance. As of June 30, 2013, OPCo’s DARR balance was $268 million, including $126 million of unrecognized equity carrying costs. The DARR is being recovered through 2018 by a non-bypassable rider. Once the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over a period not to exceed eight years. The securitization bonds are expected to be issued in the third quarter of 2013.
Debt Covenants and Borrowing Limitations
Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in our revolving credit agreements. Debt as defined in the revolving credit agreements excludes securitization bonds and debt of AEP Credit. As of June 30, 2013, this contractually-defined percentage was 51.6%. Nonperformance under these covenants could result in an event of default under these credit agreements. As of June 30, 2013, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable. However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.
The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.
The term credit facility may be drawn upon until February 2014. Repayments prior to maturity are permitted. However, any amount that is repaid may not be re-borrowed and is a permanent reduction of the facility.
Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. As of June 30, 2013, we had not exceeded those authorized limits.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.49 per share in July 2013. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Our income derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.
We do not believe restrictions related to our various financing arrangements and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.
Credit Ratings
We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings. In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.
CASH FLOW
Managing our cash flows is a major factor in maintaining our liquidity strength.
| |
|
|
Six Months Ended
|
| |
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
| |
|
|
(in millions)
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
$
|
279
|
|
$
|
221
|
|
Net Cash Flows from Operating Activities
|
|
|
1,516
|
|
|
1,713
|
|
Net Cash Flows Used for Investing Activities
|
|
|
(1,643)
|
|
|
(1,530)
|
|
Net Cash Flows Used for Financing Activities
|
|
|
(35)
|
|
|
(107)
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(162)
|
|
|
76
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
117
|
|
$
|
297
|
Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
| |
|
|
|
|
|
|
|
| |
|
|
Six Months Ended
|
| |
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
| |
|
|
(in millions)
|
|
Net Income
|
|
$
|
703
|
|
$
|
753
|
|
Depreciation and Amortization
|
|
|
863
|
|
|
883
|
|
Other
|
|
|
(50)
|
|
|
77
|
|
Net Cash Flows from Operating Activities
|
|
$
|
1,516
|
|
$
|
1,713
|
Net Cash Flows from Operating Activities were $1.5 billion in 2013 consisting primarily of Net Income of $703 million, $863 million of noncash Depreciation and Amortization and $154 million of Asset Impairments related to Muskingum River Plant, Unit 5 partially offset by $102 million of Ohio capacity deferrals as a result of the PUCO's July 2012 approval of a capacity deferral mechanism. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax/book temporary differences from operations. Net cash flows for Accrued Taxes were a result of recording the estimated federal tax loss associated with tax/book temporary differences and the recognition of the tax benefit related to the U.K. Windfall Tax.
Net Cash Flows from Operating Activities were $1.7 billion in 2012 consisting primarily of Net Income of $753 million and $883 million of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild winter weather. Cash was also used to pay real and personal property taxes and to reduce accounts payable. Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.
| |
|
|
|
|
|
|
|
| |
|
|
Six Months Ended
|
| |
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
| |
|
|
(in millions)
|
|
Construction Expenditures
|
|
$
|
(1,637)
|
|
$
|
(1,371)
|
|
Acquisitions of Nuclear Fuel
|
|
|
(59)
|
|
|
(11)
|
|
Acquisitions of Assets/Businesses
|
|
|
(4)
|
|
|
(88)
|
|
Insurance Proceeds Related to Cook Plant Fire
|
|
|
72
|
|
|
-
|
|
Proceeds from Sales of Assets
|
|
|
11
|
|
|
8
|
|
Other
|
|
|
(26)
|
|
|
(68)
|
|
Net Cash Flows Used for Investing Activities
|
|
$
|
(1,643)
|
|
$
|
(1,530)
|
Net Cash Flows Used for Investing Activities were $1.6 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.
Net Cash Flows Used for Investing Activities were $1.5 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments. Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.
| |
|
|
|
|
|
|
|
| |
|
|
Six Months Ended
|
| |
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
| |
|
|
(in millions)
|
|
Issuance of Common Stock, Net
|
|
$
|
41
|
|
$
|
50
|
|
Issuance of Debt, Net
|
|
|
425
|
|
|
332
|
|
Dividends Paid on Common Stock
|
|
|
(469)
|
|
|
(458)
|
|
Other
|
|
|
(32)
|
|
|
(31)
|
|
Net Cash Flows Used for Financing Activities
|
|
$
|
(35)
|
|
$
|
(107)
|
Net Cash Flows Used for Financing Activities in 2013 were $35 million. Our net debt issuances were $425 million. The net issuances included issuances of $475 million of senior unsecured notes, a $200 million draw on a $1 billion term credit facility, $170 million of pollution control bonds, $101 million of notes payable and an increase in short-term borrowing of $557 million offset by retirements of $796 million of senior unsecured and other debt notes, $131 million of securitization bonds and $146 million of pollution control bonds. We paid common stock dividends of $469 million. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows Used for Financing Activities in 2012 were $107 million. Our net debt issuances were $332 million. The net issuances included issuances of $800 million of securitization bonds, $275 million of senior unsecured notes and $197 million of notes payable and other debt offset by retirements of $234 million of senior unsecured and other debt notes, $155 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $442 million. We paid common stock dividends of $458 million.
In July 2013, I&M retired $12 million of Notes Payable related to DCC Fuel.
In July 2013, OPCo retired $65 million of 4.9% Pollution Control Bonds due in 2037 and issued $65 million of variable rate Pollution Control Bonds due in 2014.
OFF-BALANCE SHEET ARRANGEMENTS
In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including reducing operational expenses and spreading risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business. The following identifies significant off-balance sheet arrangements:
| |
|
|
June 30,
|
|
December 31,
|
| |
|
|
2013
|
|
2012
|
| |
|
|
(in millions)
|
|
Rockport Plant, Unit 2 Future Minimum Lease Payments
|
|
$
|
1,404
|
|
$
|
1,478
|
|
Railcars Maximum Potential Loss From Lease Agreement
|
|
|
19
|
|
|
25
|
For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report.
CONTRACTUAL OBLIGATION INFORMATION
A summary of our contractual obligations is included in our 2012 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
ACCOUNTING PRONOUNCEMENTS
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, coal and emission allowance trading and marketing contracts. These risks include commodity price risk, interest rate risk and credit risk. In addition, we are exposed to foreign currency exchange risk as we occasionally procure various services and materials used in our energy business from foreign suppliers. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.
Our Generation and Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.
We employ risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts. We engage in risk management of power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The CORC consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.
The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2012:
| |
MTM Risk Management Contract Net Assets (Liabilities)
|
| |
Six Months Ended June 30, 2013
|
| |
|
| |
|
|
|
Generation
|
|
|
| |
|
Utility
|
and
|
|
| |
|
Operations
|
Marketing
|
Total
|
| |
|
(in millions)
|
|
Total MTM Risk Management Contract Net Assets
|
|
|
|
|
|
|
|
|
| |
as of December 31, 2012
|
$
|
68
|
|
$
|
128
|
|
$
|
196
|
|
(Gain) Loss from Contracts Realized/Settled During the Period and
|
|
|
|
|
|
|
|
|
| |
Entered in a Prior Period
|
|
(17)
|
|
|
(11)
|
|
|
(28)
|
|
Fair Value of New Contracts at Inception When Entered During the
|
|
|
|
|
|
|
|
|
| |
Period (a)
|
|
-
|
|
|
10
|
|
|
10
|
|
Changes in Fair Value Due to Market Fluctuations During the
|
|
|
|
|
|
|
|
|
| |
Period (b)
|
|
1
|
|
|
13
|
|
|
14
|
|
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
12
|
|
|
-
|
|
|
12
|
|
Total MTM Risk Management Contract Net Assets
|
|
|
|
|
|
|
|
|
| |
as of June 30, 2013
|
$
|
64
|
|
$
|
140
|
|
|
204
|
| |
|
|
|
|
|
|
|
|
|
|
Commodity Cash Flow Hedge Contracts
|
|
|
|
|
|
|
|
2
|
|
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
|
|
|
|
|
|
|
|
(2)
|
|
Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
(12)
|
|
Collateral Deposits
|
|
|
|
|
|
|
|
20
|
|
Total MTM Derivative Contract Net Assets as of June 30, 2013
|
|
|
|
|
|
|
$
|
212
|
|
(a)
|
Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
|
|
(b)
|
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
|
|
(c)
|
Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
|
See Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to our risk management contracts. The following tables and discussion provide information on our credit risk and market volatility risk.
Credit Risk
We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of June 30, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.1%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of June 30, 2013, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
| |
|
|
Exposure
|
|
|
|
|
|
Number of
|
|
Net Exposure
|
| |
|
Before
|
|
|
Counterparties
|
of
|
| |
|
Credit
|
Credit
|
Net
|
>10% of
|
Counterparties
|
|
Counterparty Credit Quality
|
Collateral
|
Collateral
|
Exposure
|
Net Exposure
|
>10%
|
| |
|
|
(in millions, except number of counterparties)
|
|
Investment Grade
|
|
$
|
594
|
|
$
|
1
|
|
$
|
593
|
|
|
2
|
|
$
|
263
|
|
Split Rating
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Noninvestment Grade
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
-
|
|
No External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Internal Investment Grade
|
|
|
71
|
|
|
-
|
|
|
71
|
|
|
3
|
|
|
29
|
| |
Internal Noninvestment Grade
|
|
|
69
|
|
|
11
|
|
|
58
|
|
|
2
|
|
|
40
|
|
Total as of June 30, 2013
|
|
$
|
736
|
|
$
|
14
|
|
$
|
722
|
|
|
8
|
|
$
|
332
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total as of December 31, 2012
|
|
$
|
807
|
|
$
|
13
|
|
$
|
794
|
|
|
7
|
|
$
|
338
|
Value at Risk (VaR) Associated with Risk Management Contracts
We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of June 30, 2013, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.
The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:
VaR Model
|
Six Months Ended
|
|
Twelve Months Ended
|
|
June 30, 2013
|
|
December 31, 2012
|
|
End
|
|
High
|
|
Average
|
|
Low
|
|
End
|
|
High
|
|
Average
|
|
Low
|
|
(in millions)
|
|
(in millions)
|
|
$
|
-
|
|
$
|
1
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1
|
|
$
|
-
|
|
$
|
-
|
We back-test our VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements. We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss. We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.
Interest Rate Risk
We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of June 30, 2013 and December 31, 2012, the estimated EaR on our debt portfolio for the following twelve months was $39 million and $42 million, respectively.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
|
|
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
|
|
For the Three and Six Months Ended June 30, 2013 and 2012
|
|
(in millions, except per-share and share amounts)
|
|
(Unaudited)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Three Months Ended
|
|
Six Months Ended
|
| |
|
|
June 30,
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
$
|
3,253
|
|
$
|
3,235
|
|
$
|
6,742
|
|
$
|
6,598
|
|
Other Revenues
|
|
|
329
|
|
|
316
|
|
|
666
|
|
|
578
|
|
TOTAL REVENUES
|
|
|
3,582
|
|
|
3,551
|
|
|
7,408
|
|
|
7,176
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel and Other Consumables Used for Electric Generation
|
|
|
908
|
|
|
904
|
|
|
1,939
|
|
|
1,957
|
|
Purchased Electricity for Resale
|
|
|
359
|
|
|
268
|
|
|
730
|
|
|
528
|
|
Other Operation
|
|
|
664
|
|
|
719
|
|
|
1,402
|
|
|
1,375
|
|
Maintenance
|
|
|
285
|
|
|
252
|
|
|
578
|
|
|
514
|
|
Asset Impairments and Other Related Charges
|
|
|
154
|
|
|
-
|
|
|
154
|
|
|
-
|
|
Depreciation and Amortization
|
|
|
443
|
|
|
460
|
|
|
863
|
|
|
883
|
|
Taxes Other Than Income Taxes
|
|
|
222
|
|
|
207
|
|
|
440
|
|
|
424
|
|
TOTAL EXPENSES
|
|
|
3,035
|
|
|
2,810
|
|
|
6,106
|
|
|
5,681
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
547
|
|
|
741
|
|
|
1,302
|
|
|
1,495
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and Investment Income
|
|
|
49
|
|
|
2
|
|
|
52
|
|
|
4
|
|
Carrying Costs Income
|
|
|
8
|
|
|
11
|
|
|
12
|
|
|
31
|
|
Allowance for Equity Funds Used During Construction
|
|
|
17
|
|
|
24
|
|
|
32
|
|
|
47
|
|
Interest Expense
|
|
|
(228)
|
|
|
(235)
|
|
|
(460)
|
|
|
(464)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
|
|
|
393
|
|
|
543
|
|
|
938
|
|
|
1,113
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
68
|
|
|
190
|
|
|
263
|
|
|
379
|
|
Equity Earnings of Unconsolidated Subsidiaries
|
|
|
14
|
|
|
10
|
|
|
28
|
|
|
19
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
339
|
|
|
363
|
|
|
703
|
|
|
753
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Noncontrolling Interests
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
2
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
|
|
$
|
338
|
|
$
|
362
|
|
$
|
701
|
|
$
|
751
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
|
|
|
486,293,026
|
|
|
484,500,029
|
|
|
486,059,643
|
|
|
484,164,065
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
SHAREHOLDERS
|
|
$
|
0.69
|
|
$
|
0.75
|
|
$
|
1.44
|
|
$
|
1.55
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
|
|
|
486,763,615
|
|
|
484,860,690
|
|
|
486,555,121
|
|
|
484,554,779
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
SHAREHOLDERS
|
|
$
|
0.69
|
|
$
|
0.75
|
|
$
|
1.44
|
|
$
|
1.55
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH DIVIDENDS DECLARED PER SHARE
|
|
$
|
0.49
|
|
$
|
0.47
|
|
$
|
0.96
|
|
$
|
0.94
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
|
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
For the Three and Six Months Ended June 30, 2013 and 2012
|
|
(in millions)
|
|
(Unaudited)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Three Months Ended
|
|
Six Months Ended
|
| |
|
|
June 30,
|
|
June 30,
|
| |
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
Net Income
|
|
$
|
339
|
|
$
|
363
|
|
$
|
703
|
|
$
|
753
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges, Net of Tax of $5 and $5 for the Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
June 30, 2013 and 2012, Respectively, and $8 and $11 for the Six
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Months Ended June 30, 2013 and 2012, Respectively
|
|
|
(10)
|
|
|
(10)
|
|
|
14
|
|
|
(21)
|
|
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Ended June 30, 2013 and 2012, Respectively, and $- and $1 for the
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Six Months Ended June 30, 2013 and 2012, Respectively
|
|
|
-
|
|
|
(1)
|
|
|
1
|
|
|
1
|
|
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $2
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
and $4 for the Three Months Ended June 30, 2013 and 2012,
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Respectively, and $5 and $8 for the Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
2013 and 2012, Respectively
|
|
|
3
|
|
|
8
|
|
|
9
|
|
|
15
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
(7)
|
|
|
(3)
|
|
|
24
|
|
|
(5)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL COMPREHENSIVE INCOME
|
|
|
332
|
|
|
360
|
|
|
727
|
|
|
748
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Income Attributable to Noncontrolling Interests
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
2
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
COMMON SHAREHOLDERS
|
|
$
|
331
|
|
$
|
359
|
|
$
|
725
|
|
$
|
746
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 37.
|
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
|
|
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
|
|
For the Six Months Ended June 30, 2013 and 2012
|
|
(in millions)
|
|
(Unaudited)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
AEP Common Shareholders
|
|
|
|
|
| |
Common Stock
|
|
|
|
|
|
Accumulated
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
| |
|
|
|
|
Paid-in
|
|
Retained
|
|
Comprehensive
|
|
Noncontrolling
|
|
|
| |
Shares
|
|
Amount
|
|
Capital
|
|
Earnings
|
|
Income (Loss)
|
|
Interests
|
|
Total
|
|
TOTAL EQUITY – DECEMBER 31, 2011
|
|
504
|
|
$
|
3,274
|
|
$
|
5,970
|
|
$
|
5,890
|
|
$
|
(470)
|
|
$
|
1
|
|
$
|
14,665
|
| |
|