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EX-4 - IPALCO 2013 Q2 EXHIBIT 4.1 - IPALCO ENTERPRISES, INC.exhibit041.htm
EX-31 - IPALCO 2013 Q2 EXHIBIT 31.1 - IPALCO ENTERPRISES, INC.exh311.htm
EX-31 - IPALCO 2013 Q2 EXHIBIT 31.2 - IPALCO ENTERPRISES, INC.exh312.htm
EX-32 - IPALCO 2013 Q2 EXHIBIT 32 - IPALCO ENTERPRISES, INC.exh32.htm
10-Q - IPALCO 2013 Q2 FORM 10-Q PDF CONFIRMING COPY - IPALCO ENTERPRISES, INC.ipalco2013q210qfinal.pdf
EXCEL - IDEA: XBRL DOCUMENT - IPALCO ENTERPRISES, INC.Financial_Report.xls

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q 

 

(Mark One)

þ 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 

Commission file number 1-8644 

IPALCO ENTERPRISES, INC.
(Exact name of registrant as specified in its charter) 

 

 

 

 

 

 

 

Indiana 

 

35-1575582

(State or other jurisdiction of incorporation or organization)

 

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

One Monument Circle
Indianapolis,  Indiana 

 

46204

(Address of principal executive offices)

 

(Zip Code)

 

 

 

Registrant’s telephone number, including area code: 317-261-8261

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨   No þ

(Registrant is a voluntary filer that has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ  No ¨

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

 

 

Large accelerated filer ¨   

Accelerated filer ¨   

Non-accelerated filer (Do not check if a smaller reporting company) þ

Smaller reporting company ¨

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨   No þ 

At August 7, 2013,  89,685,177 shares of IPALCO Enterprises, Inc. common stock were outstanding. All of such shares were owned by The AES Corporation.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT


 

IPALCO ENTERPRISES, INC.

QUARTERLY Report on Form 10-q 

For Quarter Ended June 30, 2013

 

Table of Contents

 

 

 

 

Item No.

 

Page No.

 

                CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

3

 

Part I – FINANCIAL INFORMATION

1.

Financial Statements

 

 

Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three Months and Six Months ended June 30, 2013 and 2012

4

 

Unaudited Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012

5

 

Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months ended June 30, 2013 and 2012

6

 

Unaudited Condensed Consolidated Statements of Common Shareholder’s Deficit and Noncontrolling Interest for the Six Months ended June 30, 2013 and 2012

7

 

Notes to Unaudited Condensed Consolidated Financial Statements

8

1B.

Defined Terms

14

2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

15

3.

Quantitative and Qualitative Disclosure About Market Risk

22

4.

Controls and Procedures

23

 

 

 

Part II – Other Information

1.

Legal Proceedings

24

1A.

Risk Factors

24

2.

Unregistered Sales of Equity Securities and Use of Proceeds

24

3.

Defaults Upon Senior Securities

24

4.

Mine Safety Disclosures

24

5.

Other Information

24

6.

Exhibits

24

 

 

 

                                                                     Signatures

25

 

 

 

 

 

2

 


 

CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

 

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”) including, in particular, the statements about our plans, strategies and prospects under the heading “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I – Financial Information of this Form 10-Q. Forward-looking statements involve many risks and uncertainties and express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.

 

Some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to:

 

§

fluctuations in customer growth and demand;

§

impacts of weather on retail sales and wholesale prices;

§

impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;

§

weather-related damage to our electrical system;

§

fuel and other input costs;

§

generating unit availability and capacity;

§

transmission and distribution system reliability and capacity;

§

purchased power costs and availability;

§

regulatory action, including, but not limited to, the review of our basic rates and charges by the Indiana Utility Regulatory Commission (“IURC”);

§

federal and state legislation and regulations;

§

changes in our credit ratings or the credit ratings of The AES Corporation (“AES”);  

§

fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension and other post-retirement plans;

§

changes in financial or regulatory accounting policies;

§

environmental matters, including costs of compliance with current and future environmental laws and requirements;

§

interest rates and other costs of capital;

§

the availability of capital;

§

labor strikes or other workforce factors;

§

facility or equipment maintenance, repairs and capital expenditures;

§

local economic conditions, including the fact that the local and regional economies have struggled through the recession and weak economic climate the past few years and continue to face uncertainty for the foreseeable future;

§

acts of terrorism, acts of war, pandemic events or natural disasters such as floods, earthquakes, tornadoes, ice storms, droughts or other catastrophic events;

§

costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;

§

industry restructuring, deregulation and competition;

§

issues related to our participation in the Midcontinent Independent System Operator, Inc. (“MISO”), including the cost associated with membership and the recovery of costs incurred; and

§

product development and technology changes.

 

Most of these factors affect us through our consolidated subsidiary Indianapolis Power & Light Company (“IPL”). All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. Except as required by the federal securities laws, we undertake no obligation to publicly update or review any forward-looking information, whether as a result of new information, future events or otherwise. If one or more forward-looking statements are updated, no inference should be drawn that additional updates will be made with respect to those or other forward-looking statements.

 

3

 


 

PART I – financial information

 

ITEM 1. financial statementS 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income

(In Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended,

 

 

Six Months Ended,

 

June 30,

 

 

June 30,

 

2013

2012

 

 

2013

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

UTILITY OPERATING REVENUES

$

299,569 

$

292,659 

 

 

$

 

626,586 

 

$

593,763 

 

 

 

 

 

 

 

 

 

 

 

 

 

UTILITY OPERATING EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

Operation:

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

94,092 

 

74,257 

 

 

 

 

199,799 

 

 

158,571 

Other operating expenses

 

58,778 

 

53,784 

 

 

 

 

113,549 

 

 

107,042 

Power purchased

 

18,073 

 

33,278 

 

 

 

 

41,284 

 

 

64,519 

Maintenance

 

29,092 

 

28,395 

 

 

 

 

54,107 

 

 

51,129 

Depreciation and amortization

 

45,455 

 

44,551 

 

 

 

 

90,505 

 

 

87,275 

Taxes other than income taxes

 

11,403 

 

10,890 

 

 

 

 

23,280 

 

 

22,171 

Income taxes - net

 

10,893 

 

12,921 

 

 

 

 

29,317 

 

 

30,522 

Total utility operating expenses

 

267,786 

 

258,076 

 

 

 

 

551,841 

 

 

521,229 

UTILITY OPERATING INCOME

 

31,783 

 

34,583 

 

 

 

 

74,745 

 

 

72,534 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME AND (DEDUCTIONS):

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for equity funds used during construction

 

889 

 

220 

 

 

 

 

1,611 

 

 

391 

Miscellaneous income and (deductions) - net

 

(648)

 

(62)

 

 

 

 

(1,185)

 

 

(606)

Income tax benefit applicable to nonoperating income

 

5,236 

 

4,972 

 

 

 

 

11,104 

 

 

10,442 

Total other income and (deductions) - net

 

5,477 

 

5,130 

 

 

 

 

11,530 

 

 

10,227 

 

 

 

 

 

 

 

 

 

 

 

 

 

INTEREST AND OTHER CHARGES:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

26,463 

 

25,875 

 

 

 

 

52,513 

 

 

51,712 

Other interest

 

433 

 

469 

 

 

 

 

862 

 

 

920 

Allowance for borrowed funds used during construction

 

(511)

 

(148)

 

 

 

 

(921)

 

 

(624)

Amortization of redemption premiums and expense on debt

 

1,287 

 

1,226 

 

 

 

 

2,572 

 

 

2,433 

Total interest and other charges - net

 

27,672 

 

27,422 

 

 

 

 

55,026 

 

 

54,441 

NET INCOME 

 

9,588 

 

12,291 

 

 

 

 

31,249 

 

 

28,320 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: PREFERRED DIVIDENDS OF SUBSIDIARY

 

804 

 

804 

 

 

 

 

1,607 

 

 

1,607 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME APPLICABLE TO COMMON STOCK

$

8,784 

$

11,487 

 

 

$

 

29,642 

 

$

26,713 

 

 

 

 

 

 

 

 

 

 

 

 

 

ADD OTHER COMPREHENSIVE INCOME

 

-

 

-

 

 

 

 

-

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

$

8,784 

$

11,487 

 

 

$

 

29,642 

 

$

26,713 

 

 

 

 

 

 

 

 

 

 

 

 

 

See notes to unaudited condensed consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

 

June 30,

 

December 31,

 

2013

 

2012

ASSETS

UTILITY PLANT:

 

 

 

 

 

  Utility plant in service

$

4,408,542 

 

$

4,382,534 

  Less accumulated depreciation

 

2,086,929 

 

 

2,043,540 

     Utility plant in service - net

 

2,321,613 

 

 

2,338,994 

 Construction work in progress

 

129,004 

 

 

70,169 

 Spare parts inventory

 

16,012 

 

 

15,445 

 Property held for future use

 

1,002 

 

 

1,002 

     Utility plant - net

 

2,467,631 

 

 

2,425,610 

OTHER ASSETS:

 

 

 

 

 

 Nonutility property - at cost, less accumulated depreciation

 

530 

 

 

533 

 Other investments

 

5,682 

 

 

5,333 

     Other assets - net

 

6,212 

 

 

5,866 

CURRENT ASSETS:

 

 

 

 

 

 Cash and cash equivalents

 

31,413 

 

 

18,487 

 Accounts receivable and unbilled revenue (less allowance

 

 

 

 

 

   for doubtful accounts of $2,293 and $2,047, respectively)

 

131,103 

 

 

141,508 

 Fuel inventories - at average cost

 

48,795 

 

 

45,236 

 Materials and supplies - at average cost

 

58,683 

 

 

57,256 

 Deferred tax asset - current

 

10,292 

 

 

10,809 

 Regulatory assets

 

3,394 

 

 

4,906 

 Prepayments and other current assets

 

46,918 

 

 

21,135 

     Total current assets

 

330,598 

 

 

299,337 

DEFERRED DEBITS:

 

 

 

 

 

 Regulatory assets

 

512,019 

 

 

523,839 

 Miscellaneous

 

32,222 

 

 

30,695 

     Total deferred debits

 

544,241 

 

 

554,534 

             TOTAL

$

3,348,682 

 

$

3,285,347 

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:

 

 

 

 

 

 Common shareholder's deficit:

 

 

 

 

 

   Paid in capital

$

12,138 

 

$

11,811 

   Accumulated deficit

 

(15,288)

 

 

(15,030)

     Total common shareholder's deficit

 

(3,150)

 

 

(3,219)

 Cumulative preferred stock of subsidiary

 

59,784 

 

 

59,784 

 Long-term debt

 

1,821,283 

 

 

1,651,120 

          Total capitalization

 

1,877,917 

 

 

1,707,685 

CURRENT LIABILITIES:

 

 

 

 

 

 Short-term and current portion of long-term debt (Note 4)

 

50,000 

 

 

160,000 

 Accounts payable

 

108,417 

 

 

76,343 

 Accrued expenses

 

23,382 

 

 

24,310 

 Accrued real estate and personal property taxes

 

19,542 

 

 

19,405 

 Regulatory liabilities

 

30,140 

 

 

10,475 

 Accrued interest

 

29,390 

 

 

31,979 

 Customer deposits

 

25,623 

 

 

24,796 

 Other current liabilities

 

9,861 

 

 

11,210 

     Total current liabilities

 

296,355 

 

 

358,518 

DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES:

 

 

 

 

 

 Regulatory liabilities

 

580,141 

 

 

570,344 

 Accumulated deferred income taxes - net

 

337,480 

 

 

341,859 

 Non-current income tax liability

 

6,306 

 

 

6,138 

 Unamortized investment tax credit

 

7,411 

 

 

8,162 

 Accrued pension and other postretirement benefits

 

224,302 

 

 

274,017 

 Miscellaneous

 

18,770 

 

 

18,624 

     Total deferred credits and other long-term liabilities

 

1,174,410 

 

 

1,219,144 

COMMITMENTS AND CONTINGENCIES (Note 6)

 

 

 

 

 

             TOTAL

$

3,348,682 

 

$

3,285,347 

 

 

 

 

 

 

See notes to unaudited condensed consolidated financial statements.

 

 

 

5

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

 

 

 

 

 

 

 

Six Months Ended,

 

June 30,

 

2013

 

2012

CASH FLOWS FROM OPERATIONS:

 

 

 

 

 

 Net income

$

31,249 

 

$

28,320 

 Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

   Depreciation and amortization

 

91,245 

 

 

89,360 

   Amortization of regulatory assets

 

1,729 

 

 

231 

   Deferred income taxes and investment tax credit adjustments - net

 

(3,665)

 

 

(8,490)

   Allowance for equity funds used during construction

 

(1,490)

 

 

(295)

 Change in certain assets and liabilities:

 

 

 

 

 

   Accounts receivable

 

10,404 

 

 

(629)

   Fuel, materials and supplies

 

(4,986)

 

 

(13,154)

   Income taxes receivable or payable

 

(9,136)

 

 

70 

   Financial transmission rights

 

(9,682)

 

 

(4,787)

   Accounts payable and accrued expenses

 

1,306 

 

 

(352)

   Accrued real estate and personal property taxes

 

137 

 

 

639 

   Accrued interest

 

(2,589)

 

 

766 

   Pension and other postretirement benefit expenses

 

(49,715)

 

 

(13,976)

   Short-term and long-term regulatory assets and liabilities

 

28,031 

 

 

15,324 

   Other - net

 

(5,895)

 

 

(5,733)

Net cash provided by operating activities

 

76,943 

 

 

87,294 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 Capital expenditures - utility

 

(86,043)

 

 

(56,958)

 Grants under the American Recovery and Reinvestment Act of 2009

 

891 

 

 

2,663 

 Cost of removal, net of salvage

 

(2,884)

 

 

(5,879)

 Other

 

(2,187)

 

 

(3,230)

Net cash used in investing activities

 

(90,223)

 

 

(63,404)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 Short-term debt borrowings

 

129,000 

 

 

50,000 

 Short-term debt repayments

 

(129,000)

 

 

(44,000)

 Long-term borrowings, net of discount

 

169,728 

 

 

 -

 Retirement of long-term debt, including make-whole provision

 

(110,377)

 

 

 -

 Dividends on common stock

 

(29,900)

 

 

(29,600)

 Preferred dividends of subsidiary

 

(1,607)

 

 

(1,607)

 Deferred financing costs paid

 

(1,636)

 

 

(166)

 Other

 

(2)

 

 

(4)

Net cash provided by (used in) financing activities

 

26,206 

 

 

(25,377)

Net change in cash and cash equivalents

 

12,926 

 

 

(1,487)

Cash and cash equivalents at beginning of period

 

18,487 

 

 

27,283 

Cash and cash equivalents at end of period

$

31,413 

 

$

25,796 

 

 

 

 

 

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

 Cash paid during the period for:

 

 

 

 

 

   Interest (net of amount capitalized)

$

55,067 

 

$

51,227 

   Income taxes

$

31,000 

 

$

28,500 

 

 

 

 

 

 

 

As of June 30,

 

 

2013

 

2012

 Non-cash financing and investing activities:

 

 

 

 

 

      Accruals for capital expenditures

$

43,621 

 

$

19,896 

 

 

 

 

 

 

See notes to unaudited condensed consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Common Shareholder's Deficit

and Noncontrolling Interest

(In Thousands)

 

 

 

 

 

 

 

 

 

 

Paid in Capital

Accumulated Deficit

Total Common Shareholder's Deficit

Cumulative Preferred Stock of Subsidiary

2012

 

 

 

 

 

 

 

 

Beginning Balance

$

11,367 

$

(17,213)

$

(5,846)

$

59,784 

Comprehensive Income attributable to common stock:

 

 

 

 

 

 

 

 

  Net income applicable to common stock

 

 

 

26,713 

 

26,713 

 

 

Distributions to AES

 

 

 

(29,600)

 

(29,600)

 

 

Contributions from AES

 

220 

 

 

 

220 

 

 

Balance at June 30, 2012

$

11,587 

$

(20,100)

$

(8,513)

$

59,784 

2013

 

 

 

 

 

 

 

 

Beginning Balance

$

11,811 

$

(15,030)

$

(3,219)

$

59,784 

Comprehensive Income attributable to common stock:

 

 

 

 

 

 

 

 

  Net income applicable to common stock

 

 

 

29,642 

 

29,642 

 

 

Distributions to AES

 

 

 

(29,900)

 

(29,900)

 

 

Contributions from AES

 

327 

 

 

 

327 

 

 

Balance at June 30, 2013

$

12,138 

$

(15,288)

$

(3,150)

$

59,784 

 

 

 

 

 

 

 

 

 

See notes to unaudited condensed consolidated financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7

 


 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

 

For a list of certain abbreviations or acronyms used in the Notes to Unaudited Condensed Consolidated Financial Statements, see “Item 1B. Defined Terms” included in Part I – Financial Information of this Form 10-Q.

 

1. ORGANIZATION

 

IPALCO Enterprises, Inc. (“IPALCO”) is a holding company incorporated under the laws of the state of Indiana. IPALCO is a wholly-owned subsidiary of The AES Corporation (“AES”). IPALCO was acquired by AES in March 2001. IPALCO owns all of the outstanding common stock of its subsidiaries. Substantially all of IPALCO’s business consists of the generation, transmission, distribution and sale of electric energy conducted through its principal subsidiary, Indianapolis Power & Light Company (“IPL”). IPL was incorporated under the laws of the state of Indiana in 1926. IPL has approximately 470,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, the most distant point being approximately forty miles from Indianapolis. IPL has an exclusive right to provide electric service to those customers. IPL owns and operates two primarily coal-fired generating plants, one combination coal and gas-fired plant and two combustion turbines at a separate site that are all used for generating electricity. IPL’s net electric generation design  capability for winter and summer is 3,272 Megawatts (“MW”) and 3,148 MW, respectively.  

 

2. Summary of significant accounting policies

 

The accompanying Unaudited Condensed Consolidated Financial Statements (the “Financial Statements”) include the accounts of IPALCO, IPL and Mid-America Capital Resources, Inc., a non-regulated wholly owned subsidiary of IPALCO. All significant intercompany amounts have been eliminated. The accompanying financial statements are unaudited; however, they have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and in conjunction with the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all of the disclosures required by accounting principles generally accepted in the United States of America for annual fiscal reporting periods. In the opinion of management, all adjustments of a normal recurring nature necessary for fair presentation have been included. The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses are not generated evenly by month during the year. These unaudited financial statements have been prepared in accordance with the accounting policies described in IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”) and should be read in conjunction therewith. Certain prior period amounts have been reclassified to conform to current year presentation.

 

Use of Management Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions that management is required to make. Actual results may differ from those estimates.

 

New Accounting Pronouncements

 

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, requiring companies to present current period reclassifications out of accumulated other comprehensive income (“AOCI”). For significant items reclassified out of AOCI to net income in their entirety in the period, companies must report the effect of the reclassifications on the respective line items in the statement where net income is presented. In certain circumstances, this can be done on the face of that statement. Otherwise, it must be presented in the notes. The amendments in this update are effective for IPALCO beginning January 1, 2013 and did not have any impact on IPALCO’s consolidated financial statements. 

 

 

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3. FAIR VALUE MEASUREMENTS

 

Fair Value Hierarchy

 

Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 820 defined and established a framework for measuring fair value and expanded disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820, as follows:

 

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market.

 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets.

 

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

 

IPALCO did not have any financial assets or liabilities measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the periods covered by this report. As of June 30, 2013 and December 31, 2012, all of IPALCO’s financial assets or liabilities adjusted to fair value on a recurring basis (excluding pension assets – see Note 5, “Pension and Other Postretirement Benefits”) were considered Level 3, based on the above fair value hierarchy. These primarily consisted of financial transmission rights, which are used to offset MISO congestion charges. Because the benefit associated with financial transmission rights is a flow-through to IPL’s jurisdictional customers, IPL records a regulatory liability matching the value of the financial transmission rights.  In addition, IPALCO had one financial asset, a nonutility investment accounted for using the cost method of accounting, which is measured at fair value on a nonrecurring basis, again using Level 3 measurements. These financial assets and liabilities were not material to the financial statements in the periods covered by this report, individually or in the aggregate.

 

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

 

Cash Equivalents

 

As of June 30, 2013 and December 31, 2012, our cash equivalents consisted of money market funds. The fair value of cash equivalents uses Level 1 measurements and due to their short maturity, approximates their book value, which was $5.4 million and $6.4 million as of June 30, 2013 and December 31, 2012, respectively.

 

Indebtedness

 

The fair value of our outstanding fixed rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. Because trading of our debt occurs somewhat infrequently, we consider the fair values to be Level 2. The purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

 

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The following table shows the face value and the fair value of fixed rate and variable rate indebtedness for the periods ending: 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2013

December 31, 2012

 

Face Value

Fair Value

Face Value

Fair Value

 

(In Millions)

Fixed-rate

$

1,825.3 

$

1,947.5 

$

1,765.3 

$

2,012.3 

Variable-rate

 

50.0 

 

50.0 

 

50.0 

 

50.0 

Total indebtedness

$

1,875.3 

$

1,997.5 

$

1,815.3 

$

2,062.3 

 

 

 

 

 

 

 

 

 

 

 

The difference between the face value and the carrying value of this indebtedness represents unamortized discounts of $4.0 million and $4.2 million at June 30, 2013 and December 31, 2012, respectively.

 

4. INDEBTEDNESS

 

IPL First Mortgage Bonds

 

In June 2013, IPL issued $170 million aggregate principal amount of first mortgage bonds,  4.65% Series, due June 2043. Net proceeds from this offering were approximately $167.6 million, after deducting the initial purchasers’ discount and fees and expenses for the offering payable by IPL. The net proceeds from the offering were used in June of 2013 to finance the redemption of $110 million aggregate principal amount of IPL first mortgage bonds, 6.30% Series, due July 2013, and to pay related fees, expenses and applicable redemption prices. We are using all remaining proceeds to finance a portion of our environmental construction program and for other general corporate purposes.

 

 

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5. PENSION AND OTHER POSTRETIREMENT BENEFITS

 

The following table (in thousands) presents information for the six months ended June 30, 2013 relating to the Employees’ Retirement Plan of Indianapolis Power & Light Company and the Supplemental Retirement Plan of Indianapolis Power & Light Company (“Pension Plans”):

 

 

 

 

 

 

 

Net funded status of plans:

 

 

Net funded status at December 31, 2012, before tax adjustments

$

(268,518)

Net benefit cost components reflected in net funded status during first quarter:

 

 

Service cost

 

(2,299)

Interest cost

 

(7,091)

Expected return on assets

 

9,572 

Employer contributions during quarter

 

49,659 

Net funded status at March 31, 2013 before tax adjustments

$

(218,677)

Net benefit cost components reflected in net funded status during second quarter:

 

 

Service cost

 

(2,299)

Interest cost

 

(7,090)

Expected return on assets

 

9,572 

Employer contributions during quarter

 

 -

Net funded status at June 30, 2013 before tax adjustments

$

(218,494)

 

 

 

Regulatory assets related to pensions(1):

 

 

Regulatory assets at December 31, 2012, before tax adjustments

$

348,393 

Amount reclassified through net benefit cost: 

 

 

Amortization of prior service cost

 

(1,229)

Amortization of net actuarial loss

 

(5,684)

Regulatory assets at March 31, 2013 before tax adjustments

$

341,480 

Amount reclassified through net benefit cost: 

 

 

Amortization of prior service cost

 

(1,229)

Amortization of net actuarial loss

 

(5,684)

Regulatory assets at June 30, 2013 before tax adjustments

$

334,567 

 

 

 

 

(1)

Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits” are recorded as a regulatory asset or liability because IPL has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts yet to be recognized as components of net periodic benefit costs.

            

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Pension Expense

 

The following table presents Net Periodic Benefit Cost information relating to the Pension Plans combined:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended,

For the Six Months Ended,

 

June 30,

June 30,

 

2013

2012

2013

2012

 

(In Thousands)

(In Thousands)

Components of net periodic benefit cost:

 

 

 

 

 

 

 

 

Service cost

$

2,299 

$

1,996 

$

4,598 

$

3,993 

Interest cost

 

7,090 

 

7,558 

 

14,181 

 

15,116 

Expected return on plan assets

 

(9,572)

 

(8,138)

 

(19,144)

 

(16,277)

Amortization of prior service cost

 

1,229 

 

1,062 

 

2,458 

 

2,123 

Amortization of actuarial loss

 

5,684 

 

4,867 

 

11,368 

 

9,735 

Net periodic benefit cost

$

6,730 

$

7,345 

$

13,461 

$

14,690 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6. COMMITMENTS AND CONTINGENCIES

 

Legal Loss Contingencies

 

IPALCO and IPL are involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on IPALCO’s results of operations, financial condition, or cash flows. Amounts accrued or expensed for legal or environmental contingencies collectively during the periods covered by this report have not been material to the Financial Statements of IPALCO.

 

Environmental Loss Contingencies

 

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits.

 

New Source Review

 

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the U.S. Environmental Protection Agency (“EPA”) pursuant to the U.S. Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with the EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact on our business. We would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in that regard. IPL has recorded a contingent liability related to this matter.

 

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7. INCOME TAXES

 

IPALCO’s effective combined state and federal income tax rates were 39.2% and 38.1% for the three and six months ended June 30, 2013, respectively, as compared to 40.9% and 42.9% for the three and six months ended June 30, 2012, respectively. The decrease in the effective tax rate for the six months ended June 30, 2013 versus the comparable period was primarily due to a $1.1 million discrete tax expense adjustment recorded in the first quarter of 2012 and an  increase in the allowance for equity funds used during construction in 2013. The decrease in the effective tax rate for the three months ended June 30, 2013 versus the comparable period was primarily due to an increase in the allowance for equity funds used during construction in 2013.

 

8. SEGMENT INFORMATION

 

Operating segments are components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through IPL which is a vertically integrated electric utility. IPALCO’s reportable business segments are utility and nonutility. The nonutility category primarily includes the $400 million of 7.25% Senior Secured Notes due April 1, 2016 and the $400 million of 5.00% Senior Secured Notes due May 1, 2018; approximately $6.5 million and $6.4 million of nonutility cash and cash equivalents, as of June 30, 2013 and December 31, 2012, respectively; short-term and long-term nonutility investments of $4.9 million and $4.7 million at June 30, 2013 and December 31, 2012, respectively; and income taxes and interest related to those items. Nonutility assets represented less than 1% of IPALCO’s total assets as of June 30, 2013 and December 31, 2012. Net income for the utility segment was $46.9 million and $44.1 million for the six month periods ended June 30, 2013 and 2012, respectively, and $17.8  million and $20.3 million for the three month periods ended June 30, 2013 and 2012, respectively. The accounting policies of the identified segments are consistent with those policies and procedures described in the summary of significant accounting policies. Intersegment sales, if any, are generally based on prices that reflect the current market conditions.

 

9. SUBSEQUENT EVENTS

 

On July 31, 2013, IPALCO received an equity capital contribution of $49.1 million from AES for funding needs related to IPL’s environmental construction program, which IPALCO then made the same investment in IPL.                                              

 

 

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ITEM 1B. DEFINED TERMS

 

 

 

Defined Terms

The following is a list of frequently used abbreviations or acronyms that are found in this Form 10-Q:

 

 

2012 Form 10-K

IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2012

AES

The AES Corporation

AOCI

Accumulated Other Comprehensive Income

ASC

Financial Accounting Standards Board Accounting Standards Codification

CAA

U.S. Clean Air Act

CCGT

Combined Cycle Gas Turbine

CO2

Carbon Dioxide

CPCN

Certificate of Public Convenience and Necessity

DSM

Demand Side Management

ELGs

Effluent Limit Guidelines

EPA

U.S. Environmental Protection Agency

FERC

Federal Energy Regulatory Commission

The Financial Statements

The Unaudited Condensed Consolidated Financial Statements of IPALCO in “Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q

IDEM

Indiana Department of Environmental Management

IPALCO

IPALCO Enterprises, Inc.

IPL

Indianapolis Power & Light Company

IURC

Indiana Utility Regulatory Commission

kWh

Kilowatt hours

MATS

Mercury and Air Toxics Standards

MW

Megawatt

MISO

Midcontinent Independent System Operator, Inc.

NOV

Notice of Violation and Finding of Violation

NPDES

National Pollutant Discharge Elimination System

Pension Plans

Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company

 

 

 

14

 


 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and the notes thereto included in “Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward – Looking Statements” at the beginning of this Form 10-Q. For a list of certain abbreviations or acronyms used in this discussion, see “Item 1B. Defined Terms” included in Part I – Financial Information of this Form 10-Q.

 

RESULTS OF OPERATIONS

 

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenues and associated expenses are not generated evenly by month during the year. 

 

Comparison of three months ended June 30, 2013 and three months ended June 30, 2012

 

Utility Operating Revenues

 

Utility operating revenues during the three months ended June 30, 2013 increased by $6.9 million compared to the same period in 2012, which resulted from the following changes (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

June 30,

 

 

 

Percentage

 

2013

 

2012

 

Change

Change

 

 

 

 

Utility Operating Revenues:

 

 

 

 

 

 

 

 

 

 

Retail Revenues

$

271,267 

 

$

284,181 

 

$

(12,914)
(4.5%)

 

Wholesale Revenues

 

23,502 

 

 

3,523 

 

 

19,979 
567.1% 

 

Miscellaneous Revenues

 

4,800 

 

 

4,955 

 

 

(155)
(3.1%)

 

Total Utility Operating Revenues

$

299,569 

 

$

292,659 

 

$

6,910 
2.4% 

 

 

 

 

 

 

 

 

 

 

 

 

Heating Degree Days:

 

 

 

 

 

 

 

 

 

 

Actual

 

488 

 

 

361 

 

   

127 
35.2% 

 

30-year Average

 

524 

 

 

551 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cooling Degree Days:

 

 

 

 

 

 

 

 

 

 

Actual

 

355 

 

 

474 

 

   

(119)
(25.1%)

 

30-year Average

 

309 

 

 

302 

 

 

 

 

 

 

 

The decrease in retail revenues of $12.9 million was due to a 5%  decrease in the volume of kilowatt hours (“kWh”) sold ($9.9 million) and a net decrease in the weighted average price per kWh sold ($3.0 million).  The $9.9 million decrease in the volume of electricity sold was primarily due to cooler temperatures in our service territory during the second quarter of 2013 versus the comparable period (as demonstrated by the 25% decrease in cooling degree days, as shown above). The $3.0 million decrease in the weighted average price of retail kWh sold was primarily due to decreases in fuel revenues of $7.1 million, partially offset by increases in Demand Side Management (“DSM”) program rate adjustment mechanism revenues of $1.5 million and favorable block rate variances. Favorable block rate variances are attributed to our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes decrease, the weighted average price per kWh increases.

15

 


 

 

The increase in wholesale revenues of $20.0 million was primarily due to  a 441% increase in the quantity of kWh sold ($15.5 million) and a 23%  increase in the weighted average price per kWh sold ($4.4 million) as IPL’s coal-fired generation has been called upon by MISO to produce electricity more often during the three months ended June 30, 2013 versus the comparable period in 2012. Our ability to be dispatched in the MISO market is primarily impacted by the locational market price of electricity and variable generation costs. The amount of electricity available for wholesale sales is impacted by our retail load requirements, our generation capacity and unit availability. We believe the most significant factor that drove up wholesale electricity prices (which contributed to our favorable wholesale volumes) was an increase in natural gas prices.     

 

Utility Operating Expenses

 

The following table illustrates our primary operating expense changes from the three months ended June 30,  2012 to the three months ended June 30,  2013 (in millions):

 

 

 

 

 

 

 

 

 

Operating expenses for the three months ended June 30, 2012

$

258.1 

Increase in fuel costs

 

19.8 

Decrease in power purchased

 

(15.2)

Increase in DSM program costs

 

2.1 

Other miscellaneous variances

 

3.0 

Operating expenses for the three months ended June 30, 2013

$

267.8 

 

 

 

The $19.8 million increase in fuel costs is primarily due to a $19.1 million increase in the quantity of fuel consumed as the result of an increase in total electricity sales volume in the comparable periods.  The $15.2 million decrease in purchased power costs was primarily due to a 67% decrease in the volume of power purchased during the period  ($21.0 million), partially offset by a 49% increase in the market price of purchased power ($5.8 million). The volume of power we purchase each period is primarily influenced by our retail demand, our generating unit capacity and outages and because at times it is less expensive for us to buy power in the market than to produce it ourselves. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the price of environmental emissions allowances, the supply of and demand for electricity, and the time of day in which power is purchased. In the comparable periods, the increase in natural gas prices had the largest impact on the market price of purchased power. 

 

The increase in DSM program costs of $2.1 million, which are included in “Other operating expenses” on our unaudited condensed consolidated statements of comprehensive income, is attributed to the continued implementation of IPL’s energy efficiency program initiatives. The increase in DSM program costs is correlated to the increase in DSM program rate adjustment mechanism revenues, as noted above. 

 

16

 


 

Comparison of six months ended June 30, 2013 and six months ended June 30, 2012

 

Utility Operating Revenues

 

Utility operating revenues during the six months ended June 30, 2013 increased by $32.8 million compared to the same period in 2012, which resulted from the following changes (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

 

 

 

June 30,

 

 

 

Percentage

 

2013

 

2012

 

Change

Change

 

 

 

 

 

 

Utility Operating Revenues:

 

 

 

 

 

 

 

 

 

 

Retail Revenues

$

577,144 

 

$

573,169 

 

$

3,975 
0.7% 

 

Wholesale Revenues

 

39,624 

 

 

11,230 

 

 

28,394 
252.8% 

 

Miscellaneous Revenues

 

9,818 

 

 

9,364 

 

 

454 
4.8% 

 

Total Utility Operating Revenues

$

626,586 

 

$

593,763 

 

$

32,823 
5.5% 

 

 

 

 

 

 

 

 

 

 

 

 

Heating Degree Days:

 

 

 

 

 

 

 

 

 

 

Actual

 

3,426 

 

 

2,418 

 

   

1,008 
41.7% 

 

30-year Average

 

3,379 

 

 

3,453 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cooling Degree Days:

 

 

 

 

 

 

 

 

 

 

Actual

 

355 

 

 

519 

 

   

(164)
(31.6%)

 

30-year Average

 

309 

 

 

302 

 

 

 

 

 

 

 

Retail revenues increased slightly by 0.7%, primarily due to a slight increase in the volume of kilowatt hours (“kWh”) sold ($3.8  million).  The $3.8 million increase in the volume of electricity sold was primarily due to cooler temperatures in our service territory during the winter heating season in 2013 (as demonstrated by the 42% increase in heating degree days, as shown above). In contrast, this was partially offset by cooler temperatures in our service territory during the early stages of the cooling season in 2013 (as demonstrated by the 32% decrease in cooling degree days, as shown above).  

 

The increase in wholesale revenues of $28.4 million was primarily due to a 174% increase in the quantity of kWh sold ($19.5 million) and a 29% increase in the weighted average price per kWh sold ($8.9 million) as IPL’s coal-fired generation has been called upon by MISO to produce electricity more often during the six months ended June 30, 2013 versus the comparable period in 2012. As described previously, this was primarily due to increased natural gas prices which drove up wholesale electricity prices.

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Utility Operating Expenses

 

The following table illustrates our primary operating expense changes from the six months ended June 30, 2012 to the six months ended June 30, 2013 (in millions):

 

 

 

 

 

 

 

 

 

 

Operating expenses for the six months ended June 30, 2012

$

521.2 

Increase in fuel costs

 

41.2 

Decrease in power purchased

 

(23.2)

Increase in DSM program costs

 

4.7 

Other miscellaneous variances

 

7.9 

Operating expenses for the six months ended June 30, 2013

$

551.8 

 

 

 

 

The $41.2 million increase in fuel costs is primarily due to a $34.5 million increase in the quantity of fuel consumed as the result of an increase in total electricity sales volume in the comparable periods. The fuel cost increase also includes a $6.4 million increase in deferred fuel costs as the result of variances between estimated fuel and purchased power costs in our fuel adjustment charges and actual fuel and purchased power costs. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through the fuel adjustment charges proceedings and, therefore, the costs are deferred and amortized into expense in the same period that our rates are adjusted. 

The $23.2 million decrease in purchased power costs was primarily due to a 61% decrease in the volume of power purchased during the period ($34.9 million), partially offset by a 52% increase in the market price of purchased power ($11.5 million). As described previously, IPL’s units were called upon more often in 2013, primarily due to increased natural gas prices which drove up wholesale electricity prices. This reduced the amount of electricity IPL needed to purchase in order to serve its retail load requirements.  

 

The increase in DSM program costs of $4.7 million, which are included in “Other operating expenses” on our unaudited condensed consolidated statements of comprehensive income, is attributed to the continued implementation of IPL’s energy efficiency program initiatives. The increase in DSM program costs is correlated to the increase in DSM program rate adjustment mechanism revenues, as previously noted.

 

LIQUIDITY AND CAPITAL RESOURCES

 

As of June 30, 2013, we had unrestricted cash and cash equivalents of $31.4 million and available borrowing capacity of $246.9 million under our $250.0 million committed revolving credit facility after outstanding borrowings and existing letters of credit. All of IPL’s long-term borrowings must first be approved by the IURC and the aggregate amount of IPL’s short-term indebtedness must be approved by the Federal Energy Regulatory Commission (“FERC”). We have approval from FERC to borrow up to $500 million of short-term indebtedness outstanding at any time through July 28, 2014. As of June 30, 2013, we also have remaining authority from the IURC to, among other things, issue up to $75 million in aggregate principal amount of long-term debt through December 31, 2013, and to have up to $250 million of long-term credit agreements and liquidity facilities outstanding at any one time. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

 

We believe that existing cash balances, cash generated from operating activities and borrowing capacity on our committed credit facility will be adequate for the foreseeable future to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures and to pay dividends to AES. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed credit facility; and (iv) additional debt financing. In addition, due to current and future environmental

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regulations, it is expected that equity capital will also be used as a significant funding source. AES has approved significant equity investments in IPL for its proposed nonrecurring capital expenditures from 2013 through 2016; however, AES is under no contractual obligation to provide such equity capital and there can be no assurance we will receive capital contributions in the amounts or at the times funding may be required. On July 31, 2013,  IPALCO received an equity capital contribution of $49.1 million from AES for funding needs related to IPL’s environmental construction program, which IPALCO then made the same investment in IPL.

 

IPL First Mortgage Bonds

 

In June 2013, IPL issued $170 million aggregate principal amount of first mortgage bonds, 4.65% Series, due June 2043. Net proceeds from this offering were approximately $167.6 million, after deducting the initial purchasers’ discount and fees and expenses for the offering payable by IPL. The net proceeds from the offering were used in June of 2013 to finance the redemption of $110 million aggregate principal amount of IPL first mortgage bonds, 6.30% Series, due July 2013, and to pay related fees, expenses and applicable redemption prices. We are using all remaining proceeds to finance a portion of our environmental construction program and for other general corporate purposes.

 

Capital Requirements

 

Capital Expenditures

 

Our construction program is composed of capital expenditures necessary for prudent utility operations and compliance with environmental laws and regulations, along with discretionary investments designed to replace aging equipment or improve overall performance. Our capital expenditures totaled $86.0 million and $57.0 million for the six months ended June 30, 2013 and 2012, respectively, reflecting an increase of $29.0 million, which is primarily due to spending to comply with Mercury and Air Toxics Standards (“MATS”). Construction expenditures during the first six months of 2013 and 2012 were financed primarily with internally generated cash provided by operations, borrowings on our credit facility, long-term borrowings and, to a lesser extent, federal grants for IPL’s Smart Energy Projects.

 

Our capital expenditure program, including development and permitting costs, for the three year period from 2013 to 2015 is currently estimated to cost approximately $427 million (excluding environmental compliance and replacement generation costs). It includes approximately $256 million for additions, improvements and extensions to transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers, street lighting facilities and Smart Energy Projects. The capital expenditure program also includes approximately $149 million for power plant related projects and $22 million for other miscellaneous equipment.  

 

In addition to the amounts listed above, IPL plans to spend an additional $511 million through 2016, excluding demolition costs which are not expected to be material, to comply with the MATS rule. Of this amount, $456 million is projected to be spent in the three year period from 2013 to 2015. In addition, IPL will incur costs for compliance with other environmental rules. Such amounts are more difficult to predict, but are currently expected to be less than the expected costs to comply with MATS (please see “Environmental Matters – MATS” for more details). If approved by the IURC, IPL also plans to expend significant capital on replacement generation costs (please see “Unit Retirements and Replacement Generation”  below for more details).

 

Common Stock Dividends

 

All of IPALCO’s outstanding common stock is held by AES. During the first six months of 2013 and 2012 we paid $29.9 million and $29.6 million, respectively, in dividends to AES. Future distributions will be determined at the discretion of our board of directors and will depend primarily on dividends received from IPL. Dividends from IPL are affected by IPL’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as IPL’s board of directors deems relevant.

 

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Pension Funding

 

We contributed $49.7 million and $17.1 million to the Employees’ Retirement Plan of Indianapolis Power & Light Company and Supplemental Retirement Plan of Indianapolis Power & Light Company (“Pension Plans”) during the first six months of 2013 and 2012, respectively.  We currently do not expect to make additional pension funding contributions in 2013. Funding for the qualified Employees’ Retirement Plan of Indianapolis Power & Light Company is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. Management does not currently expect any of the pension assets to be returned to us during 2013.

 

Regulatory Matters

 

Senate Bill 560

 

In April 2013, Senate Bill 560 became law in Indiana.  This law provides more regulatory flexibility to the current process for reviewing necessary utility system improvements and determining appropriate rates. Senate Bill 560 allows utilities to propose a seven-year infrastructure plan for distribution, transmission and storage to the IURC and, if the plan is considered reasonable by the IURC, the utility could recover its investment in facilities identified in the plan in a timely manner. In addition, when Indiana utilities apply for a change in their base rates, if new rates are not approved by the IURC within 300 days after the utility filed its case-in-chief, the bill allows the utility to implement temporary rates including 50% of the proposed increase.  Such temporary rates would be subject to a reconciliation implemented via a credit or surcharge in equal amounts each month for six months, if the IURC’s final order established rates were to differ from the temporary rates previously placed into effect. The IURC would be allowed to extend the 300 day deadline by 60 days, for good cause. Both provisions, as well as an additional provision that allows utilities to utilize a forward-looking test year in rate cases, recognize the capital-intensive nature of the energy industry and seek to reduce time between a utility’s investment and the opportunity to recover the investment through rates.  

 

Environmental Matters

 

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of hazardous materials; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, and permit revocation and/or facility shutdowns.

 

MATS

 

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for each hazardous air pollutant regulated under the CAA emitted from coal and oil-fired electric utilities, known as MATS, became effective. IPL management has developed a plan to comply with this rule. Most of our coal-fired capacity has acid gas scrubbers or comparable control technologies; however, there are other improvements to such control technologies that are necessary to achieve compliance. Under the CAA, compliance with MATS is required by April 16, 2015; however, the compliance period for certain units, or group of units, may be extended by state permitting authorities (for up to one additional year) or through a CAA administrative order from the EPA (for another additional year). In December 2012, Indiana Department of Environmental Management (“IDEM”) granted a one-year extension covering all coal-fired units at Harding Street and Eagle Valley, in addition to Unit 3 and Unit 4 at Petersburg. In February 2013, IDEM granted a three month extension on Petersburg Unit 2.

 

We have reviewed the impact of the MATS rule and estimate additional expenditures related to this rule for environmental controls for our baseload generating units to be approximately $511 million through 2016, excluding demolition costs which are not expected to be material. In August 2012, we filed our original MATS plan petition and a request with the IURC for a Certificate of Public Convenience and Necessity (“CPCN”) for the installation of emission controls to comply with the MATS rule.  These filings detail the controls we plan to add to each of our five baseload units, including four at our Petersburg generating station and one at our Harding Street generating station. A hearing with the IURC was held on this matter in April 2013, and IPL expects to receive an order from the IURC

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within the next  month. We will seek and expect to recover through our environmental rate adjustment mechanism, all operating and capital expenditures related to compliance with MATS; however, there can be no assurance that we will be successful in that regard.  Recovery of these costs is expected to be sought through an Indiana statute that allows for 100% recovery of qualifying costs through a rate adjustment mechanism.

 

Several lawsuits challenging the MATS rule have been filed and consolidated into a single proceeding before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this litigation.  

 

Environmental Wastewater Requirements 

In August 2012, IDEM issued National Pollutant Discharge Elimination System (NPDES”) permits to the IPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the Federal Water Pollution Control Act. These permits set new water quality based levels of acceptable metal effluent water discharges for the Petersburg and Harding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limits required by October 2015. In April 2013, IPL received an extension to the compliance deadline through September 2017 as part of an agreed order with IDEM.

 

IPL is conducting studies to determine what operational changes and/or additional equipment will be required to comply with the new limitations. In developing its compliance plans, IPL must make assumptions about the outcomes of future Federal rulemakings with respect to coal combustion residuals, cooling water intake and wastewater effluents. We will seek and expect to recover through our environmental rate adjustment mechanism, any operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is expected to be sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that we will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact of these permit requirements on our consolidated results of operations, cash flows, or financial condition, but it is expected to be material.

 

In April 2013, EPA announced proposed rules to reduce toxic pollutants discharged into waterways by power plants commonly known as “Effluent Limit Guidelines” or “ELGs. The proposed ELGs are intended to update the existing technology-based rules for controlling the discharge of pollutants from various waste streams associated with steam electric generating facilities. It is too early to determine whether the impacts of these proposed ELGs, if and when they become final, will materially impact IPL or its current NPDES permits. Under a consent decree, EPA is required to finalize the ELGs by May 2014.

 

Climate Change Legislation and Regulation

 

On June 25, 2013, the President of the United States directed the EPA to issue a new proposed rule establishing New Source Performance Standards for carbon dioxide (“CO2”) emissions for newly constructed fossil-fueled electric utility steam generating units (“EUSGUs”) larger than 25 MW by September 20, 2013, and to issue a final rule in a timely fashion after considering all public comments.  The EPA subsequently indicated its intention to issue a new proposed rule to address GHGs from newly constructed fossil-fueled power plants. 

In his June 25, 2013 announcement, the President,  as anticipated, also directed the EPA to issue new standards, regulations, or guidelines, as appropriate, that address CO2 emissions from existing power plants.  The President directed the EPA to (i) issue a proposed rule by June 1, 2014; (i) issue a final rule by June 1, 2015; and (iii) require that States submit their implementation plans to EPA by no later than June 30, 2016.

It is impossible to estimate the impact and compliance costs associated with any future EPA regulations applicable to new, modified or existing EUSGUs until such regulations are finalized; however, the impact, including the compliance costs, could be material to our consolidated financial condition or results of operations. 

 

 

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Summary

 

Environmental laws and regulations presently require us to incur material capital expenditures and operating costs. We expect to incur material costs, both in capital expenditures and ongoing operating and maintenance costs, to comply with MATS (up to $511 million in capital expenditures through 2016, excluding demolition costs which are not expected to be material, as discussed in “MATS” above) and NPDES, and, to a lesser extent to which we cannot predict, other expected environmental regulations related to: coal combustion byproducts; cooling water intake; Polychlorinated Biphenyl-containing equipment; National Ambient Air Quality Standards; and wastewater effluent rules. In addition, the combination of existing and expected environmental regulations and other economic factors make it likely that we will temporarily or permanently retire or repower several of our existing, primarily coal-fired, smaller and older generating units within the next several years (the total estimated cost of these projects is $667 million, as discussed in “Unit Retirements and Replacement Generation” below). We would expect to seek recovery of both capital and operating costs related to all such compliance, although there can be no assurances that we would be successful in that regard. 

 

Unit Retirements and Replacement Generation

 

In the second quarter of 2013, IPL retired in place five oil-fired peaking units with an average life of approximately 61 years (approximately 168 MW net capacity in total). Although these units represented approximately 5% of IPL’s generating capacity, they were seldom dispatched by MISO in recent years due to their relatively higher production cost and in some instances repairs were needed. In accordance with FERC accounting guidelines and standard utility practice for composite depreciation, these retirements were recorded as a reduction of $19.8 million to both Utility Plant in Service and Accumulated Depreciation”  on our unaudited condensed consolidated balance sheets, with no gain or loss recognized.

 

In addition to the units recently retired, IPL has several other generating units that we expect to retire or refuel in the next few years, primarily due to the MATS rule.  These units are primarily coal-fired and represent 472 MW of net capacity in total. To replace this generation, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (106 MW net capacity each). The total estimated cost of these projects is $667 million. IPL is seeking authority to accrue post in-service allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense of the CCGT until such time that IPL is allowed to collect a return and depreciation expense on the CCGT. If approved, the CCGT is expected to be placed into service in April 2017 and the refueling project is expected to be complete by April 2016. For the refueling project, we are requesting timely recovery of 80% of the revenue requirement of these federally mandated costs under Senate Bill 251, and deferral of the remaining 20% until the resolution of a base rate case filed with the IURC. If the Harding Street Units 5 and 6 are not refueled, they will likely need to be retired because it is currently not economical to install controls on those units to comply with MATS. If we receive approval for the CCGT, the costs to build and operate the equipment would be recoverable only by IPL filing a base rate case with the IURC. 

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 

 

Not applicable pursuant to General Instruction H of the Form 10-Q.

 

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ITEM 4. CONTROLS AND PROCEDURES

 

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

 

Evaluation of Disclosure Controls and Procedures

 

We carried out an evaluation, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15-d-15(e)), as required by paragraph (b) of the Exchange Act Rules 13a-15 or 15d-15, as of June 30, 2013. Our management, including the principal executive officer and principal financial officer, is engaged in a comprehensive effort to review, evaluate and improve our controls; however, management does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. We have interests in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities is generally more limited than those we maintain with respect to our consolidated subsidiaries. 

 

Based upon the controls evaluation performed, the principal executive officer and principal financial officer have concluded that as of June 30, 2013, our disclosure controls and procedures were effective to provide reasonable assurance that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

 

Changes in Internal Controls

 

In the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the principal executive officer and principal financial officer concluded that there were no changes in our internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of the Exchange Act Rules 13a-15 or 15d-15 that occurred during the six months ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.  

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PART II  Other Information

 

ITEM 1. Legal proceedings

 

Please see Note 6,  “Commitments and Contingencies” to The Financial Statements for a summary of significant legal proceedings involving us. We are also subject to routine litigation, claims and administrative proceedings arising in the ordinary course of business, none of which we believe, based on currently available information, will result in a material adverse effect on our results of operations, financial condition, or cash flows. 

 

ITEM 1a.  risk factors

 

There have been no material changes to the risk factors as previously disclosed in IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2012. 

 

ITEM 2. unregistered sales of equity securities and use of proceeds

 

None.

 

Item 3. defaults upon senior securities

 

None. 

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

 

ITEM 5.  Other information

 

None.

 

ITEM 6. EXHIBITS

 

 

 

Exhibit No.

Document

 

 

4.1

Sixty-First Supplemental Indenture, dated as of June 1, 2013

31.1

Certification by Chief Executive Officer required by Rule 13a-14(a) or 15d-14(a)

31.2

Certification by Principal Financial Officer required by Rule 13a-14(a) or 15d-14(a)

32

Certification required by Rule 13a-14(b) or 15d-14(b)

101.INS

XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)

101.SCH

XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

101.LAB

XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

 

 

 

 

 

 

 

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

IPALCO ENTERPRISES, INC.            

(Registrant)

 

 

Date:             August 7, 2013                                              /s/ Kelly M. Huntington                                    

Kelly M. Huntington

President

(Principal Executive Officer) 

 

 

Date:             August 7, 2013                                              /s/ Craig L. Jackson                                    

Craig L. Jackson

Chief Financial Officer

(Principal Financial Officer) 

 

 

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