10-Q 1 a11-25724_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

(Mark One)

 

x      Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the quarterly period ended September 30, 2011 or

 

o         Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from                    to                    .

 

Commission file number: 1-3368

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

 

Kansas

(State of Incorporation)

 

44-0236370

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

 

 

 

602 S. Joplin Avenue, Joplin, Missouri

(Address of principal executive offices)

 

64801

(zip code)

 

Registrant’s telephone number: (417) 625-5100

 

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 x    No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x    No o

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a 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 o    No x

 

As of November 1, 2011, 41,975,818 shares of common stock were outstanding.

 

 

 



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

 

INDEX

 

 

 

PAGE

 

 

 

 

Forward Looking Statements

3

 

 

 

Part I -

Financial Information:

 

 

 

 

Item 1.

Financial Statements:

 

 

 

 

 

a.  Consolidated Statements of Income

4

 

 

 

 

b.  Consolidated Statements of Comprehensive Income

7

 

 

 

 

c.  Consolidated Balance Sheets

8

 

 

 

 

d.  Consolidated Statements of Cash Flows

10

 

 

 

 

e.  Notes to Consolidated Financial Statements

11

 

 

 

Item 2.

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

34

 

 

 

 

Executive Summary

34

 

 

 

 

Results of Operations

37

 

 

 

 

Rate Matters

49

 

 

 

 

Competition

53

 

 

 

 

Liquidity and Capital Resources

54

 

 

 

 

Contractual Obligations

57

 

 

 

 

Dividends

57

 

 

 

 

Off-Balance Sheet Arrangements

58

 

 

 

 

Critical Accounting Policies

58

 

 

 

 

Recently Issued Accounting Standards

59

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

59

 

 

 

Item 4.

Controls and Procedures

61

 

 

 

Part II-

Other Information:

 

 

 

 

Item 1.

Legal Proceedings

61

 

 

 

Item 1A.

Risk Factors

61

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds - (none)

 

 

 

 

Item 3.

Defaults Upon Senior Securities - (none)

 

 

 

 

Item 5.

Other Information

62

 

 

 

Item 6.

Exhibits

62

 

 

 

 

Signatures

63

 

2



Table of Contents

 

FORWARD LOOKING STATEMENTS

 

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, impacts from the 2011 tornado, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

 

·                  weather, business and economic conditions and other factors which may impact sales volumes and customer growth;

·                  the amount, terms and timing of rate relief we seek and related matters;

·                  the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

·                  volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

·                  the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures, fuel and purchased power costs and Southwest Power Pool (SPP) regional transmission organization (RTO) expansion costs;

·                  operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

·                  the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

·                  the periodic revision of our construction and capital expenditure plans and cost and timing estimates;

·                  legislation and regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

·                  competition, including the SPP Energy Imbalance Market;

·                  electric utility restructuring, including ongoing federal activities and potential state activities;

·                  the impact of electric deregulation on off-system sales;

·                  changes in accounting requirements (including as a result of being required to report in accordance with IFRS rather than U. S. GAAP);

·                  the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses;

·                  rate regulation, growth rates, discount rates, capital spending rates, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

·                  the effect of changes in our credit ratings on the availability and cost of funds;

·                  the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

·                  interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

·                  the success of efforts to invest in and develop new opportunities;

·                  costs and effects of legal and administrative proceedings, settlements, investigations and claims;

·                  our exposure to the credit risk of our hedging counterparties; and

·                  other circumstances affecting anticipated rates, revenues and costs.

 

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us.  Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

 

We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

 

3



Table of Contents

 

PART I.  FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

 

 

Three Months Ended

 

 

 

September 30

 

 

 

2011

 

2010

 

 

 

(000’s except per share amounts)

 

Operating revenues:

 

 

 

 

 

Electric

 

$

157,118

 

$

146,620

 

Gas

 

5,052

 

5,403

 

Water

 

501

 

508

 

Other

 

1,613

 

1,555

 

 

 

164,284

 

154,086

 

Operating revenue deductions:

 

 

 

 

 

Fuel and purchased power

 

54,316

 

57,286

 

Cost of natural gas sold and transported

 

1,225

 

1,554

 

Regulated operating expenses

 

23,299

 

20,309

 

Other operating expenses

 

507

 

481

 

Maintenance and repairs

 

9,891

 

8,722

 

Depreciation and amortization

 

14,757

 

14,622

 

Provision for income taxes

 

15,672

 

11,934

 

Other taxes

 

8,167

 

7,305

 

 

 

127,834

 

122,213

 

 

 

 

 

 

 

Operating income

 

36,450

 

31,873

 

Other income and (deductions):

 

 

 

 

 

Allowance for equity funds used during construction

 

82

 

840

 

Interest income

 

29

 

30

 

Benefit for other income taxes

 

20

 

14

 

Other — non-operating expense, net

 

(522

)

(245

)

 

 

(391

)

639

 

Interest charges:

 

 

 

 

 

Long-term debt

 

10,654

 

10,757

 

Short-term debt

 

23

 

114

 

Allowance for borrowed funds used during construction

 

(77

)

(771

)

Other

 

275

 

(569

)

 

 

10,875

 

9,531

 

 

 

 

 

 

 

Net income

 

$

25,184

 

$

22,981

 

 

 

 

 

 

 

Weighted average number of common shares outstanding - basic

 

41,951

 

41,404

 

 

 

 

 

 

 

Weighted average number of common shares outstanding - diluted

 

41,984

 

41,448

 

 

 

 

 

 

 

Total earnings per weighted average share of common stock — basic

 

$

0.60

 

$

0.56

 

Total earnings per weighted average share of common stock — diluted

 

$

0.60

 

$

0.55

 

Dividends per share of common stock

 

$

0.00

 

$

0.32

 

 

See accompanying Notes to Consolidated Financial Statements.

 

4



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

(000’s except per share amounts)

 

Operating revenues:

 

 

 

 

 

Electric

 

$

404,955

 

$

366,469

 

Gas

 

33,344

 

36,480

 

Water

 

1,353

 

1,377

 

Other

 

4,453

 

4,136

 

 

 

444,105

 

408,462

 

Operating revenue deductions:

 

 

 

 

 

Fuel and purchased power

 

155,761

 

152,225

 

Cost of natural gas sold and transported

 

15,977

 

18,929

 

Regulated operating expenses

 

62,100

 

58,497

 

Other operating expenses

 

1,630

 

1,448

 

Maintenance and repairs

 

29,673

 

26,129

 

Depreciation and amortization

 

48,978

 

41,394

 

Provision for income taxes

 

28,529

 

26,263

 

Other taxes

 

24,026

 

21,347

 

 

 

366,674

 

346,232

 

 

 

 

 

 

 

Operating income

 

77,431

 

62,230

 

Other income and (deductions):

 

 

 

 

 

Allowance for equity funds used during construction

 

152

 

4,493

 

Interest income

 

68

 

152

 

Benefit/(provision) for other income taxes

 

53

 

(78

)

Other — non-operating expense, net

 

(981

)

(747

)

 

 

(708

)

3,820

 

Interest charges:

 

 

 

 

 

Long-term debt

 

31,927

 

31,325

 

Trust preferred securities

 

 

2,090

 

Short-term debt

 

69

 

604

 

Allowance for borrowed funds used during construction

 

(158

)

(5,616

)

Other

 

(1,396

)

(1,289

)

 

 

30,442

 

27,114

 

 

 

 

 

 

 

Net income

 

$

46,281

 

$

38,936

 

 

 

 

 

 

 

Weighted average number of common shares outstanding - basic

 

41,810

 

40,220

 

 

 

 

 

 

 

Weighted average number of common shares outstanding - diluted

 

41,846

 

40,253

 

 

 

 

 

 

 

Total earnings per weighted average share of common stock — basic and diluted

 

$

1.11

 

$

0.97

 

Dividends per share of common stock

 

$

0.64

 

$

0.96

 

 

See accompanying Notes to Consolidated Financial Statements.

 

5



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

 

 

Twelve Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

(000’s except per share amounts)

 

Operating revenues:

 

 

 

 

 

Electric

 

$

521,397

 

$

469,103

 

Gas

 

47,750

 

52,993

 

Water

 

1,780

 

1,808

 

Other

 

5,992

 

5,427

 

 

 

576,919

 

529,331

 

Operating revenue deductions:

 

 

 

 

 

Fuel and purchased power

 

202,835

 

197,783

 

Cost of natural gas sold and transported

 

23,662

 

28,978

 

Regulated operating expenses

 

82,895

 

77,152

 

Other operating expenses

 

2,131

 

1,962

 

Maintenance and repairs

 

40,315

 

34,343

 

Depreciation and amortization

 

66,240

 

54,441

 

Provision for income taxes

 

32,737

 

29,379

 

Other taxes

 

30,408

 

26,927

 

 

 

481,223

 

450,965

 

 

 

 

 

 

 

Operating income

 

95,696

 

78,366

 

Other income and (deductions):

 

 

 

 

 

Allowance for equity funds used during construction

 

197

 

6,636

 

Interest income

 

93

 

189

 

Benefit/(provision) for other income taxes

 

67

 

(310

)

Other — non-operating expense, net

 

(1,273

)

(1,030

)

 

 

(916

)

5,485

 

Interest charges:

 

 

 

 

 

Long-term debt

 

42,561

 

41,951

 

Trust preferred securities

 

 

3,152

 

Short-term debt

 

96

 

748

 

Allowance for borrowed funds used during construction

 

(177

)

(7,326

)

Other

 

(2,440

)

(1,537

)

 

 

40,040

 

36,988

 

Net income

 

$

54,740

 

$

46,863

 

 

 

 

 

 

 

Weighted average number of common shares outstanding — basic

 

41,734

 

39,300

 

Weighted average number of common shares outstanding — diluted

 

41,771

 

39,329

 

 

 

 

 

 

 

Total earnings per weighted average share of common stock — basic and diluted

 

$

1.31

 

$

1.19

 

Dividends per share of common stock

 

$

0.96

 

$

1.28

 

 

See accompanying Notes to Consolidated Financial Statements.

 

6



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

 

 

Three Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

($-000’s)

 

 

 

 

 

 

 

Net income

 

$

25,184

 

$

22,981

 

Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability

 

 

4,864

 

Net change in fair market value of derivative contracts for period

 

 

(1,934

)

Income taxes

 

 

(1,116

)

 

 

 

 

 

 

Comprehensive income

 

$

25,184

 

$

24,795

 

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

($-000’s)

 

 

 

 

 

 

 

Net income

 

$

46,281

 

$

38,936

 

Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability

 

 

5,814

 

Net change in fair market value of derivative contracts for period

 

 

(7,258

)

Income taxes

 

 

550

 

 

 

 

 

 

 

Comprehensive income

 

$

46,281

 

$

38,042

 

 

 

 

Twelve Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

($-000’s)

 

 

 

 

 

 

 

Net income

 

$

54,740

 

$

46,863

 

Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability

 

 

6,703

 

Net change in fair market value of derivative contracts for period

 

896

 

(9,278

)

Income taxes

 

(341

)

981

 

 

 

 

 

 

 

Comprehensive income

 

$

55,295

 

$

45,269

 

 

See accompanying Notes to Consolidated Financial Statements.

 

7



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

($-000’s)

 

Assets

 

 

 

 

 

Plant and property, at original cost:

 

 

 

 

 

Electric

 

$

2,044,092

 

$

2,001,142

 

Natural gas

 

64,986

 

63,581

 

Water

 

11,444

 

11,128

 

Other

 

34,423

 

32,264

 

Construction work in progress

 

26,612

 

9,337

 

 

 

2,181,557

 

2,117,452

 

Accumulated depreciation and amortization

 

629,997

 

598,363

 

 

 

1,551,560

 

1,519,089

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

8,796

 

14,499

 

Accounts receivable — trade, net

 

51,914

 

41,380

 

Accrued unbilled revenues

 

10,788

 

23,595

 

Accounts receivable — other

 

23,098

 

25,445

 

Fuel, materials and supplies

 

56,898

 

45,557

 

Prepaid expenses and other

 

7,396

 

5,688

 

Regulatory assets

 

8,770

 

4,974

 

 

 

167,660

 

161,138

 

 

 

 

 

 

 

Noncurrent assets and deferred charges:

 

 

 

 

 

Regulatory assets

 

191,484

 

189,404

 

Goodwill

 

39,492

 

39,492

 

Unamortized debt issuance costs

 

9,535

 

9,257

 

Other

 

4,656

 

2,931

 

 

 

245,167

 

241,084

 

Total Assets

 

$

1,964,387

 

$

1,921,311

 

 

(Continued)

 

See accompanying Notes to Consolidated Financial Statements.

 

8



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

($-000’s)

 

Capitalization and Liabilities

 

 

 

 

 

Common stock, $1 par value, 41,955,716 and 41,576,869 shares issued and outstanding, respectively

 

$

41,956

 

$

41,577

 

Capital in excess of par value

 

617,593

 

610,579

 

Retained earnings

 

25,017

 

5,468

 

Total common stockholders’ equity

 

684,566

 

657,624

 

 

 

 

 

 

 

Long-term debt (net of current portion):

 

 

 

 

 

Obligations under capital lease

 

4,811

 

4,995

 

First mortgage bonds and secured debt

 

488,102

 

488,577

 

Unsecured debt

 

199,554

 

199,500

 

Total long-term debt

 

692,467

 

693,072

 

Total long-term debt and common stockholders’ equity

 

1,377,033

 

1,350,696

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

 

56,879

 

58,820

 

Current maturities of long-term debt

 

923

 

881

 

Short-term debt

 

4,000

 

24,000

 

Customer deposits

 

11,192

 

11,061

 

Interest accrued

 

12,126

 

6,004

 

Other current liabilities

 

1,181

 

578

 

Unrealized loss in fair value of derivative contracts

 

3,402

 

760

 

Taxes accrued

 

14,046

 

3,935

 

Regulatory liabilities

 

120

 

1,243

 

 

 

103,869

 

107,282

 

Commitments and contingencies (Note 7)

 

 

 

 

 

Noncurrent liabilities and deferred credits:

 

 

 

 

 

Regulatory liabilities

 

124,444

 

87,579

 

Deferred income taxes

 

247,671

 

212,003

 

Unamortized investment tax credits

 

19,296

 

19,597

 

Pension and other postretirement benefit obligations

 

67,329

 

93,405

 

Unrealized loss in fair value of derivative contracts

 

2,985

 

3,564

 

Other

 

21,760

 

47,185

 

 

 

483,485

 

463,333

 

Total Capitalization and Liabilities

 

$

1,964,387

 

$

1,921,311

 

 

See accompanying Notes to Consolidated Financial Statements.

 

9



Table of Contents

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2011

 

2010

 

 

 

($-000’s)

 

Operating activities:

 

 

 

 

 

Net income

 

$

46,281

 

$

38,936

 

Adjustments to reconcile net income to cash flows from operating activities:

 

 

 

 

 

Depreciation and amortization

 

61,902

 

49,644

 

Pension and other postretirement benefit costs, net of contribution

 

(21,085

)

(3,927

)

Deferred income taxes and unamortized investment tax credit, net

 

35,477

 

24,225

 

Allowance for equity funds used during construction

 

(152

)

(4,493

)

Stock compensation expense

 

1,565

 

2,355

 

Non-cash (gain)/loss on derivatives

 

(70

)

1,853

 

Other

 

387

 

 

Cash flows impacted by changes in:

 

 

 

 

 

Accounts receivable and accrued unbilled revenues

 

4,690

 

(9,274

)

Fuel, materials and supplies

 

(11,341

)

(3,491

)

Prepaid expenses, other current assets and deferred charges

 

(23,596

)

(15,733

)

Accounts payable and accrued liabilities

 

(8,622

)

(20,976

)

Interest, taxes accrued and customer deposits

 

16,364

 

18,393

 

Other liabilities and other deferred credits

 

4,338

 

(613

)

Accumulated provision — rate refunds

 

603

 

271

 

SWPA minimum flows payment

 

 

26,564

 

 

 

 

 

 

 

Net cash provided by operating activities

 

106,741

 

103,734

 

 

 

 

 

 

 

Investing activities:

 

 

 

 

 

Capital expenditures — regulated

 

(66,927

)

(78,695

)

Capital expenditures and other investments — non-regulated

 

(2,838

)

(2,360

)

 

 

 

 

 

 

Net cash used in investing activities

 

(69,765

)

(81,055

)

 

 

 

 

 

 

Financing activities:

 

 

 

 

 

Proceeds from first mortgage bonds, net

 

 

149,635

 

Debt financing costs

 

(854

)

 

Long-term debt issuance costs

 

 

(1,733

)

Proceeds from issuance of common stock, net of issuance costs

 

5,584

 

58,139

 

Repayment of first mortgage bonds

 

 

(50,000

)

Redemption of trust preferred securities

 

 

(50,000

)

Redemption of senior notes

 

 

(48,304

)

Net short-term debt repayments

 

(20,000

)

(31,500

)

Dividends

 

(26,732

)

(38,712

)

Other

 

(677

)

(1,136

)

 

 

 

 

 

 

Net cash used in financing activities

 

(42,679

)

(13,611

)

 

 

 

 

 

 

Net (decrease)/increase in cash and cash equivalents

 

(5,703

)

9,068

 

 

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

14,499

 

5,620

 

 

 

 

 

 

 

Cash and cash equivalents at end of period

 

$

8,796

 

$

14,688

 

 

See accompanying Notes to Consolidated Financial Statements.

 

10


 

 


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

Note 1 - Summary of Significant Accounting Policies

 

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

 

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

 

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2010, of which there were none.

 

Note 2 - Recently Issued and Proposed Accounting Standards

 

Fair Value:  In May 2011, the Financial Accounting Standards Board (FASB) amended the guidance governing fair value measurements and disclosure requirements. The revised guidance is intended to result in common fair value measurement and disclosure requirements in U.S. Generally Accepted Accounting Principles (GAAP) and International Financial Reporting Standards. The revised guidance changes the wording used to describe some of the requirements in U.S. GAAP. Additionally, some of the revisions clarify the FASB’s intent for the application of the guidance. The revised guidance will be applicable for interim and annual periods beginning after December 15, 2011. The application of this standard will not have a material impact on our results of operations, financial position or liquidity.

 

Other Comprehensive Income:  In June 2011, the FASB amended the guidance governing the presentation of other comprehensive income. Under the revised guidance, items of net income and other comprehensive income may be presented in one single statement, or in two separate, but consecutive, statements. The statements are required to be presented with equal prominence as the other primary financial statements. The revised guidance will be applicable for interim and annual periods beginning after December 15, 2011. The application of this standard will not have a material impact on our results of operations, financial position or liquidity.

 

Goodwill impairment: In September 2011, the FASB amended the guidance governing goodwill impairment testing. Under the revised guidance an entity will be permitted to complete a qualitative analysis to determine if further impairment testing is necessary. The standard is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. The application of this standard will not have a material impact on our results of operations, financial position or liquidity.

 

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding recently issued and proposed accounting standards.

 

Note 3— Regulatory Matters

 

Construction Accounting. The Missouri Public Service Commission (MPSC) approved a regulatory plan in 2005, allowing construction accounting. Construction accounting, for the purposes of this regulatory plan, was specific to Iatan 1 and Iatan 2 and allowed us to defer certain charges as regulatory assets. These deferred charges included depreciation, operations and maintenance and

 

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carrying costs related to operation of the facilities until the facilities were ultimately included in our rates. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which were approximately $8.3 million as of September 30, 2011 and are recorded in Non-Current Regulatory Liabilities. Construction accounting began for Iatan 2 in August 2010 when it met its in-service criteria on August 26, 2010. In addition, in our 2009 Missouri rate case, construction accounting was approved for Plum Point, which met its in-service criteria on August 13, 2010. Construction accounting for Plum Point applied only to construction costs incurred subsequent to February 28, 2010. All of these deferrals began at the in-service dates and are to be amortized at the weighted average of the current depreciation rates for these plants once they were included in our rates, which for Iatan 2 and Plum Point was on June 15, 2011, the effective date of rates for our recently completed Missouri rate case. The amortization of the deferred Iatan 1 costs began in September 2010.

 

As part of a stipulated agreement in our 2009 Kansas rate case, approved by the KCC on June 25, 2010, we also defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, which was filed on June 17, 2011 as an abbreviated case. These deferrals will be recovered over a 3-5 year period as determined in the next case. (See Note 7 for additional details).

 

Rate base inclusion or amortizable lives for some of our regulatory assets and liabilities have been modified since December 31, 2010. As a result of our recently completed Missouri rate case, a tracking mechanism has been created to track the 2010 Southwest Power Administration (SWPA) payment and associated taxes (see Note 12). The Missouri jurisdictional portion of the payment will be amortized over ten years and reflected as a reduction to fuel expense. The Arkansas jurisdictional portion of the 2010 SWPA payment will be amortized on a straight-line basis over a 50 year period and reflected in the fuel adjustment clause. A tracking mechanism was also created related to the Plum Point, Iatan 2 and Iatan common plant operating expenses. The tracker is to exclude consumables and SO2 allowances which are recovered through the fuel adjustment clause. A regulatory asset or liability will be recorded for the difference between the Missouri jurisdictional portion of actual expenses and the annual recovery allowance with a corresponding charge or credit to regulated operating expense.

 

The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet (in thousands).

 

Regulatory Assets and Liabilities

 

 

 

September 30, 2011

 

December 31, 2010

 

Regulatory Assets:

 

 

 

 

 

Under recovered electric fuel and purchased power costs — current

 

$

8,770

 

$

4,974

 

Regulatory assets, current(1)

 

8,770

 

4,974

 

Pension and other postretirement benefits(2)

 

85,700

 

92,192

 

Income taxes

 

49,707

 

50,188

 

Unamortized loss on reacquired debt

 

11,982

 

13,099

 

Deferred operating and maintenance expenses

 

442

 

 

Unamortized loss on interest rate derivative

 

1,541

 

1,776

 

Asbury five-year maintenance

 

606

 

948

 

Storm costs(3)

 

5,440

 

7,733

 

Deferred construction accounting costs(4)

 

17,012

 

10,521

 

Asset retirement obligation

 

3,532

 

3,412

 

Under recovered electric fuel and purchased gas costs

 

1,069

 

 

Under recovered purchased gas costs — gas segment

 

1,159

 

439

 

Unsettled derivative losses — electric segment

 

4,505

 

3,166

 

Customer programs

 

3,205

 

2,119

 

System reliability — vegetation management

 

4,871

 

3,338

 

Other

 

713

 

473

 

Regulatory assets, long-term

 

191,484

 

189,404

 

Total

 

$

200,254

 

$

194,378

 

 

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September 30, 2011

 

December 31, 2010

 

Regulatory Liabilities:

 

 

 

 

 

Over recovered purchased gas costs — gas segment - current

 

$

120

 

$

1,243

 

Regulatory liabilities, current(1)

 

120

 

1,243

 

Cost of removal

 

70,932

 

62,756

 

SWPA payment for Ozark Beach lost generation

 

25,689

 

 

Income taxes

 

12,344

 

12,715

 

Unamortized gain on interest rate derivative

 

3,754

 

3,881

 

Pension and other postretirement benefits(5)

 

3,210

 

4,604

 

Deferred construction accounting costs — fuel

 

8,340

 

3,126

 

Over recovered electric fuel and purchased power costs

 

175

 

155

 

Other

 

 

342

 

Regulatory liabilities, long-term

 

124,444

 

87,579

 

Total

 

$

124,564

 

$

88,822

 

 


(1)  Reflects under or over recovered costs expected to be recovered within the next 12 months in Missouri rates.

(2)  Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.4 million in pension and other postretirement benefit costs have been recognized since January 1, 2011 to reflect the amortization of the regulatory assets that were recorded at the time of the EDG acquisition of the Aquila, Inc. gas properties.

(3)  Primarily reflects ice storm costs incurred in 2007.

 

(4)

Balances as of September 30, 2011

 

Deferred Carrying Charges

 

Deferred O&M

 

Depreciation

 

Total

 

 

Iatan 1

 

$

2,738

 

1,368

 

1,657

 

$

5,763

 

 

Iatan 2

 

$

3,908

 

4,244

 

2,689

 

$

10,841

 

 

Plum Point

 

$

65

 

207

 

136

 

$

408

 

 

Total

 

 

 

 

 

 

 

$

17,012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances as of December 31, 2010

 

Deferred Carrying Charges

 

Deferred O&M

 

Depreciation

 

Total

 

 

Iatan 1

 

$

2,779

 

1,388

 

1,682

 

$

5,849

 

 

Iatan 2

 

$

1,770

 

1,643

 

1,111

 

$

4,524

 

 

Plum Point

 

$

33

 

70

 

45

 

$

148

 

 

Total

 

 

 

 

 

 

 

$

10,521

 

 

(5) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs. Since January 1, 2011, regulatory liabilities and corresponding expenses have been reduced by approximately $0.5 million as a result of ratemaking treatment.

 

Note 4— Risk Management and Derivative Financial Instruments

 

We engage in hedging activities in an effort to minimize our risk from volatility in natural gas prices. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

 

All derivative instruments are recognized at fair value on the balance sheet. In conjunction with the implementation of the Missouri fuel adjustment clause, the unrealized losses or gains from new derivatives used to hedge our fuel costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

 

Risks and uncertainties affecting the determination of fair value include:  market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating

 

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underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment clause.

 

As of September 30, 2011 and December 31, 2010, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

 

 

 

September 30,

 

December 31,

 

ASSET DERIVATIVES

 

2011

 

2010

 

Non-designated hedging
instruments due to regulatory accounting

 

Balance Sheet Classification

 

Fair Value

 

Fair Value

 

Natural gas contracts, gas segment

 

Current assets

 

$

 

$

39

 

 

 

Non-current assets and deferred charges

 

 

117

 

 

 

 

 

 

 

 

 

Natural gas contracts, electric segment

 

Current assets

 

 

 

 

 

Non-current assets and deferred charges

 

 

77

 

Total derivatives assets

 

 

 

$

 

$

233

 

 

 

 

September 30,

 

December 31,

 

LIABILITY DERIVATIVES

 

2011

 

2010

 

Non-designated hedging instruments
due to regulatory accounting

 

Balance Sheet Classification

 

Fair Value

 

Fair Value

 

Natural gas contracts, gas segment

 

Current liabilities

 

$

469

 

$

252

 

 

 

Non-current liabilities and deferred credits

 

73

 

2

 

 

 

 

 

 

 

 

 

Natural gas contracts, electric segment

 

Current liabilities

 

2,933

 

508

 

 

 

Non-current liabilities and deferred credits

 

2,912

 

3,562

 

Total derivatives liabilities

 

 

 

$

6,387

 

$

4,324

 

 

Electric

 

At September 30, 2011, approximately $2.9 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

 

The following tables set forth the actual pre-tax gains/(losses) and the mark to market effect of unsettled positions from the qualified portion of our hedging activities for settled contracts for the electric segment for each of the periods ended September 30, (in thousands):

 

Derivatives in Cash
Flow Hedging

 

Income Statement
Classification of

 

Amount of Gain / (Loss) Reclassed from OCI into Income
(Effective portion)

 

Relationships -

 

Gain / (Loss) on

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

Electric Segment

 

Derivative

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Commodity contracts

 

Fuel and purchased power expense

 

$

 

$

(4,864

)

$

 

$

(5,814

)

$

 

$

(6,703

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Effective — Electric Segment

 

 

 

$

 

$

(4,864

)

$

 

$

(5,814

)

$

 

$

(6,703

)

 

Derivatives in Cash
Flow Hedging 

 

Statement of

 

Amount of Gain / (Loss) Recognized in OCI on Derivative
(Effective portion)

 

Relationships - 

 

Comprehensive

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

Electric Segment

 

Income

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Commodity contracts

 

Net change in fair value

 

$

 

$

(1,934

)

$

 

$

(7,258

)

$

(896

)

$

(9,278

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Effective — Electric Segment

 

 

 

$

 

$

(1,934

)

$

 

$

(7,258

)

$

(896

)

$

(9,278

)

 

There were no “mark-to-market” pre-tax gains/(losses) from ineffective portions of our hedging activities for the electric segment for the periods ended September 30, 2011 and 2010, respectively.

 

In accordance with the Missouri fuel adjustment clause discussed above, the recoverable portion of any gain or loss is recorded in a regulatory asset or liability account. The following tables

 

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Table of Contents

 

set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 30, (in thousands):

 

Non-Designated Hedging
Instruments - Due to

 

Balance Sheet
Classification of

 

Amount of (Loss) Recognized on Balance Sheet

 

Regulatory Accounting

 

Gain / (Loss) on

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

Electric Segment

 

Derivatives

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Commodity contracts

 

Regulatory (assets)/liabilities

 

$

(2,022

)

$

(1,646

)

$

(2,758

)

$

(3,384

)

$

(3,165

)

$

(3,840

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Electric Segment

 

 

 

$

(2,022

)

$

(1,646

)

$

(2,758

)

$

(3,384

)

$

(3,165

)

$

(3,840

)

 

Non-Designated Hedging
Instruments - Due to

 

Statement of
Operations
Classification of

 

Amount of (Loss) Recognized in Income

 

Regulatory Accounting

 

Gain / (Loss) on

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

Electric Segment

 

Derivatives

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Commodity contracts

 

Fuel and purchased power expense

 

$

(966

)

$

(363

)

$

(1,358

)

$

(760

)

$

(1,441

)

$

(859

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Electric Segment

 

 

 

$

(966

)

$

(363

)

$

(1,358

)

$

(760

)

$

(1,441

)

$

(859

)

 

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

 

As of October 21, 2011, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2011 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

 

Dth Hedged

 

Year

 

% Hedged

 

Physical

 

Financial

 

Average Price

 

Remainder 2011

 

44

%

327,500

 

 

$

7.085

 

2012

 

60

%

2,325,000

 

1,420,000

 

$

6.618

 

2013

 

41

%

2,020,000

 

1,440,000

 

$

6.079

 

2014

 

20

%

460,000

 

1,120,000

 

$

5.607

 

2015

 

7

%

 

700,000

 

$

5.562

 

 

We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

 

Year

 

Minimum % Hedged

 

Current

 

Up to 100%

 

First

 

60%

 

Second

 

40%

 

Third

 

20%

 

Fourth

 

10%

 

 

Gas

 

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter

 

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progresses, gas is withdrawn from storage to serve our customers. As of September 30, 2011, we had 1.5 million Dths in storage on the three pipelines that serve our customers. This represents 76% of our storage capacity.

 

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2011.

 

Season

 

Minimum %
Hedged

 

Dth Hedged
Financial

 

Dth Hedged
Physical

 

Dth in Storage

 

Actual % Hedged

 

Current

 

50%

 

790,000

 

222,200

 

1,532,769

 

70

%

Second

 

Up to 50%

 

310,000

 

 

 

7

%

Third

 

Up to 20%

 

 

 

 

%

Total

 

 

 

1,100,000

 

222,200

 

1,532,769

 

 

 

 

A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

 

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended September 30, (in thousands).

 

Non-Designated Hedging

 

Balance Sheet
Classification of

 

Amount of (Loss) Recognized on Balance Sheet

 

Instruments Due to Regulatory

 

Gain / (Loss) on

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

Accounting - Gas Segment

 

Derivatives

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Commodity contracts

 

Regulatory (assets)/liabilities

 

$

(572

)

$

(602

)

$

(842

)

$

(781

)

$

(688

)

$

(283

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total - Gas Segment

 

 

 

$

(572

)

$

(602

)

$

(842

)

$

(781

)

$

(688

)

$

(283

)

 

Contingent Features

 

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on September 30, 2011, is $1.2 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2011, we would have been required to post $1.2 million of collateral with the counterparty.

 

Note 5— Fair Value Measurements

 

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data. Our Level 3 fair value measurements consist of both quoted price inputs and unobservable inputs.

 

The guidance also requires that the fair value measurements of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of

 

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our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

 

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of September 30, 2011 and December 31, 2010.

 

($ in 000’s)

 

 

 

 

 

Fair Value Measurements at Reporting Date Using

 

Description

 

Liabilities
at Fair Value

 

Quoted Prices in 
Active Markets for 
Identical Liabilities
(Level 1)

 

Significant Other 
Observable
Inputs
(Level 2)

 

Significant 
Unobservable 
Inputs
(Level 3)

 

 

 

 

 

September 30, 2011

 

 

 

 

 

Net derivative liabilities*

 

$

(6,387

)

$

(6,387

)

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

Net derivative liabilities*

 

$

(4,091

)

$

(4,091

)

$

 

$

 

 


*The only recurring measurements are derivative commodity contracts. Therefore, assets and liabilities are netted together in the table above.

 

The following table presents the change in net fair value of our Level 3 assets/liabilities during the twelve months ended September 30, 2011 and 2010. There were no Level 3 assets/liabilities for the three and six months ended September 30, 2011 and 2010.

 

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — 12 Months Ended

 

 

 

2011

 

2010

 

 

 

Derivatives Commodity

 

Derivatives Commodity

 

($ in 000’s)

 

Contracts(1)

 

Contracts(1)

 

Beginning Balance, October 1,

 

$

 

$

3,237

 

Total gains or (losses) (realized/unrealized)

 

 

 

 

 

Included in earnings (or changes in net assets)

 

 

 

Included in comprehensive income

 

 

 

 

Purchases, issuances, and settlements

 

 

 

Transfers out of Level 3(2) (3)

 

 

 

(3,237

)

Ending Balance, September 30,

 

$

 

$

 

Changes in unrealized gains relating to assets still held at reporting date

 

$

 

$

 

 


(1) Net derivatives at September 30, 2011 and 2010 included no derivative assets or derivative liabilities.

(2) Transferred from Level 3 to Level 1 due to an increase in availability of observable market data and increased market liquidity for these derivatives.

(3) The company’s policy is to recognize transfers in and out of a level as of the end of the period.

 

Long-Term Debt

 

The carrying amount of our total debt exclusive of capital leases at September 30, 2011, was $688 million compared to a fair market value of approximately $746 million. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of September 30, 2011, or that will be realizable in the future.

 

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Note 6— Financing

 

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250 million of such securities in the form of first mortgage bonds. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

 

On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated our unsecured $150 million revolving credit facility. This agreement extended the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013.

 

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios would result in an event of default under the credit facility and would prohibit us from borrowing funds thereunder. As of September 30, 2011, we are in compliance with these ratios. Our total indebtedness is 50.5% of our total capitalization as of September 30, 2011 and our EBITDA is 5.25 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at September 30, 2011. However, $4.0 million was used to back up our outstanding commercial paper.

 

Note 7— Commitments and Contingencies

 

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

 

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of Plaintiff crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are a 12% owner. This matter was set for trial beginning November 7, 2011, but has now been rescheduled for March 14, 2012. We are unable to predict the outcome of the law suit or estimate the amount of damages, if any.

 

On March 12, 2010, we filed Generation Formula Rate (GFR) tariffs with the Federal Energy Regulatory Commission (FERC) which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

 

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Coal, Natural Gas and Transportation Contracts

 

(in millions)

 

Firm physical gas and 
transportation contracts

 

Coal and coal 
transportation contracts

 

 

 

 

 

 

 

October 1, 2011 through December 31, 2011

 

$

10.4

 

$

8.6

 

January 1, 2012 through December 31, 2013

 

56.9

 

56.6

 

January 1, 2014 through December 31, 2015

 

29.4

 

36.4

 

January 1, 2016 and beyond

 

25.8

 

15.7

 

 

In addition to the above, we have signed an agreement with Southern Star Central Pipeline, Inc. to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years which began in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually.

 

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price. The firm physical gas and transportation commitments are detailed in the table above.

 

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts are detailed in the table above.

 

Purchased Power

 

We currently supplement our on-system generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

 

We have a long-term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a 665-megawatt, coal-fired generating facility operated by North America Energy Services near Osceola, Arkansas which met its in-service criteria on August 13, 2010. We began receiving purchased power on September 1, 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. Commitments under this contract total approximately $37.3 million through August 30, 2015.

 

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We also have a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under GAAP, payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

 

New Construction

 

We purchased an undivided ownership interest in the coal-fired Iatan 2 generating facility operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri. We own 12%, or approximately 102 megawatts, of the 850-megawatt unit, which met its in-service criteria on August 26, 2010 and

 

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entered commercial operation on December 31, 2010. Our share of the Iatan 2 construction costs is expected to be in a range of approximately $237 million to $240 million, excluding AFUDC. Our share of the Iatan 2 costs through September 30, 2011 was $232.6 million plus AFUDC of $19.1 million. KCP&L project management expects that project closeout will be substantially complete by the end of the second quarter of 2012. These construction costs will be subject to prudency reviews by our regulators. We have requested or been granted recovery with respect to certain of these costs as set forth in the following section.

 

Recovery of construction costs

 

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case that was effective September 10, 2010. A settlement agreement was filed on May 27, 2011, reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7%. As part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011. The prudency of the construction costs for Iatan 1, Iatan 2 and Plum Point was not addressed in this case but may be considered in a future rate proceeding.

 

On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the Oklahoma Corporation Commission (OCC) with the first phase effective September 1, 2010. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. The CRR revenue being collected is subject to refund/true-up in the next general rate case. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers (which would replace the CRR with permanent rates) in the amount of $0.6 million, or 4.1%, over the base rate and CRR revenues that are currently in effect.

 

A stipulated agreement in our 2009 Kansas rate case was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We are deferring depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date of the rates from the next Kansas case, which was filed on June 17, 2011 as an abbreviated case seeking a rate increase of $1.5 million, or 6.39%. This case includes a request to recover the Iatan and Plum Point cost deferrals over a 3 year period.

 

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement included a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

 

Leases

 

We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these arrangements are disclosed in the Purchased Power section of this note.

 

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

 

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Environmental Matters

 

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. Environmental requirements have changed frequently and become more stringent over time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect any such costs to be material, although recoverable in rates.

 

Electric Segment

 

Air

 

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, and nitrogen oxides (NOx). In the future they are also likely to include limits on emissions of mercury, other hazardous pollutants (HAPs) and so-called greenhouse gases (GHG) such as carbon dioxide (CO2) and methane.

 

Permits

 

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants.

 

SO2 Emissions

 

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are limited by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). In 2012, CAIR will be replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule) however, the Title IV Acid Rain Program will still remain in effect.

 

The Power Plant Mercury and Air Toxics Standards Rule (Toxics Rule), discussed below, is expected to be issued December 16, 2011 and will affect SO2 emission rates at our facilities. In addition, the compliance date for existing sources with the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017, which will also affect SO2 emissions. The SO2 NAAQS is discussed in more detail below.

 

Title IV Acid Rain Program:

 

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance allows the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2010, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our Title IV Acid Rain Program SO2 allowance bank is exhausted, currently estimated to be early 2012, we will need to purchase additional SO2 allowances, blend more low sulfur coal at our facilities or fuel switch to natural gas at our coal-fired Riverton Units 7 and 8. The longer term solution may be some combination of the above until a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant can be constructed. We expect the cost of compliance to be fully recoverable in our rates.

 

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CAIR:

 

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.

 

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

 

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. Beginning in 2010, SO2 allowances were utilized at a 2:1 ratio for our Missouri units. As a result, based on current SO2 allowance usage projections, we expected to have sufficient allowances to take us up to the beginning of the CSAPR program, which replaces CAIR and is set to begin January 1, 2012 (CSAPR is discussed in more detail below).

 

In order to meet CAIR requirements for SO2 and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a FGD scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was installed at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

 

CSAPR- formerly the Clean Air Transport Rule:

 

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and becomes effective January 1, 2012. The final rule requires a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program cannot be used for compliance with CSAPR but will continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances will be allocated under CSAPR and will be retired at one allowance per ton of SO2 emissions emitted. We will receive fewer SO2 allowances than we currently emit. Compliance options range from purchasing additional emission allowances to using more low sulfur coal to installing a FGD scrubber at our Asbury facility (see estimated construction costs below) and potential forced retirement or fuel switching to natural gas of our coal-fired Riverton Units 7 and 8. A number of states, including Kansas, electric utilities and industrial organizations have filed litigation with the District of Columbia Court of Appeals to block implementation of the rule. We expect compliance costs, if incurred, to be recoverable in our rates.

 

Toxics Rule

 

Proposed by the EPA on March 16, 2011 and scheduled to take effect by the end of this year, this regulation does not include allowance mechanisms, but would establish alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the Toxics Rule section below).

 

SO2 National Ambient Air Quality Standard (NAAQS):

 

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no SO2 monitor, will require modeling to determine attainment and non-attainment areas within each state. This modeling of emission sources is to be completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking to

 

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address some of the 1-hour SO2 NAAQS implementation program elements. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

 

NOx Emissions

 

The CAA regulates the amount of NOx an affected unit can emit. Each of our affected units is in compliance with the NOx limits applicable to it as currently operated. Currently, revised NOx emissions are limited by the CAIR and will be limited by the CSAPR beginning in 2012 and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

 

CAIR:

 

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is located. Kansas was not included in CAIR and our Riverton Plant was not affected.

 

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing State SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance through the end of the CAIR program in 2011. The CAIR NOx program will also be replaced by the CSAPR program January 1, 2012.

 

CSAPR:

 

The final rule requires a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR cannot be used for compliance under CSAPR.  New allowances will be issued under CSAPR.

 

To address NOx annual and NOx ozone season compliance, options range from increasing the level of control with the Asbury SCR, fuel switching to natural gas at our Riverton Plant coal-fired units, or purchasing emission allowances. We expect the cost of compliance to be fully recoverable in our rates.

 

Ozone NAAQS:

 

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary NAAQS for ozone designed to protect public health to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems.

 

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States will move forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory will be designated as attainment, meaning it will be in compliance with the standard. In the interim, the 1997 ozone NAAQS will remain in effect.

 

Toxics Rule

 

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of

 

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Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

 

The EPA issued an Information Collection Request (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. All ICRs were submitted as required. The EPA ICR was intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of HAPs, including mercury. The EPA proposed the first ever national mercury and air toxics standards (Power Plant Mercury and Air Toxics Standards Rule) in March 2011. It is expected to be finalized by the end of this year and would establish numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply.

 

Absent a successful legal challenge or changes to applicable legislation, we expect the Toxics Rule regulation of HAPs in combination with CSAPR to ultimately require a scrubber, baghouse and powder activated carbon injection system to be added to our Asbury facility at a cost ranging from $120 million to $180 million and to force retirement of our Riverton coal-fired assets or a switch to natural gas fuel. Our Riverton coal-fired units were designed to combust either coal or natural gas. We expect compliance costs to be recoverable in our rates.

 

Green House Gases

 

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other GHGs which are measured in Carbon Dioxide Equivalents (CO2e).

 

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. GHG emissions have been reported as required to the EPA in 2011 for EDE and EDG.

 

On December 7, 2009, responding to a 2007 US Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding does not itself trigger any EPA regulations, but is a necessary predicate for the EPA to proceed with regulations to control GHGs. On May 13, 2010, the EPA issued under the CAA its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) to address GHG emissions from stationary sources, which became effective January 2, 2011. The rule sets thresholds for GHG emissions that determine when permits will be required under the New Source Review Prevention of Significant Deterioration (PSD) and title V Operating Permit programs applicable to new and existing power plants and other covered sources. Under the PSD program, required controls for GHG emissions would be determined based on Best Available Control Technology (BACT). EPA issued a BACT permitting guidance document on November 11, 2010. Missouri and Kansas have been delegated GHG permitting authority by EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging the EPA’s Endangerment Finding and the Tailoring Rule.

 

In addition, on December 23, 2010 the EPA entered into an agreement with a number of state and environmental petitioners to settle litigation pending in the U.S. Court of Appeals for the District of Columbia Circuit that requires EPA to propose New Source Performance Standards (NSPS) for GHGs for fossil-fuel fired steam generating units by September 30, 2011 and to issue final GHG NSPS standards by May 26, 2012. The EPA has not to date issued a proposed GHG emissions rule for stationary sources.

 

A variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

 

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Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

 

The ultimate cost of any GHG regulations cannot be determined at this time. However, we would expect the cost of complying with any such regulations to be recoverable in our rates.

 

Water Discharges

 

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received necessary discharge permits.

 

The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR). In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011 and is obligated to finalize the rule by July 27, 2012.

 

We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have an impact at Riverton ranging from minor improvements to the cooling water intake structure to retirement of units 7 and 8. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

 

Surface Impoundments

 

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants before 2012. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of the coal ash impoundments are compliant with existing state and federal regulations.

 

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal the EPA presents two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in late 2011 or in 2012. We expect compliance with either option as proposed to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

 

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On September 23, 2010 and on November 4, 2010 representatives from GEI Consultants, on behalf of the EPA, conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. We released a Request for Proposal (RFP) on August 24, 2011 to complete additional geotechnical studies and install additional monitoring devices at both coal ash impoundments. The work project is expected to be completed in December 2012 and will accomplish the recommendations made by the EPA in its site assessment reports.

 

Renewable Energy

 

We currently purchase more than 15% of our energy through long-term Purchased Power Agreements (PPAs) with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and “unbundles” the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

 

On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires us and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase RECs, at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021. Two percent of this amount must be solar. We believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied.

 

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped but the remainder of the ruling remains intact. We are complying with the portions of the rule left intact requiring us and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021.

 

Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2011, 15% by 2016, and 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

 

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. Over time, we expect to retain a sufficient amount of RECs to meet any current or future RPS.

 

Gas Segment

 

The acquisition of our natural gas distribution assets in June 2006 involved the potential future remediation of two former manufactured gas plant (FMGP) sites. FMGP Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term. We have received a letter stating no further action is required from the MDNR with respect to FMPG Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two sites to be minimal.

 

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Note 8 — Retirement Benefits

 

Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

 

 

 

Three months ended September 30,

 

 

 

Pension Benefits

 

SERP

 

OPEB

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Service cost

 

$

1,399

 

$

1,119

 

$

23

 

$

18

 

$

566

 

$

585

 

Interest cost

 

2,601

 

2,486

 

46

 

37

 

1,096

 

1,122

 

Expected return on plan assets

 

(2,785

)

(2,419

)

 

 

(1,039

)

(950

)

Amortization of prior service cost (1)

 

133

 

133

 

(2

)

(2

)

(253

)

(253

)

Amortization of net actuarial loss (1)

 

1,374

 

930

 

43

 

8

 

441

 

436

 

Net periodic benefit cost

 

$

2,722

 

$

2,249

 

$

110

 

$

61

 

$

811

 

$

940

 

 

 

 

Nine months ended September 30,

 

 

 

Pension Benefits

 

SERP

 

OPEB

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Service cost

 

$

4,197

 

$

3,665

 

$

70

 

$

52

 

$

1,699

 

$

1,603

 

Interest cost

 

7,804

 

7,586

 

137

 

115

 

3,287

 

3,247

 

Expected return on plan assets

 

(8,354

)

(7,385

)

 

 

(3,118

)

(2,883

)

Amortization of prior service cost (1)

 

398

 

399

 

(6

)

(6

)

(758

)

(758

)

Amortization of net actuarial loss (1)

 

4,121

 

2,997

 

128

 

72

 

1,322

 

1,124

 

Net periodic benefit cost

 

$

8,166

 

$

7,262

 

$

329

 

$

233

 

$

2,432

 

$

2,333

 

 

 

 

Twelve months ended September 30,

 

 

 

Pension Benefits

 

SERP

 

OPEB

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Service cost

 

$

5,418

 

$

4,818

 

$

87

 

$

68

 

$

2,234

 

$

2,060

 

Interest cost

 

10,333

 

10,055

 

176

 

152

 

4,370

 

4,224

 

Expected return on plan assets

 

(10,816

)

(9,980

)

 

 

(4,079

)

(3,843

)

Amortization of prior service cost (1)

 

532

 

550

 

(8

)

(8

)

(1,011

)

(1,011

)

Amortization of net actuarial loss (1)

 

5,120

 

3,792

 

152

 

98

 

1,696

 

1,341

 

Net periodic benefit cost

 

$

10,587

 

$

9,235

 

$

407

 

$

310

 

$

3,210

 

$

2,771

 

 


(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

 

In accordance with our regulatory agreements, our funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We made the following quarterly contributions to our Pension Trust in 2011: $13.5 million on March 29, 2011, $2.1 million on April 13, 2011, $2.1 million on July 14, 2011, and $2.1 million on October 6, 2011. In addition to these quarterly contributions, we made an additional $10.0 million contribution on September 16, 2011. The actual minimum funding requirements for 2012 will be determined by the performance of our pension assets during 2011. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

 

Note 9— Stock-Based Awards and Programs

 

Our performance based restricted stock awards, stock options and their related dividend equivalents and time vested restricted stock awards are valued as liability awards, in accordance with fair value guidelines. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

 

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended September 30 (in thousands):

 

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Table of Contents

 

 

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Compensation Expense

 

$

358

 

$

569

 

$

1,317

 

$

2,097

 

$

2,414

 

$

2,551

 

Tax Benefit Recognized

 

121

 

205

 

460

 

754

 

866

 

912

 

 

Activity for our various stock plans for the nine months ended September 30, 2011, is summarized below:

 

Performance-Based Restricted Stock Awards

 

Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The fair value of the outstanding restricted stock awards was estimated using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

 

 

 

Fair Value of Grants Outstanding at September 30,

 

 

 

2011

 

2010

 

Risk-free interest rate

 

0.02% to 0.29%

 

0.17% to 0.50%

 

Expected volatility of Empire stock

 

27.8%

 

27.6%

 

Expected volatility of peer group stock

 

20.4% to 78.0%

 

21.9% to 82.6%

 

Expected dividend yield on Empire stock

 

0.00% to 4.6%

 

6.8%

 

Expected forfeiture rates

 

3%

 

3%

 

Plan cycle

 

3 years

 

3 years

 

Fair value percentage

 

62.0% to 87.0%

 

120.0% to 140.0%

 

Weighted average fair value per share

 

$ 14.85

 

$ 26.63

 

 

Non-vested restricted stock awards (based on target number) as of September 30, 2011 and 2010 and changes during the nine months ended September 30, 2011 and 2010 were as follows:

 

 

 

2011

 

2010

 

 

 

Number

 

Weighted Average

 

Number

 

Weighted Average

 

 

 

of shares

 

Grant Date Price

 

of shares

 

Grant Date Price

 

Nonvested at January 1,

 

47,500

 

$

19.86

 

52,200

 

$

21.57

 

Granted

 

10,900

 

$

21.84

 

13,000

 

$

18.36

 

Awarded

 

(39,621

)

$

21.92

 

(15,104

)

$

23.81

 

Awarded in excess of target

 

18,621

 

$

21.92

 

 

 

 

 

Not Awarded

 

 

 

(2,596

)

 

 

 

 

 

 

 

 

 

 

 

Nonvested at September 30,

 

37,400

 

$

19.28

 

47,500

 

$

19.86

 

 

At September 30, 2011, there was $0.1 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

 

Stock Options

 

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of September 30, 2011 and 2010, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

 

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Table of Contents

 

 

 

Fair Value of Grants Outstanding at September 30,

 

 

 

2011

 

2010

 

Risk-free interest rate

 

0.13% to 0.94 %

 

0.38% to 1.59 %

 

Expected dividend yield

 

4.1% to 4.9 %

 

6.8 %

 

Expected volatility

 

24.0 %

 

24.0 %

 

Expected life in months

 

78

 

78

 

Market value

 

$ 19.38

 

$ 20.15

 

Weighted average fair value per option

 

$   1.42

 

$   1.35

 

 

 

 

2011

 

2010

 

 

 

 

 

Weighted Average

 

 

 

Weighted Average

 

 

 

Options

 

Exercise Price

 

Options

 

Exercise Price

 

Outstanding at January 1,

 

267,400

 

$

21.69

 

232,600

 

$

22.19

 

Granted

 

 

 

34,800

 

$

18.36

 

Exercised

 

77,100

 

$

22.02

 

 

 

 

Outstanding at September 30,

 

190,300

 

$

21.56

 

267,400

 

$

21.69

 

Exercisable at September 30,

 

128,500

 

$

23.15

 

149,200

 

$

23.04

 

 

The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value is zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic values at September 30, 2011 and 2010:

 

 

 

2011

 

2010

 

Aggregate intrinsic value (in millions)

 

$0.1

 

$0.1

 

Weighted-average remaining contractual life of outstanding options

 

5.3 years

 

6.3 years

 

Range of exercise prices

 

$18.12 to $23.81

 

$18.12 to $23.81

 

Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan

 

Less than $0.1

 

$0.2

 

Recognition period

 

0.3 to 1.3 years

 

1 to 3 years

 

 

Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options.

 

Time-Vested Restricted Stock Awards

 

Beginning in 2011, time-vested restricted stock awards were granted to qualified individuals that vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock, discounted by the dividend yield, on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award.

 

On February 2, 2011, shares of time-vested restricted stock were granted to qualified individuals at the fair market value per the table below:

 

29



Table of Contents

 

 

 

2011

 

 

 

Number of shares

 

Grant Date Price

 

Outstanding at January 1,

 

 

$

 

Granted

 

10,200

 

$

21.84

 

Vested

 

 

 

 

 

 

 

 

 

Outstanding at September 30,

 

10,200

 

$

21.84

 

 

All time-vested restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The cost of the awards is generally recognized over the requisite (explicit) service period.

 

Employee Stock Purchase Plan

 

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of September 30, 2011, there were 261,792 shares available for issuance in this plan.

 

 

 

2011

 

2010

 

Subscriptions outstanding at September 30

 

72,182

 

72,516

 

Maximum subscription price

 

$

17.27

 

$

16.06

 

Shares of stock issued (1)

 

69,229

 

66,723

 

Stock issuance price

 

$

16.06

 

$

14.62

 

 


(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2011 to May 31, 2012.

 

Assumptions for valuation of these shares are shown in the table below.

 

 

 

ESPP

 

 

 

2011

 

2010

 

Weighted average fair value of grants

 

$

3.17

 

$

2.28

 

Risk-free interest rate

 

0.18

%

0.35

%

Expected dividend yield

 

2.60

%

7.20

%

Expected volatility

 

22.0

%

17.00

%

Expected life in months

 

12

 

12

 

Grant Date

 

6/1/11

 

6/1/10

 

 

Note 10- Regulated Operating Expenses

 

The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income (in thousands) for all periods presented ended September 30:

 

 

 

Three
Months
Ended

 

Three
Months
Ended

 

Nine
Months
Ended

 

Nine
Months
Ended

 

Twelve
Months
Ended

 

Twelve
Months
Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Electric transmission and distribution expense

 

$

4,101

 

$

3,448

 

$

11,341

 

$

9,419

 

$

14,918

 

$

12,317

 

Natural gas transmission and distribution expense

 

652

 

541

 

1,793

 

1,588

 

2,399

 

2,135

 

Power operation expense (other than fuel)

 

4,316

 

3,140

 

9,463

 

8,835

 

11,984

 

11,913

 

Customer accounts and assistance expense

 

2,614

 

2,893

 

7,545

 

8,810

 

10,353

 

11,532

 

Employee pension expense (1)

 

2,504

 

1,355

 

6,323

 

4,106

 

8,116

 

5,520

 

Employee healthcare plan (1)

 

1,999

 

1,939

 

5,336

 

5,184

 

7,082

 

6,558

 

General office supplies and expense

 

2,382

 

2,778

 

7,517

 

8,159

 

10,942

 

10,729

 

Administrative and general expense

 

3,537

 

2,999

 

10,240

 

9,633

 

13,504

 

13,071

 

Allowance for uncollectible accounts

 

1,169

 

1,179

 

2,494

 

2,634

 

3,511

 

3,218

 

Miscellaneous expense

 

25

 

37

 

48

 

129

 

86

 

159

 

Total

 

$

23,299

 

$

20,309

 

$

62,100

 

$

58,497

 

$

82,895

 

$

77,152

 

 

30



Table of Contents

 


(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri and Kansas jurisdictions.

 

Note 11— Segment Information

 

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our fiber optics business.

 

The tables below present statement of operations information, balance sheet information and capital expenditures of our business segments.

 

 

 

For the quarter ended September 30, 2011

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

157,619

 

$

5,052

 

$

1,761

 

$

(148

)

$

164,284

 

Depreciation and amortization

 

13,418

 

873

 

466

 

 

14,757

 

Federal and state income taxes

 

15,703

 

(257

)

206

 

 

15,652

 

Operating income

 

35,359

 

517

 

574

 

 

36,450

 

Interest income

 

30

 

75

 

 

(76

)

29

 

Interest expense

 

10,047

 

979

 

2

 

(76

)

10,952

 

Income from AFUDC (debt and equity)

 

158

 

1

 

 

 

159

 

Net income

 

25,276

 

(427

)

335

 

 

25,184

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

20,800

 

$

1,841

 

$

1,452

 

 

 

$

24,093

 

 

 

 

For the quarter ended September 30, 2010

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

147,128

 

$

5,403

 

$

1,703

 

$

(148

)

$

154,086

 

Depreciation and amortization

 

13,354

 

844

 

424

 

 

14,622

 

Federal and state income taxes

 

11,864

 

(241

)

297

 

 

11,920

 

Operating income

 

30,827

 

557

 

489

 

 

31,873

 

Interest income

 

36

 

80

 

 

(86

)

30

 

Interest expense

 

9,392

 

989

 

7

 

(86

)

10,302

 

Income from AFUDC (debt and equity)

 

1,605

 

6

 

 

 

1,611

 

Net income

 

22,887

 

(388

)

482

 

 

22,981

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

21,081

 

$

750

 

$

369

 

 

 

$

22,200

 

 

 

 

For the nine months ended September 30, 2011

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

406,308

 

$

33,344

 

$

4,897

 

$

(444

)

$

444,105

 

Depreciation and amortization

 

45,027

 

2,617

 

1,334

 

 

48,978

 

Federal and state income taxes

 

26,676

 

1,111

 

689

 

 

28,476

 

Operating income

 

71,430

 

4,639

 

1,362

 

 

77,431

 

Interest income

 

68

 

204

 

 

(204

)

68

 

Interest expense

 

27,865

 

2,933

 

6

 

(204

)

30,600

 

Income from AFUDC (debt and equity)

 

308

 

2

 

 

 

310

 

Net income

 

43,369

 

1,792

 

1,120

 

 

46,281

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

70,685

 

$

2,875

 

$

2,900

 

 

 

$

76,460

 

 

31



Table of Contents

 

 

 

For the nine months ended September 30, 2010

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

367,846

 

$

36,480

 

$

4,580

 

$

(444

)

$

408,462

 

Depreciation and amortization

 

38,028

 

2,184

 

1,182

 

 

41,394

 

Federal and state income taxes

 

24,642

 

981

 

718

 

 

26,341

 

Operating income

 

56,700

 

4,334

 

1,196

 

 

62,230

 

Interest income

 

169

 

339

 

 

(356

)

152

 

Interest expense

 

30,099

 

2,959

 

28

 

(356

)

32,730

 

Income from AFUDC (debt and equity)

 

10,097

 

12

 

 

 

10,109

 

Net income

 

36,216

 

1,553

 

1,167

 

 

38,936

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

74,862

 

$

1,636

 

$

2,328

 

 

 

$

78,826

 

 

 

 

For the twelve months ended September 30, 2011

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

523,177

 

$

47,750

 

$

6,584

 

$

(592

)

$

576,919

 

Depreciation and amortization

 

60,983

 

3,465

 

1,792

 

 

66,240

 

Federal and state income taxes

 

29,959

 

1,751

 

960

 

 

32,670

 

Operating income

 

87,258

 

6,631

 

1,807

 

 

95,696

 

Interest income

 

97

 

269

 

 

(273

)

93

 

Interest expense

 

36,564

 

3,915

 

11

 

(273

)

40,217

 

Income from AFUDC (debt and equity)

 

366

 

8

 

 

 

374

 

Net income

 

50,340

 

2,840

 

1,560

 

 

54,740

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

96,532

 

$

6,480

 

$

3,342

 

 

 

$

106,354

 

 

 

 

For the twelve months ended September 30, 2010

 

 

 

Electric

 

Gas

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Information

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

470,911

 

$

52,993

 

$

6,019

 

$

(592

)

$

529,331

 

Depreciation and amortization

 

50,196

 

2,691

 

1,554

 

 

54,441

 

Federal and state income taxes

 

27,148

 

1,619

 

922

 

 

29,689

 

Operating income

 

70,541

 

6,290

 

1,535

 

 

78,366

 

Interest income

 

210

 

400

 

 

(421

)

189

 

Interest expense

 

40,753

 

3,946

 

36

 

(421

)

44,314

 

Income from AFUDC (debt and equity)

 

13,949

 

13

 

 

 

13,962

 

Net Income

 

42,902

 

2,462

 

1,499

 

 

46,863

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures

 

$

109,992

 

$

2,337

 

$

2,677

 

 

 

$

115,006

 

 

 

 

As of September 30, 2011

 

 

 

Electric

 

Gas(1)

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Information

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

1,882,904

 

$

141,679

 

$

25,658

 

$

(85,854

)

$

1,964,387

 

 


(1) Includes goodwill of $39,492.

 

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Table of Contents

 

 

 

As of December 31, 2010

 

 

 

Electric

 

Gas(1)

 

Other

 

Eliminations

 

Total

 

($-000’s)

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Information

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

1,837,910

 

$

139,532

 

$

23,163

 

$

(79,294

)

$

1,921,311

 

 


(1) Includes goodwill of $39,492.

 

Note 12— Income Taxes

 

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30:

 

 

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Consolidated provision for income taxes

 

$

15.7

 

$

11.9

 

$

28.5

 

$

26.3

 

$

32.7

 

$

29.7

 

Consolidated effective federal and state income tax rates

 

38.3

%

34.2

%

38.1

%

40.4

%

37.4

%

38.8

%

 

The effective tax rate for the three months ended September 30, 2011 is higher than the comparable period primarily due to substantially decreased equity AFUDC in the third quarter of 2011. The effective tax rates for the nine months ended September 30, 2011, and the twelve months ended September 30, 2011, are lower than comparable year periods primarily due to an adjustment made in 2010 as a result of the Patient Protection and Affordable Care Act, which became law on March 23, 2010. This legislation included a provision that removed the non-taxable status, for income tax purposes, of Medicare D subsidies received. Although the elimination of this tax benefit does not take effect until 2013, this change required us to recognize the full accounting impact in our financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to reflect the impact of this change, which increased our effective tax rate in 2010 and our 2010 provision for income taxes.

 

As part of an agreement reached in our 2009 Missouri electric rate case, effective September 10, 2010, we also agreed to commence an eighteen year amortization of a regulatory asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981-2008 and totaled approximately $11.1 million. We had recorded the regulatory asset expecting to recover these benefits from customers in future periods. Based on the agreement, we estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization of the remaining regulatory tax asset began during the third quarter of 2011.

 

We received $26.6 million in 2010 from the SWPA which has been deferred for book purposes and treated as a noncurrent liability and is more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010. We increased our current tax liability by $10.0 million in recognition that the $26.6 million payment may be considered taxable income in 2010. During the first quarter of 2011, we submitted a pre-filing agreement with the Internal Revenue Service (IRS) requesting that a determination be made regarding whether or not the payment could be deferred under certain sections of the Internal Revenue code. The IRS has signed the pre-filing agreement accepting our position that the payment be deferred for tax purposes and will be recognized over the next twenty years.

 

We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The reserve balance related to unrecognized tax benefits as of December 31, 2010 was $359,000. With the running of the statute of limitations on these unrecognized tax benefits on September 15, 2011, there are no unrecognized tax benefits at September 30, 2011.

 

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Table of Contents

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

EXECUTIVE SUMMARY

 

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business. During the twelve months ended September 30, 2011, 90.7% of our gross operating revenues were provided from sales from our electric segment (including 0.3% from the sale of water), 8.3% from our gas segment and 1.0% from our other segment.

 

Earnings

 

During the third quarter of 2011, basic earnings per weighted average share of common stock were $0.60 as compared to $0.56 in the third quarter of 2010 and diluted earnings per weighted average share of common stock were $0.60 as compared to $0.55 in the third quarter of 2010. For the nine months ended September 30, 2011, basic and diluted earnings per weighted average share of common stock were $1.11 as compared to $0.97 for the nine months ended September 30, 2010. For the twelve months ended September 30, 2011, basic and diluted earnings per weighted average share of common stock were $1.31 as compared to $1.19 for the twelve months ended September 30, 2010. The primary positive driver for all periods presented was increased electric revenues (due primarily to rate increases). Also positively impacting the nine and twelve month periods were decreased interest charges. The primary negative drivers for the nine and twelve month periods were changes in AFUDC amounts due to the completion of our construction program, increased depreciation and amortization amounts and the dilutive effect of additional shares issued. A portion of the increase in depreciation and amortization expense reflects the effect of additional regulatory amortization collected in revenues in our Missouri rate case effective September 2010. The regulatory amortization expense ended effective June 15, 2011.

 

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months, nine months and twelve months ended September 30, 2010 and September 30, 2011, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

 

We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers’ understanding of the reasons for the EPS change from the previous year’s EPS. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

 

This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statement of income. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

 

34



Table of Contents

 

 

 

Three Months
 Ended

 

Nine Months
 Ended

 

Twelve Months
 Ended

 

Earnings Per Share — September 30, 2010

 

$

0.56

 

$

0.97

 

$

1.19

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

Electric on-system

 

$

0.17

 

$

0.57

 

$

0.79

 

Electric off-system and other

 

(0.01

)

0.05

 

0.08

 

Gas

 

(0.01

)

(0.05

)

(0.09

)

Other

 

0.00

 

0.00

 

0.01

 

Expenses

 

 

 

 

 

 

 

Electric fuel and purchased power

 

0.05

 

(0.06

)

(0.08

)

Cost of natural gas sold and transported

 

0.00

 

0.05

 

0.09

 

Operating — electric segment

 

(0.05

)

(0.07

)

(0.11

)

Operating —gas segment

 

0.00

 

0.01

 

0.02

 

Maintenance and repairs

 

(0.02

)

(0.06

)

(0.10

)

Depreciation and amortization

 

0.00

 

(0.12

)

(0.20

)

Other taxes

 

(0.01

)

(0.04

)

(0.06

)

Interest charges

 

(0.01

)

0.03

 

0.07

 

AFUDC

 

(0.02

)

(0.16

)

(0.23

)

Change in effective income tax rates

 

(0.04

)

0.03

 

0.02

 

Other income and deductions

 

0.00

 

0.00

 

(0.01

)

Dilutive effect of additional shares issued

 

(0.01

)

(0.04

)

(0.08

)

Earnings Per Share — September 30, 2011

 

$

0.60

 

$

1.11

 

$

1.31

 

 

Recent Activities

 

Tornado and Dividend Suspension

 

On May 22, 2011, a devastating EF-5 tornado hit the Joplin, Missouri area damaging or destroying thousands of homes and businesses. At the end of the second quarter of 2011, approximately 4,200 customers remained unable to return to service. Joplin’s tornado recovery efforts during the third quarter of 2011, however, resulted in approximately 300 customers returning to service, leaving approximately 3,900 customers still unable to return to service due to damaged or destroyed structures. Approximately 600 temporary housing facilities were added to our system during the third quarter to shelter some local residents displaced by the tornado. We estimate lost customers from the tornado will reduce kilowatt hour sales approximately 2.5%-3% over the near term. Storm restoration costs are estimated to be in the $20 million to $30 million range, of which approximately $19.1 million has been incurred to date. The majority of these costs have been capitalized. The ongoing loss of revenue associated with the tornado has been mitigated by increased usage due to storm recovery efforts, rate increases that became effective during 2010 and early 2011 and record hot weather during the month of July. We expect a continuing loss of electric load and corresponding revenues as customers rebuild. In addition, we currently expect our growth to be relatively flat now through 2012 for our electric service territory.

 

In response to this expected loss of revenues, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. Based on current conditions and knowledge, at the October 2011 meeting, the Board of Directors reaffirmed their expectation to re-establish the dividend at an approximate level of $0.25 per quarter beginning with the first quarter of 2012.

 

On June 6, 2011, we filed an Accounting Authority Order with the MPSC requesting authorization to defer expenses associated with the tornado and to allow for recovery of the loss of the fixed cost component included in our rates resulting from the lost sales. On June 23, 2011, Praxair, Inc. and Explorer Pipeline Company filed as intervenors with the MPSC, who granted their request on July 6, 2011. The order is still pending.

 

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Table of Contents

 

New Union Agreement

 

At September 30, 2011, we had 742 full-time employees, including 50 employees of EDG. 337 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On October 17, 2011, the Local 1474 IBEW voted to ratify a new two-year agreement which will extend through October 31, 2013.

 

Coal Conservation related to Missouri River Flooding

 

The Iatan plant, located along the Missouri River north of Kansas City and operated by Kansas City Power & Light (“KCP&L”), was impacted by flooding in the Midwest during June and July of 2011. Beginning June 30, 2011 coal deliveries to Iatan were suspended. As a result, in early July it was decided to begin operating Iatan Units 1 and 2 at reduced loads in an effort to conserve coal. Additionally, we entered into a short term purchase of power for the month of August to address a portion of the lost generation from the Iatan units. We would expect that any additional fuel and purchased power costs incurred as a result of this event would be recovered in our rates through fuel recovery mechanisms. The Iatan plant returned to normal operations on October 13, 2011.

 

Amendment of EDE Mortgage

 

On June 9, 2011, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the indenture and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 73.91% in aggregate principal amount of the outstanding bonds and paid consent fees of approximately $0.9 million. See “Dividends” below.

 

Financings

 

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250 million of such securities in the form of first mortgage bonds. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

 

Regulatory Matters

 

A settlement agreement among the parties to our Missouri rate case filed on September 28, 2010 was reached and filed with the MPSC on May 27, 2011, reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7%, effective June 15, 2011. Due to rate design changes, this rate increase, however, will primarily impact our winter season rates which generally run from October through May. Also as part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated on June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011.

 

On June 17, 2011, we filed an application with the Kansas Corporation Commission (KCC) seeking a rate increase of $1.5 million, or 6.39%. The rate increase is being requested to recover the costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the

 

36



Table of Contents

 

depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC’s abbreviated rate case rules which the KCC authorized in our 2009 Kansas rate case. The case includes a request to recover the Iatan and Plum Point cost deferrals over a 3-year period.

 

On June 30, 2011, we filed a request with the Oklahoma Corporation Commission (OCC) for an annual increase in base rates for our Oklahoma electric customers in the amount of $0.6 million, or 4.1% over the base rate and Capital Reliability Rider (CRR) revenues that are currently in effect.

 

On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved in our Arkansas rate case filed August 19, 2010. The settlement included a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

 

On March 12, 2010, we filed Generation Formula Rate (GFR) tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

 

For additional information on all these cases, see “Rate Matters” below.

 

RESULTS OF OPERATIONS

 

The following discussion analyzes significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2011, compared to the same periods ended September 30, 2010.

 

The following table represents our results of operations by operating segment for the applicable periods ended September 30 (in millions):

 

 

 

Quarter Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric

 

$

25.3

 

$

22.9

 

$

43.4

 

$

36.2

 

$

50.3

 

$

42.9

 

Gas

 

(0.4

)

(0.4

)

1.8

 

1.6

 

2.8

 

2.5

 

Other

 

0.3

 

0.5

 

1.1

 

1.1

 

1.6

 

1.5

 

Net income

 

$

25.2

 

$

23.0

 

$

46.3

 

$

38.9

 

$

54.7

 

$

46.9

 

 


*Differences could occur due to rounding.

 

Electric Segment

 

Overview

 

Our electric segment income for the third quarter of 2011 was $25.3 million as compared to $22.9 million for the third quarter of 2010, an increase of $2.4 million, primarily due to the September 2010 Missouri rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase (discussed below).

 

Electric operating revenues comprised approximately 95.6% of our total operating revenues during the third quarter of 2011. Electric operating revenues for the third quarter of 2011 and 2010 were comprised of the following:

 

 

 

2011

 

2010

 

Residential

 

43.8

%

43.3

%

Commercial

 

30.1

 

30.9

 

Industrial

 

15.3

 

14.4

 

Wholesale on-system

 

3.9

 

4.0

 

Wholesale off-system

 

3.0

 

3.4

 

Miscellaneous sources*

 

2.5

 

2.5

 

Other electric revenues

 

1.4

 

1.5

 

 


*primarily public authorities

 

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Table of Contents

 

The amounts and percentage changes from the prior periods in kilowatt-hour (“kWh”) sales and operating revenues by major customer class for on-system sales and for off-system sales for the applicable periods ended September 30, were as follows:

 

 

 

kWh Sales
(in millions)

 

 

 

3 Months

 

3 Months

 

 

 

9 Months

 

9 Months

 

 

 

12 Months

 

12 Months

 

 

 

 

 

Ended

 

Ended

 

%

 

Ended

 

Ended

 

%

 

Ended

 

Ended

 

%

 

Customer Class

 

2011

 

2010

 

Change*

 

2011

 

2010

 

Change*

 

2011

 

2010

 

Change*

 

Residential

 

578.8

 

586.4

 

(1.3

)%

1,569.6

 

1,621.9

 

(3.2

)%

2,008.1

 

2,079.3

 

(3.4

)%

Commercial

 

442.7

 

461.7

 

(4.1

)

1,202.9

 

1,252.9

 

(4.0

)

1,594.9

 

1,644.6

 

(3.0

)

Industrial

 

277.7

 

272.3

 

2.0

 

777.4

 

762.7

 

1.9

 

1,021.7

 

997.0

 

2.5

 

Wholesale on-system

 

105.5

 

102.8

 

2.6

 

281.8

 

273.2

 

3.2

 

364.4

 

352.3

 

3.4

 

Other**

 

34.3

 

33.8

 

1.5

 

98.3

 

97.2

 

1.2

 

127.6

 

127.7

 

(0.1

)

Total on-system sales

 

1,439.0

 

1,457.0

 

(1.2

)

3,930.0

 

4,007.9

 

(1.9

)

5,116.7

 

5,200.9

 

(1.6

)

Off-system

 

132.9

 

158.2

 

(16.0

)

585.9

 

554.0

 

5.8

 

830.0

 

723.6

 

14.7

 

Total KWh Sales

 

1,571.9

 

1,615.2

 

(2.7

)

4,515.9

 

4,561.9

 

(1.0

)

5,946.7

 

5,924.5

 

0.4

 

 


*Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

**Other kWh sales include street lighting, other public authorities and interdepartmental usage.

 

 

 

Electric Segment Operating Revenues
($ in millions)

 

 

 

3 Months

 

3 Months

 

 

 

9 Months

 

9 Months

 

 

 

12 Months

 

12 Months

 

 

 

 

 

Ended

 

Ended

 

%

 

Ended

 

Ended

 

%

 

Ended

 

Ended

 

%

 

Customer Class

 

2011

 

2010

 

Change*

 

2011

 

2010

 

Change*

 

2011

 

2010

 

Change*

 

Residential

 

$

68.8

 

$

63.5

 

8.4

%

$

174.4

 

$

157.8

 

10.5

%

$

221.4

 

$

200.2

 

10.6

%

Commercial

 

47.3

 

45.2

 

4.5

 

119.6

 

109.8

 

9.0

 

156.2

 

141.4

 

10.5

 

Industrial

 

24.0

 

21.2

 

13.4

 

60.5

 

52.3

 

15.7

 

77.9

 

67.0

 

16.3

 

Wholesale on-system

 

6.2

 

5.9

 

3.8

 

14.9

 

15.4

 

(3.2

)

18.7

 

19.5

 

(3.8

)

Other**

 

3.9

 

3.6

 

9.6

 

10.6

 

9.3

 

13.7

 

13.6

 

12.0

 

13.0

 

Total on-system revenues

 

$

150.2

 

$

139.4

 

7.8

 

$

380.0

 

$

344.6

 

10.3

 

$

487.8

 

$

440.1

 

10.8

 

Off-system

 

4.7

 

5.0

 

(5.9

)

18.7

 

16.3

 

14.7

 

25.3

 

21.4

 

18.2

 

Total revenues from kWh sales

 

154.9

 

144.4

 

7.3

 

398.7

 

360.9

 

10.5

 

513.1

 

461.5

 

11.2

 

Miscellaneous revenues***

 

2.2

 

2.2

 

(1.3

)

6.3

 

5.5

 

12.8

 

8.3

 

7.6

 

8.9

 

Total electric operating revenues

 

$

157.1

 

$

146.6

 

7.2

 

$

405.0

 

$

366.4

 

10.5

 

$

521.4

 

$

469.1

 

11.1

 

Water revenues

 

0.5

 

0.5

 

(1.3

)

1.3

 

1.4

 

(1.8

)

1.8

 

1.8

 

(1.5

)

Total electric segment operating revenues

 

$

157.6

 

$

147.1

 

7.1

 

$

406.3

 

$

367.8

 

10.5

 

$

523.2

 

$

470.9

 

11.1

 

 


*Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

**Other operating revenues include street lighting, other public authorities and interdepartmental usage.

***Miscellaneous revenues include transmission service revenue, late payment fees, renewable energy credit sales, rent, etc.

 

We have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs on our net income. For this reason, we believe electric gross margin, although a non-GAAP measurement, is useful for understanding and analyzing changes in our electric operating performance from one period to the next. We define electric gross margins as electric revenues less fuel and purchased power costs.

 

The table below represents our electric gross margins for the applicable periods ended September 30 (in millions), which is a non-GAAP presentation. We believe this presentation is useful to investors and have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

 

 

 

Quarter Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric revenues

 

$

157.1

 

$

146.6

 

$

405.0

 

$

366.4

 

$

521.4

 

$

469.1

 

Fuel and purchased power

 

54.3

 

57.3

 

155.8

 

152.2

 

202.8

 

197.8

 

Electric gross margins

 

$

102.8

 

$

89.3

 

$

249.2

 

$

214.2

 

$

318.6

 

$

271.3

 

Margin as % of total electric revenues

 

65.4

%

60.9

%

61.5

%

58.5

%

61.1

%

57.8

%

 

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Electric gross margins increased during 2011 in all periods presented mainly due to the Missouri, Oklahoma and Arkansas rate increases and to the July 2010 Kansas rate increase for the nine months and twelve months ended periods.

 

Quarter Ended September 30, 2011 Compared to Quarter Ended September 30, 2010

 

On-System Operating Revenues and Kilowatt-Hour Sales

 

KWh sales for our on-system customers decreased during the third quarter of 2011 as compared to the third quarter of 2010 primarily due to the loss of approximately 3,900 of our customers who remain unable to return to service due to damaged or destroyed structures resulting from the May 22, 2011 tornado, although some of the effect has been offset by temporary housing units. Revenues for our on-system customers increased approximately $10.8 million, or 7.8%. Rate changes, primarily the September 2010 Missouri rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $13.1 million to revenues. We estimate the impact of the tornado, after adjusting for weather, was a 2.5% reduction in kilowatt hour sales which corresponds to a $4.3 million reduction in revenues due to negative sales growth (contraction), resulting from the loss of customers due to the loss of residences and businesses. Weather and other related factors increased revenues an estimated $2.0 million, primarily due to favorable weather in the third quarter of 2011 and restoration activities that partially mitigated the impact of some of our load loss, as tornado victims and outside volunteers needing housing occupied hotels, rental properties and some temporary structures during much of the summer. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for the third quarter of 2011 were 4.8% more than the same period last year and 26.6% more than the 30-year average, mainly due to unseasonably hot weather in July 2011.

 

Residential and commercial kWh sales decreased during the third quarter of 2011 mainly due to customer contraction resulting from the loss of residences and businesses in the May 22, 2011 tornado. Residential and commercial revenues increased mainly due to the Missouri, Oklahoma and Arkansas rate increases discussed above.

 

Industrial kWh sales increased 2.0% during the third quarter of 2011 as compared to the third quarter of 2010. Industrial revenues increased mainly due to the Missouri, Oklahoma and Arkansas rate increases discussed above.

 

On-system wholesale kWh sales increased 2.6% during the third quarter of 2011 as compared to the same period in 2010 and revenues associated with these sales increased 3.8%, reflecting the warmer weather in the third quarter of 2011.

 

Off-System Electric Transactions

 

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See “— Competition” below. The majority of our off-system sales margins are included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on income.

 

Off-system sales and revenues decreased during the third quarter of 2011 compared to the third quarter of 2010 as the excessive heat in the third quarter of 2011 required us to use our resources to serve our own load and therefore we had limited power available for sale. Total purchased power related expenses are included in our discussion of purchased power costs below.

 

Miscellaneous Revenues

 

Our miscellaneous revenues were $2.2 million for both the third quarter of 2011 and the third quarter of 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

 

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Operating Revenue Deductions — Fuel and Purchased Power

 

During the third quarter of 2011, total fuel and purchased power expenses decreased approximately $3.0 million (5.2%). The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of income for the third quarter of 2011 and 2010.

 

(in millions)

 

2011

 

2010

 

Actual fuel and purchased power expenditures

 

$

59.9

 

$

59.6

 

Missouri fuel adjustment recovery(1)

 

1.1

 

2.0

 

Missouri fuel adjustment deferral(2)

 

(5.6

)

(4.8

)

Kansas regulatory adjustments(2)

 

(0.7

)

0.1

 

SWPA amortization(3)

 

(0.7

)

 

 

Unrealized loss/(gain) on derivatives

 

0.3

 

0.4

 

Total fuel and purchased power expense per income statement

 

$

54.3

 

$

57.3

 

 


(1) Recovered from customers from prior deferral period.

(2) A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

(3) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

 

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the third quarter of 2011 as compared to the third quarter of 2010. This table incorporates all the changes mentioned above.

 

 

 

Three Months Ended

 

(in millions)

 

September 30, 2011 vs. 2010

 

Natural gas generation volume

 

$

(1.3

)

Coal generation volume

 

0.5

 

Purchased power spot purchase volume

 

(1.0

)

Purchased power (cost per mWh)

 

0.6

 

Natural gas (cost per mWh)

 

(2.6

)

Coal (cost per mWh)

 

4.3

 

Other (primarily fuel adjustments)

 

(3.5

)

TOTAL

 

$

(3.0

)

 

Operating Revenue Deductions — Other Than Fuel and Purchased Power

 

Regulated operating expenses increased approximately $3.0 million (16.4%) during the third quarter of 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

 

(in millions)

 

2011 vs. 2010

 

Employee pension expense

 

$

1.1

 

Steam power other operating expense

 

0.8

 

Transmission expense(1)

 

0.5

 

Distribution expense

 

0.2

 

Other steam power expense(2)

 

0.3

 

General labor costs

 

(0.3

)

Injuries and damages expense

 

0.2

 

Other miscellaneous accounts (netted)

 

0.2

 

TOTAL

 

$

3.0

 

 


(1) Approximately $0.5 million of this total is for charges incurred for delivering the output from Plum Point to our system.

 

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(2) Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates.    Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Maintenance and repairs expense increased approximately $1.2 million (13.7%) in the third quarter of 2011 as compared to 2010 primarily due to changes in the following accounts:

 

(in millions)

 

2011 vs. 2010

 

Distribution maintenance costs

 

$

0.6

 

Transmission maintenance costs

 

0.2

 

Maintenance and repairs expense at the Iatan plant

 

0.2

 

Maintenance and repairs expense at the SLCC plant

 

0.3

 

Maintenance and repairs expense at the Plum Point plant

 

0.2

 

Maintenance and repairs expense at the Asbury plant

 

(0.5

)

Other miscellaneous accounts (netted)

 

0.2

 

TOTAL

 

$

1.2

 

 

Depreciation and amortization expense increased approximately $0.1 million (0.5%) during the quarter. This reflects increased depreciation of $1.4 million due to increased plant in service in the third quarter of 2011 as compared to the same period in 2010 and the effect of ending deferred depreciation of $0.4 million related to Iatan 2 as allowed in our regulatory agreements. This increase was offset by a decrease in regulatory amortization expense of $1.7 million due to the termination of construction accounting as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Other taxes increased approximately $0.8 million during the third quarter of 2011 mainly due to increased property tax reflecting our additions to plant in service.

 

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

 

On-System Operating Revenues and Kilowatt-Hour Sales

 

KWh sales for our on-system customers decreased during the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, primarily due to the loss of approximately 3,900 of our customers who remain unable to return to service due to damaged or destroyed structures resulting from the May 22, 2011 tornado, although some of the effect has been offset by temporary housing units. Revenues for our on-system customers increased approximately $35.4 million, or 10.3%. Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $42.3 million to revenues. Sales contraction resulting from the loss of customers due to the May 22, 2011 tornado decreased revenues an estimated $5.4 million. Weather and other related factors decreased revenues by an estimated $1.5 million during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010 primarily due to milder weather in the first quarter of 2011 as compared to the same period in 2010.

 

Residential and commercial kWh sales decreased during the nine months ended September 30, 2011 mainly due to customer contraction resulting from the loss of residences and businesses in the May 22, 2011 tornado. Residential and commercial revenues increased during the nine months ended September 30, 2011 mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

 

Industrial kWh sales increased 1.9% during the nine months ended September 30, 2011 while the related revenues increased 15.7% mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

 

On-system wholesale kWh sales increased 3.2% during the nine months ended September 30, 2011. Revenues associated with these sales decreased 3.2% primarily due to the portion of

 

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Table of Contents

 

FERC revenues that are subject to refund while we are waiting on approval of the Settlement Agreement and Offer of Settlement filed with the FERC on May 24, 2011.

 

Off-System Electric Transactions

 

Off-system sales and revenues were higher during the nine months ended September 30, 2011, as compared to the same period in 2010 primarily due to increased market demand in the first quarter of 2011. Total purchased power related expenses are included in our discussion of purchased power costs below.

 

Miscellaneous Revenues

 

Our miscellaneous revenues were $6.3 million for the nine months ended September 30, 2011, as compared to $5.5 million during the same period in 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

 

Operating Revenue Deductions — Fuel and Purchased Power

 

During the nine months ended September 30, 2011, total fuel and purchased power expenses increased approximately $3.5 million (2.3%). The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of income for the nine months ended September 30, 2011 and 2010.

 

(in millions)

 

2011

 

2010

 

Actual fuel and purchased power expenditures

 

$

155.9

 

$

157.6

 

Missouri fuel adjustment recovery(1)

 

6.0

 

1.5

 

Missouri fuel adjustment deferral(2)

 

(5.0

)

(7.4

)

Kansas regulatory adjustments(2)

 

(0.8

)

(0.3

)

SWPA amortization(3)

 

(0.8

)

 

 

Unrealized loss/(gain) on derivatives

 

0.5

 

0.8

 

Total fuel and purchased power expense per income statement

 

$

155.8

 

$

152.2

 

 


(1)   Recovered from customers from prior deferral period.

(2)   A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

(3)   Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

 

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010. This table incorporates all the changes mentioned above. As shown below, the largest impacts on fuel and purchased power costs were increased coal generation (mainly due to the availability of Iatan 2 and Plum Point) and increased coal costs, partially offset by decreased gas generation and purchased power.

 

(in millions)

 

Nine Months Ended
September 30, 2011 vs. 2010

 

Natural gas generation volume

 

$

(8.3

)

Coal generation volume

 

8.1

 

Purchased power spot purchase volume

 

(6.1

)

Purchased power (cost per mWh)

 

1.3

 

Natural gas (cost per mWh)

 

(4.0

)

Coal (cost per mWh)

 

8.4

 

Other (primarily fuel adjustments)

 

4.1

 

TOTAL

 

$

3.5

 

 

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Operating Revenue Deductions — Other Than Fuel and Purchased Power

 

Regulated operating expenses increased approximately $4.5 million (8.8%) during the nine months ended September 30, 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

 

(in millions)

 

2011 vs. 2010

 

Employee pension expense

 

$

2.4

 

Steam power other operating expense

 

2.4

 

Transmission expense(1)

 

1.9

 

Injuries and damages expense

 

0.7

 

Uncollectible accounts

 

0.3

 

Other power supply expense

 

0.2

 

Property insurance

 

0.2

 

General labor costs

 

(0.8

)

Other steam power expense(2)

 

(1.8

)

Professional services

 

(1.2

)

Other miscellaneous accounts (netted)

 

0.2

 

TOTAL

 

$

4.5

 

 


(1)          Approximately $1.4 million of this total is for charges incurred for delivering the output from Plum Point to our system.

(2)          Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates.  Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Maintenance and repairs expense increased approximately $3.6 million (13.9%) during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010 primarily due to changes in the following accounts:

 

(in millions)

 

2011 vs. 2010

 

Distribution maintenance costs

 

$

1.9

 

Maintenance and repairs expense at the Iatan plant

 

1.3

 

Maintenance and repairs expense at the SLCC plant

 

1.1

 

Maintenance and repairs expense at the Plum Point plant

 

0.7

 

Maintenance and repairs expense at the Asbury plant

 

(0.7

)

Maintenance and repairs expense to the Riverton coal units

 

(1.1

)

Other miscellaneous accounts (netted)

 

0.4

 

TOTAL

 

$

3.6

 

 

Depreciation and amortization expense increased approximately $7.0 million (18.4%) during the nine months ended September 30, 2011. This reflects additional regulatory amortization expense of $2.7 million granted in our Missouri rate case effective September 10, 2010 and which ended June 15, 2011. The remainder of the increase resulted from increased plant in service during the nine months ended September 30, 2011 as compared to the same period in 2010, net of the construction accounting effect of deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. The construction accounting effect of deferring Iatan 2 depreciation expense was $1.6 million as compared to $1.2 million of Iatan 1 and Iatan 2 depreciation expense in the prior period. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Other taxes increased approximately $2.8 million during the nine months ended September 30, 2011 primarily due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

 

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Table of Contents

 

Twelve Months Ended September 30, 2011 Compared to Twelve Months Ended September 30, 2010

 

On-System Operating Revenues and Kilowatt-Hour Sales

 

For the twelve months ended September 30, 2011, kWh sales to our on-system customers decreased 1.6% with the associated revenues increasing approximately $47.7 million (10.8%). Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $55.3 million to revenues. Sales contraction resulting from the loss of customers due to the May 22, 2011 tornado decreased revenues an estimated $4.9 million. Weather and other related factors decreased revenues by an estimated $2.7 million during the twelve months ended September 30, 2011 compared to the twelve months ended September 30, 2010.

 

The decrease in residential and commercial kWh sales during the twelve months ended September 30, 2011 was primarily due to the loss of residences and businesses in the May 22, 2011 tornado while the increase in revenues reflects the Missouri, Kansas, Oklahoma and Arkansas rate increases. Industrial kWh sales increased during the twelve months ended September 30, 2011 as compared to the same period in 2010 when there was a slowdown created by economic uncertainty. Industrial revenues also increased due to the Missouri, Kansas, Oklahoma and Arkansas rate increases. On-system wholesale kWh sales increased during the twelve months ended September 30, 2011 due to increased market demand. Revenues associated with these sales decreased 3.8% primarily due to the portion of FERC revenues that are subject to refund while we are waiting on approval of the Settlement Agreement and Offer of Settlement filed with the FERC on May 24, 2011.

 

Off-System Electric Transactions

 

Off-system sales and revenues increased during the twelve months ended September 30, 2011, as compared to the same period in 2010 primarily due to increased market demand resulting from the favorable weather discussed above. Total purchased power related expenses are included in our discussion of purchased power costs below.

 

Miscellaneous Revenues

 

Our miscellaneous revenues were $8.3 million for the twelve months ended September 30, 2011, as compared to $7.6 million during the same period in 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

 

Operating Revenue Deductions — Fuel and Purchased Power

 

During the twelve months ended September 30, 2011, total fuel and purchased power expenses increased approximately $5.1 million (2.6%). The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of income for the twelve months ended September 30, 2011 and 2010.

 

(in millions)

 

2011

 

2010

 

Actual fuel and purchased power expenditures

 

$

198.3

 

$

204.2

 

Missouri fuel adjustment recovery(1)

 

7.6

 

2.1

 

Missouri fuel adjustment deferral(2)

 

(2.2

)

(9.1

)

Kansas regulatory adjustments(2)

 

(0.6

)

(0.3

)

SWPA amortization(3)

 

(0.8

)

 

 

Unrealized loss on derivatives

 

0.5

 

0.9

 

Total fuel and purchased power expense per income statement

 

$

202.8

 

$

197.8

 

 


(1)    Recovered from customers from prior deferral period.

(2)    A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional

 

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Table of Contents

 

costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

(3)    Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

 

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the twelve months ended September 30, 2011, as compared to the twelve months ended September 30, 2010 This table incorporates all the changes mentioned above. As shown below, the largest impacts on fuel and purchased power costs were increased coal generation (mainly due to the availability of Iatan 2 and Plum Point) and increased coal costs, partially offset by decreased purchased power and decreased gas costs.

 

(in millions)

 

Twelve Months Ended
September 30, 2011 vs. 2010

 

Natural gas generation volume

 

$

(6.9

)

Coal generation volume

 

12.4

 

Purchased power spot purchase volume

 

(10.9

)

Purchased power (cost per mWh)

 

0.6

 

Natural gas (cost per mWh)

 

(7.9

)

Coal (cost per mWh)

 

8.3

 

Other (primarily fuel adjustments)

 

9.5

 

TOTAL

 

$

5.1

 

 

Operating Revenue Deductions — Other Than Fuel and Purchased Power

 

Regulated operating expenses increased approximately $6.8 million (10.0%) during the twelve months ended September 30, 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

 

(in millions)

 

2011 vs. 2010

 

Employee pension expense

 

$

3.1

 

Steam power other operating expense

 

2.9

 

Transmission expense (1)

 

2.6

 

Injuries and damages expense

 

0.9

 

Employee health care expense

 

0.5

 

Uncollectible accounts

 

0.7

 

General labor costs and office expense

 

0.2

 

Other power supply expense

 

0.2

 

Property insurance

 

0.3

 

Professional services

 

(1.8

)

Other steam power expense(2)

 

(2.8

)

TOTAL

 

$

6.8

 

 


(1)          Approximately $1.8 million of this total is for charges incurred for delivering the output from Plum Point to our system.

(2)          Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates.  Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Maintenance and repairs expense increased approximately $6.0 million (17.9%) during the twelve months ended September 30, 2011 as compared to the twelve months ended September 30, 2010 primarily due to changes in the following accounts:

 

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(in millions)

 

2011 vs. 2010

 

Distribution maintenance costs

 

$

3.1

 

Transmission maintenance costs

 

0.4

 

Maintenance and repairs expense at the Iatan plant

 

1.8

 

Maintenance and repairs expense at the SLCC plant

 

1.5

 

Maintenance and repairs expense at the Plum Point plant

 

0.9

 

Maintenance and repairs expense to the Riverton combustion turbines

 

0.4

 

Maintenance and repairs expense at the Asbury plant

 

(1.4

)

Maintenance and repairs expense to the Riverton coal units

 

(1.0

)

Other miscellaneous accounts (netted)

 

0.3

 

TOTAL

 

$

6.0

 

 

Depreciation and amortization expense increased approximately $10.8 million (21.5%) during the twelve months ended September 30, 2011. This reflects additional regulatory amortization expense of $5.2 million granted in our Missouri rate case effective September 10, 2010 and which ended June 15, 2011. The remainder of the increase resulted from increased plant in service during the twelve months ended September 30, 2011 as compared to the same period in 2010, net of the construction accounting effect of deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. The construction accounting effect of deferring Iatan 2 depreciation expense was $2.4 million as compared to $1.5 million of Iatan 1 and Iatan 2 depreciation expense in the prior period. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

 

Other taxes increased approximately $3.7 million during the twelve months ended September 30, 2011 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

 

Gas Segment

 

Gas Operating Revenues and Sales

 

The following tables detail our natural gas sales and revenues for the periods ended September 30:

 

Total Gas Delivered to Customers

 

 

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

 

 

 

 

%

 

 

 

 

 

%

 

 

 

 

 

%

 

(bcf sales)

 

2011

 

2010

 

change

 

2011

 

2010

 

change

 

2011

 

2010

 

change

 

Residential

 

0.10

 

0.10

 

(5.0

)%

1.79

 

1.81

 

(1.6

)%

2.65

 

2.77

 

(4.3

)%

Commercial

 

0.11

 

0.11

 

0.7

 

0.91

 

0.88

 

3.4

 

1.29

 

1.32

 

(2.0

)

Industrial

 

0.01

 

0.02

 

(49.7

)

0.07

 

0.08

 

(1.5

)

0.11

 

0.11

 

(2.4

)

Other(1)

 

0.00

 

0.00

 

23.5

 

0.03

 

0.03

 

1.6

 

0.04

 

0.03

 

(0.2

)

Total retail sales

 

0.22

 

0.23

 

(5.3

)

2.80

 

2.80

 

0.0

 

4.09

 

4.23

 

(3.5

)

Transportation sales

 

0.86

 

0.86

 

0.7

 

3.42

 

3.54

 

(3.6

)

4.70

 

4.91

 

(4.3

)

Total gas operating sales

 

1.08

 

1.09

 

(0.6

)

6.22

 

6.34

 

(2.0

)

8.79

 

9.14

 

(3.9

)

 

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Table of Contents

 

Operating Revenues and Cost of Gas Sold

 

 

 

Three Months Ended

 

 

 

Nine Months Ended

 

 

 

Twelve Months Ended

 

 

 

($ in millions)

 

2011

 

2010

 

% change

 

2011

 

2010

 

% change

 

2011

 

2010

 

% change

 

Residential

 

$

2.8

 

$

3.0

 

(5.6

)%

$

20.6

 

$

23.1

 

(10.6

)%

$

29.8

 

$

33.7

 

(11.7

)%

Commercial

 

1.4

 

1.5

 

(3.4

)

9.0

 

9.6

 

(5.6

)

12.8

 

14.1

 

(9.3

)

Industrial

 

0.1

 

0.1

 

(58.2

)

0.5

 

0.6

 

(16.3

)

0.7

 

0.9

 

(17.6

)

Other(1)

 

0.0

 

0.0

 

3.4

 

0.3

 

0.2

 

(5.0

)

0.4

 

0.4

 

(9.2

)

Total retail revenues

 

$

4.3

 

$

4.6

 

(6.4

)

$

30.4

 

$

33.5

 

(9.2

)

$

43.7

 

$

49.1

 

(11.1

)

Other revenues

 

0.1

 

0.1

 

45.1

 

0.4

 

0.3

 

21.6

 

0.5

 

0.4

 

42.1

 

Transportation revenues

 

0.6

 

0.7

 

(12.9

)

2.6

 

2.7

 

(4.1

)

3.6

 

3.5

 

2.1

 

Total gas operating revenues

 

$

5.0

 

$

5.4

 

(6.5

)

$

33.4

 

$

36.5

 

(8.6

)

$

47.8

 

$

53.0

 

(9.9

)

Cost of gas sold

 

1.2

 

1.6

 

(21.1

)

16.0

 

18.9

 

(15.6

)

23.7

 

29.0

 

(18.4

)

Gas operating revenues over cost of gas in rates

 

$

3.8

 

$

3.8

 

(0.6

)

$

17.4

 

$

17.6

 

(1.0

)

$

24.1

 

$

24.0

 

0.3

 

 


(1) Other includes other public authorities and interdepartmental usage.

 

Quarter Ended September 30, 2011 Compared to Quarter Ended September 30, 2010

 

Operating Revenues and bcf Sales

 

Gas retail sales decreased 5.3% during the third quarter of 2011 as compared to 2010. Residential and industrial sales decreased during the period primarily due to customer contraction. Commercial sales increased 0.7% during the third quarter of 2011 as compared to the same period in 2010.

 

During the third quarter of 2011, gas segment revenues were approximately $5.0 million as compared to $5.4 million in the third quarter of 2010. Our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $1.2 million as compared to $1.6 million in the third quarter of 2010, a decrease of approximately $0.4 million, reflecting the decrease in sales. Our margin (defined as gas operating revenues less cost of gas in rates) was virtually the same for the third quarter of 2011 as compared to the third quarter of 2010.

 

Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of September 30, 2011, we had under recovered purchased gas costs of $1.2 million recorded as a regulatory asset and over recovered purchased gas costs of $0.1 million recorded as a regulatory liability. On October 21, 2011, we filed a request with the MPSC for an increase in the PGA for our gas customers.

 

Operating Revenue Deductions

 

Total other operating expenses were virtually the same during the third quarter of 2011 as compared to the third quarter of 2010.

 

Our gas segment had a net loss of $0.4 million for the third quarter of 2011 as compared to a net loss of $0.4 million for the third quarter of 2010. These losses are not unexpected due to the seasonality of the gas segment whose heating season runs from November to March of each year.

 

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

 

Operating Revenues and bcf Sales

 

Gas retail sales were virtually the same for the nine months ended September 30, 2011 and September 30, 2010. Residential and industrial sales decreased 1.6% and 1.5%, respectively, while commercial sales increased 3.4%.

 

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During the nine months ended September 30, 2011, gas segment revenues were approximately $33.4 million as compared to $36.5 million in the nine months ended September 30, 2010, a decrease of $3.1 million. This decrease was largely driven by a lower PGA that went into effect November 2, 2010. During the nine months ended September 30, 2011, our PGA revenue was approximately $16.0 million as compared to $18.9 million during the nine months ended September 30, 2010, a decrease of approximately $2.9 million. Our margin was $0.2 million less during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010.

 

Operating Revenue Deductions

 

Total other operating expenses were $6.2 million for the nine months ended September 30, 2011, as compared to $7.1 million for the nine months ended September 30, 2010. This decrease was mainly due to a $0.4 million decrease in uncollectible accounts expense, a $0.2 million decrease in employee pension expense, a $0.2 million decrease in general labor expense, and a $0.2 million decrease in rents expense, partially offset by a $0.1 million increase in distribution expense.

 

Our gas segment had net income of $1.8 million for the nine months ended September 30, 2011, as compared to $1.6 million for the nine months ended September 30, 2010.

 

Twelve Months Ended September 30, 2011 Compared to Twelve Months Ended September 30, 2010

 

Operating Revenues and bcf Sales

 

Gas retail sales decreased 3.5% during the twelve months ended September 30, 2011, reflecting customer contraction. Residential, commercial and industrial sales decreased 4.3%, 2.0%, and 2.4%, respectively during the twelve months ended September 30, 2011.

 

During the twelve months ended September 30, 2011, gas segment revenues were approximately $47.8 million as compared to $53.0 million in the twelve months ended September 30, 2010, a decrease of $5.2 million. This decrease was largely driven by a decrease in the PGA that went into effect November 2, 2010. During the twelve months ended September 30, 2011, our PGA revenue was approximately $23.7 million as compared to $29.0 million during the twelve months ended September 30, 2010, a decrease of approximately $5.3 million. Our margin was $0.1 million more during the twelve months ended September 30, 2011 as compared to the twelve months ended September 30, 2010.

 

Operating Revenue Deductions

 

Total other operating expenses were $8.5 million for the twelve months ended September 30, 2011, as compared to $9.6 million for the twelve months ended September 30, 2010. This decrease was mainly due to a $0.5 million decrease in employee pension expense, a $0.4 million decrease in uncollectible accounts expense and a $0.2 million decrease in rents expense.

 

Our gas segment had net income of $2.8 million for the twelve months ended September 30, 2011, as compared to $2.5 million for the twelve months ended September 30, 2010.

 

Consolidated Company

 

Income Taxes

 

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended September 30, 2011:

 

 

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

 

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Consolidated provision for income taxes

 

$

15.7

 

$

11.9

 

$

28.5

 

$

26.3

 

$

32.7

 

$

29.7

 

Consolidated effective federal and state income tax rates

 

38.3

%

34.2

%

38.1

%

40.4

%

37.4

%

38.8

%

 

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See Note 12 for more information and discussion concerning our income tax provision and effective tax rates.

 

Nonoperating Items

 

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended September 30. AFUDC decreased during all three periods in 2011 as compared to the same periods in 2010 reflecting the completion of Iatan 2 and the Plum Point Energy Station in 2010.

 

 

 

Three Months Ended

 

Nine Months Ended

 

Twelve Months Ended

 

($ in millions)

 

2011

 

2010

 

2011

 

2010

 

2011

 

2010

 

Allowance for equity funds used during construction

 

$

0.1

 

$

0.8

 

$

0.1

 

$

4.5

 

$

0.2

 

$

6.6

 

Allowance for borrowed funds used during construction

 

0.1

 

0.8

 

0.2

 

5.6

 

0.2

 

7.3

 

Total AFUDC

 

$

0.2

 

$

1.6

 

$

0.3

 

$

10.1

 

$

0.4

 

$

13.9

 

 

Total interest charges on long-term and short-term debt for the periods ended September 30, 2011 are shown below. The changes in long-term debt interest for all periods presented reflect the redemption of $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022, which were redeemed on August 27, 2010, and replaced by $50 million principal amount 5.20% first mortgage bonds issued August 25, 2010. The changes in long-term debt interest for the nine-months ended and twelve-months ended periods also reflects the redemption of 6.5% first mortgage bonds on April 1, 2010 and the redemption of our 8.5% trust preferred securities on September 28, 2010, which were replaced by 4.65% first mortgage bonds issued May 28, 2010. The decreases in short-term debt interest for each period primarily reflect lower levels of borrowing.

 

 

 

Interest Charges

 

 

 

($ in millions)

 

 

 

Third

 

Third

 

 

 

9 Months

 

9 Months

 

 

 

12 Months

 

12 Months

 

 

 

 

 

Quarter

 

Quarter

 

%

 

Ended

 

Ended

 

%

 

Ended

 

Ended

 

%

 

 

 

2011

 

2010

 

Change*

 

2011

 

2010

 

Change

 

2011

 

2010

 

Change

 

Long-term debt interest

 

$

10.7

 

$

10.8

 

(1.0

)%

$

31.9

 

$

31.3

 

1.9

%

$

42.6

 

$

42.0

 

1.5

%

Short-term debt interest

 

0.0

 

0.1

 

(80.1

)

0.1

 

0.6

 

(88.5

)

0.1

 

0.7

 

(87.1

)

Trust preferred securities interest

 

 

 

 

 

2.1

 

(100.0

)

 

3.2

 

(100.0

)

Iatan 1 and 2 carrying charges*

 

 

(0.8

)

104.4

 

(2.1

)

(1.9

)

(9.4

)

(3.4

)

(2.4

)

(42.0

)

Other interest

 

0.3

 

0.2

 

29.9

 

0.7

 

0.6

 

11.4

 

0.9

 

0.8

 

11.0

 

Total interest charges

 

$

11.0

 

$

10.3

 

6.3

 

$

30.6

 

$

32.7

 

(6.5

)

$

40.2

 

$

44.3

 

(9.2

)

 


*Beginning in the second quarter of 2009, we deferred Iatan 1 carrying charges to reflect construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the environmental upgrades to Iatan 1 were included in our rate base. We began deferring Iatan 2 carrying charges in the third quarter of 2010. Deferral ended when the plant was placed in rates. Iatan 1 was placed in rates in September 2010. Iatan 2 was placed in rates June 15, 2011. See Note 3 and Rate Matters below for additional information regarding carrying charges.

 

RATE MATTERS

 

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

 

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off’s as ordered by the utility commissions. In general, a request of new rates is made on the basis of a “rate base” as of a date

 

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prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag between the time we incur costs and the time when we can start recovering the costs through rates.

 

The following table sets forth information regarding electric and gas rate increases since January 1, 2008:

 

Jurisdiction

 

Date Requested

 

Annual Increase
Granted

 

Percent Increase
Granted

 

Date Effective

 

Missouri – Electric

 

September 28, 2010

 

$

18,700,000

 

4.70

%

June 15, 2011

 

Missouri – Electric

 

October 29, 2009

 

$

46,800,000

 

13.40

%

September 10, 2010

 

Missouri – Electric

 

October 1, 2007

 

$

22,040,395

 

6.70

%

August 23, 2008

 

Kansas – Electric

 

November 4, 2009

 

$

2,800,000

 

12.4

%

July 1, 2010

 

Oklahoma – Electric

 

January 28, 2011

 

$

1,063,100

 

9.32

%

March 1, 2011

 

Oklahoma – Electric

 

March 25, 2010

 

$

1,456,979

 

15.70

%

September 1, 2010

 

Arkansas - Electric

 

August 19, 2010

 

$

2,104,321

 

19.00

%

April 13, 2011

 

Missouri – Gas

 

June 5, 2009

 

$

2,600,000

 

4.37

%

April 1, 2010

 

 

Electric Segment

 

Missouri

 

2010 Rate Case

 

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case, effective September 10, 2010. A settlement agreement among the parties to the case was reached and filed with the MPSC on May 27, 2011 reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7% effective on June 15, 2011. Due to rate design changes, this rate increase, however, will primarily impact our winter season rates which generally run from October through May. Also as part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011.

 

2009 Rate Case

 

On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request was primarily designed to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. As a result of the delay in the Iatan 2 project, however, we agreed to not seek a permanent increase in this rate case for any costs associated with the Iatan 2 unit with the exception of that portion of the Iatan common plant needed to operate Iatan 1.

 

A stipulated agreement was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station met its in-service criteria by August 15, 2010. If the in-service criteria were not met by such date, a base rate increase of $33.1 million was stipulated. The Plum Point Generating Station completed its in-service criteria testing on August 12, 2010, with an in-service date of August 13, 2010, thus new rates, providing for the full increase of $46.8 million, were effective September 10, 2010. The $46.8 million authorized increase in annual revenues includes $36.8 million in base rate revenue and $10 million in regulatory amortization. The regulatory amortization, which is treated as additional book depreciation for rate-making purposes and is reflected in the financial statements, was granted to provide additional cash flow through rates. This regulatory amortization is related to our investments in facilities and environmental upgrades completed during the recent construction cycle. As agreed in our regulatory plan, we used construction accounting for our Iatan 2 project. As noted above, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011 as a result of our

 

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2010 rate case. (See Note 3 and Note 7 of “Notes to Consolidated Financial Statements”). We also agreed to commence an eighteen year amortization of a deferred asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981 to 2008 and totaled approximately $11.1 million. We had previously recorded a regulatory asset expecting to recover these benefits from customers in future periods. We estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization of the remaining regulatory tax asset began during the third quarter of 2011.

 

2007 Rate Case

 

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went into effect August 23, 2008.

 

The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with accounting guidance for regulated activities, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified.

 

The MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

 

On October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on December 31, 2009, affirming the Commission’s Report and Order. OPC, Praxair and Explorer Pipeline filed appeals with the Western District Court of Appeals. On August 2, 2011, the Western District Court of Appeals issued a ruling affirming the Commission’s Report and Order.

 

Kansas

 

On November 4, 2009, we filed a request with the KCC for an annual increase in base rates for our Kansas electric customers in the amount of $5.2 million, or 24.6%. This request was primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. A stipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We will defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date of the rates from the next Kansas case, which was filed on June 17, 2011. This case requests a rate increase of $1.5 million, or 6.39%. The rate

 

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increase is being requested to recover the remaining costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC’s abbreviated rate case rules, which the KCC authorized in our 2009 Kansas rate case. The case includes a request to recover the Iatan and Plum Point cost deferrals over a 3 year period.

 

Oklahoma

 

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the Oklahoma Corporation Commission (OCC). The rider was designed to recover the carrying costs on our capital investment for generation, transmission and distribution assets that have been added to the system since our last Oklahoma general rate case (May 2003), as well as investments made on an ongoing basis. As requested, the operation of the CCRR would have increased our operating revenue by approximately $3 million, or approximately 33%, in Oklahoma in a series of three steps to be followed with a general rate case in 2011. On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the OCC. The first phase of the rider was put into place for Oklahoma customers for usage on and after September 1, 2010, and results in an overall annual base revenue increase of approximately $1.5 million, or 15.7%. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. On January 28, 2011 we requested the approval by the OCC of the phase 2 rates of the CRR. We requested an additional $1.1 million, which brings the total annual revenue under the OCC to approximately $2.5 million effective March 25, 2011. The CRR revenue being collected is subject to refund/true-up in the next general rate case. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers (which would replace the CRR with permanent rates) in the amount of $0.6 million, or 4.1% over the base rate and CRR revenues that are currently in effect.

 

Arkansas

 

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement included a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

 

FERC

 

On March 12, 2010, we filed GFR tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. As of June 30, 2011, we had collected $1.2 million in rates subject to refund. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. Also on May 28, 2010, we filed a notice with the FERC requesting termination of the current bundled service agreements for our wholesale customers effective July 31, 2010. On July 28, 2010, the FERC issued an order accepting and suspending the proposed terminations for a nominal period to become effective July 31, 2010, subject to refund. The FERC’s order also consolidated the GFR and termination proceedings. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

 

Gas Segment

 

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested

 

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recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. On February 24, 2010, the MPSC unanimously approved an agreement among the Office of the Public Counsel (OPC), the MPSC staff and Empire for an increase of $2.6 million. Pursuant to the Agreement, new rates went into effect on April 1, 2010.

 

COMPETITION

 

Electric Segment

 

SPP-RTO

 

SPP Regional Transmission Development:  On October 27, 2009, the Southwest Power Pool Board of Directors (SPP BOD) endorsed a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future. On April 19, 2010, SPP filed revisions to its OATT to adopt a new highway/byway cost allocation methodology which require SPP BOD approved transmission projects of 300 kV or larger to be funded by the region at 100%, transmission projects between 100 kV and 300 kV to receive 33% regional funding with individual constructing zones to pay 67% of those projects built within the zone. For projects under 100kV, the constructing zones would pay 100% of the cost. On May 17, 2010, we filed a joint protest at the FERC with other SPP members based on our disagreement with the SPP on the allocation percentages and various other issues. On June 17, 2010, the FERC unconditionally approved the new highway/byway cost allocation method. We and other members of the SPP filed a Request for Rehearing on July 19, 2010. On October 20, 2011, the FERC issued its Order on Rehearing denying our request to review various aspects of its June 17, 2010 order. Our decision to seek an appeal or petition for review of the FERC’s order to a United States Court of Appeals is pending. To date, the SPP’s BOD has approved over $1.4 billion in highway/byway projects to be constructed by 2017. As these projects are constructed, we will be allocated a share of the costs of the projects pursuant to the FERC accepted cost allocation method. We expect that these costs will be recoverable in future rates.

 

Other FERC Activity

 

On July 21, 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities). Order 1000 requires all public utility transmission providers to (among other things) facilitate non-incumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal right of first refusal (ROFR) for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation. As a transmission owning member of the SPP RTO, this could directly affect our rights to build transmission facilities within our service territory. A second key element of Order 1000 directed transmission providers to develop policy and procedures for interregional transmission coordination and interregional cost allocation. Since we are on the southeastern seam of the SPP, this policy will most likely have a direct impact on our customers, primarily through a potential reduction to our production costs as a result of greater access to lower cost power from within the SPP and across this seam and the possible reduction because of the cost sharing for new transmission projects. We will continue to participate in the SPP stakeholder processes to understand the impact of Order 1000 on our ability to construct new facilities within our service territory as well as its influence on promoting construction of transmission projects on/near our borders with our seams neighbors. Compliance filings to address the ROFR requirements are currently scheduled to be due October 11, 2012 and April 13, 2013 for interregional/seams planning and cost allocation.

 

See Note 3 in our Annual Report on Form 10-K for the year ended December 31, 2010 for additional information on Competition.

 

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LIQUIDITY AND CAPITAL RESOURCES

 

Overview.              Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. As needed, we raise funds from the debt and equity capital markets, including through our existing shelf registration statement, to fund our liquidity and capital resource needs.

 

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide the majority of the funds required for the remainder of 2011 for our budgeted capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). We believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with this cash provided by operating activities will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

 

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs, impacts of the 2011 tornado and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities for the periods shown below:

 

Summary of Cash Flows

 

 

 

Nine Months Ended September 30,

 

 

 

(in millions)

 

2011

 

2010

 

Change

 

Cash provided by/(used in):

 

 

 

 

 

 

 

Operating activities

 

$

106.7

 

$

103.7

 

$

3.0

 

Investing activities

 

(69.7

)

(81.0

)

11.3

 

Financing activities

 

(42.7

)

(13.6

)

(29.1

)

Net change in cash and cash equivalents

 

$

(5.7

)

$

9.1

 

$

(14.8

)

 

Cash flow from Operating Activities

 

We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in commodity risk management assets and liabilities and changes in the consolidated balance sheet for working capital from the beginning to the end of the period.

 

Period-over-period changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas and coal purchases and the effects of deferred fuel recoveries. The increase in natural gas prices directly impacts the cost of gas stored in inventory.

 

Nine Months Ended September 30, 2011 Compared to 2010During the nine months ended September 30, 2011, our net cash flows provided from operating activities increased $3.0 million or 2.9% from 2010. This change resulted from the following:

 

·                  Change in net income - $7.3 million.

·                  Changes in depreciation and amortization, reflecting increased regulatory amortization, plant in service and fuel deferral amortization - $12.3 million

·                  Changes in pension and other post retirement benefit costs due to the result of $27.7 million in additional pension contributions during the nine months ended September 30, 2011 compared to 2010 — $(17.2) million.

 

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·                  Increased deferrals for income taxes, reflecting positive impacts for accelerated tax depreciation and deferring taxability of the 2010 SWPA payment- $11.3 million.

·                  Changes in investment tax credits, reflecting 2010 receipt of Iatan 2 credits - $(17.6) million.

·                  Lower equity AFUDC - $4.3 million

·                  Changes in receivables due to lower unbilled revenues and income tax refunds collected - $14.0 million.

·                  Increased natural gas purchases and supplies for new and existing generation plants — $(7.9) million.

·                  Changes in accounts payable mostly due to storm related activities - $12.4 million.

·                  Changes in prepaid expenses and deferred charges mostly reflecting certain regulatory treatment of fuel charges and carrying costs - $(7.9) million.

·                  Changes in accrued interest and taxes - $(2.0) million.

·                  Changes in other liabilities, mostly reflecting customer fuel adjustments - $4.9 million.

·                  Changes reflecting the receipt of SWPA minimum flows payment in 2010 - $(26.6) million.

 

Capital Requirements and Investing Activities

 

Our net cash flows used in investing activities decreased $11.3 million during the nine months ended September 30, 2011, as compared to the same period in 2010.

 

Our capital expenditures incurred totaled approximately $76.5 million during the nine months ended September 30, 2011, compared to $78.9 million for the nine months ended September 30, 2010. The decrease was primarily the result of a decrease in new generation construction partially offset by increased storm expense due to the May 2011 tornado.

 

A breakdown of the capital expenditures for the nine months ended September 30, 2011 and 2010 is as follows:

 

 

 

 

 

 

 

Capital Expenditures

 

 

 

 

 

(in millions)

 

2011

 

2010

 

Distribution and transmission system additions

 

$

33.0

 

$

25.1

 

New Generation — Plum Point Energy Station

 

 

6.6

 

New Generation — Iatan 2

 

3.8

 

38.3

 

Storms

 

15.1

 

0.1

 

Additions and replacements — electric plant

 

8.9

 

5.0

 

Gas segment additions and replacements

 

2.7

 

1.4

 

Transportation

 

2.8

 

1.0

 

Other (including retirements and salvage -net) (1)

 

7.2

 

(0.9

)

Subtotal

 

73.5

 

76.6

 

Non-regulated capital expenditures (primarily fiber optics)

 

3.0

 

2.3

 

Subtotal capital expenditures incurred (2)

 

76.5

 

78.9

 

Adjusted for capital expenditures payable (3)

 

(6.7

)

2.2

 

Total cash outlay

 

$

69.8

 

$

81.1

 

 


(1) Other includes equity AFUDC of $(0.2) million and $(4.5) million for 2011 and 2010, respectively.

(2) Expenditures incurred represent the total cost for work completed for the projects during the reporting period. Discussion of capital expenditures throughout this 10-Q is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

(3) The amount of expenditures paid/(unpaid) at the end of the reporting period to adjust to actual cash outlay reflected in the Investing Activities section of the Statement of Cash Flows.

 

100% of our cash requirements for capital expenditures during the nine months ended September 30, 2011 were satisfied internally from operations (funds provided by operating activities less dividends paid). We estimate that our capital expenditures (excluding AFUDC) for the remainder of 2011 will be approximately $28.3 million and for 2012 through 2016 will be as follows:

 

 

 

2012

 

2013

 

2014

 

2015

 

2016

 

Estimated Capital Expenditures

 

$

147.2

(1)

$

194.8

(1)

$

176.9

 

$

285.0

 

$

137.4

 

 


(1) 2012 and 2013 estimates have been reduced by $7.0 million and $1.0 million, respectively, due to expected insurance proceeds related to substation damage from the tornado.

 

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The largest expenditures for the years 2012-2014 include environmental upgrades at Asbury and the year 2015 includes the possible purchase, pursuant to our option, of an undivided ownership interest in 50 megawatts of capacity at the Plum Point Energy Station. No decision has yet been made to exercise this option.

 

We estimate that internally generated funds will provide 100% of the funds required for our annual 2011 capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance additional amounts, if needed beyond those provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. For further information see Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

 

Financing Activities

 

Our net cash flows used in financing activities increased $29.1 million during the first nine months of 2011 as compared to the same period in 2010, primarily due to a decrease in proceeds (net of repayments of long-term debt) received from new issuances of long term debt and equity in 2011 as compared to 2010.

 

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250 million of such securities in the form of first mortgage bonds. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

 

On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated our unsecured $150 million revolving credit facility. This agreement extended the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013.

 

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios would result in an event of default under the credit facility and would prohibit us from borrowing funds thereunder. As of September 30, 2011, we are in compliance with these ratios. Our total indebtedness is 50.5% of our total capitalization as of September 30, 2011 and our EBITDA is 5.25 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at September 30, 2011. However, $4.0 million was used to back up our outstanding commercial paper.

 

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended September 30, 2011, would permit us to issue approximately $494.1 million of new first mortgage bonds based on this test with an assumed interest rate of 6.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At September 30, 2011, we had retired bonds and net property additions which

 

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Would enable the issuance of at least $664.4 million principal amount of bonds if the annual interest requirements are met. As of September 30, 2011, we are in compliance with all restrictive covenants of the EDE Mortgage.

 

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of September 30, 2011, this test would allow us to issue approximately $9.8 million principal amount of new first mortgage bonds.

 

Currently, our corporate credit ratings and the ratings for our securities are as follows:

 

 

 

Fitch

 

Moody’s

 

Standard & Poor’s

 

Corporate Credit Rating

 

n/r*

 

Baa2

 

BBB-

 

First Mortgage Bonds

 

BBB+

 

A3

 

BBB+

 

Senior Notes

 

BBB

 

Baa2

 

BBB-

 

Commercial Paper

 

F3

 

P-2

 

A-3

 

Outlook

 

Stable

 

Stable

 

Stable

 

 


*Not rated

 

On March 10, 2011, Standard & Poor’s revised its outlook on us from stable to positive and affirmed the corporate credit rating at BBB-, citing greater-than-expected improvement in our financial condition from the winding down of our heavy construction program, sale of $120 million of common stock in 2010, rate increases and enhanced cost recovery via new rate riders. On May 27, 2011 Standard & Poor’s revised our rating outlook to stable from positive after the May 22, 2011 tornado. On May 14, 2010, Moody’s upgraded our First Mortgage Bonds from Baa1 to A3 and upgraded its outlook from negative to stable. On April 14, 2011, and again on May 26, 2011 after the May 22, 2011 tornado, Moody’s reaffirmed all of our other ratings. On April 1, 2010, Fitch revised their rating outlook on us to stable. On March 24, 2011, Fitch revised our commercial paper rating from F2 to F3 and reaffirmed our other ratings. The rating action was not based on a specific action or event on our part, but reflected their traditional linkage of long-term and short-term Issuer Default Ratings.

 

A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

 

CONTRACTUAL OBLIGATIONS

 

Our contractual obligations have not significantly changed at September 30, 2011, compared to December 31, 2010 with the exception of our estimate for pension and post retirement benefits funding. Upon completion of the final actuarial calculations, our estimate for 2011 pension benefit funding was lowered by $1.5 million, from $21.4 million to $19.9 million, and post retirement benefit obligation funding estimates were reduced by $2.2 million, from $5.7 million to $3.5 million.

 

DIVIDENDS

 

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). In response to the

 

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expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. Based on current conditions and knowledge, at the October 2011 meeting, the Board of Directors reaffirmed their expectation to re-establish the dividend at an approximate level of $0.25 per quarter beginning with the first quarter of 2012.

 

Our diluted earnings per share were $1.11 for the nine months ended September 30, 2011 and were $1.17 and $1.18 for the years ended December 31, 2010 and 2009, respectively. Dividends paid per share were $0.64 for the nine months ended September 30, 2011 and $1.28 for each of the years ended December 31, 2010 and 2009.

 

Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds “properly included in capital account”. There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

 

In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million, as described above. On June 9, 2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

 

OFF-BALANCE SHEET ARRANGEMENTS

 

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.

 

CRITICAL ACCOUNTING POLICIES

 

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2010 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended September 30, 2011.

 

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RECENTLY ISSUED ACCOUNTING STANDARDS

 

See Note 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

 

Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

 

Market Risk and Hedging Activities.

 

Prices in the wholesale power markets often are extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

 

We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

 

Commodity Price Risk.

 

We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

 

We satisfied 62.3% of our 2010 generation fuel supply need through coal. Approximately 92% of our 2010 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2014. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2011, 65% for 2012, 61% for 2013 and 31% for our 2014 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

 

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of October 21, 2011, 44%, or 0.3 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2011 is hedged.

 

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at September 30, 2011, our natural gas cost would increase by approximately $0.9 million based on our September 30, 2011, total hedged positions for the next twelve months. However, this is probable of recovery through fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

 

We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of September 30, 2011, we have 1.5 million Dths in storage on the three pipelines that serve our customers. This represents 76% of our storage capacity.

 

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The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2011 (in thousands). However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

 

Season

 

Minimum %
Hedged

 

Dth Hedged
Financial

 

Dth Hedged
Physical

 

Dth in Storage

 

Actual % Hedged

 

Current

 

50%

 

790,000

 

222,200

 

1,532,769

 

70

%

Second

 

Up to 50%

 

310,000

 

 

 

7

%

Third

 

Up to 20%

 

 

 

 

%

Total

 

 

 

1,100,000

 

222,200

 

1,532,769

 

 

 

 

Credit Risk.

 

In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at September 30, 2011 and December 31, 2010. There were no margin deposit liabilities at these dates.

 

 

 

 

 

 

 

(in millions)

 

September 30, 2011

 

December 31, 2010

 

Margin deposit assets

 

$

4.8

 

$

3.9

 

 

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at September 30, 2011, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

 

(in millions)

 

 

 

Net unrealized mark-to-market losses for physical forward natural gas contracts

 

$

11.0

 

Net unrealized mark-to-market losses for financial natural gas contracts

 

6.4

 

Net credit exposure

 

$

17.4

 

 

The $6.4 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of unrealized losses that our counterparties are exposed to Empire for. We are holding no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold in our agreements. As noted above, as of September 30, 2011, we have $4.8 million on deposit for NYMEX contract exposure to Empire, of which $4.7 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their September 30, 2011, levels, we would be required to post an additional $2.8 million in collateral. If these prices increased 25%, our collateral requirement would decrease $2.8 million. Our other counterparties would not be required to post collateral with Empire.

 

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We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

 

Interest Rate Risk.

 

We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

 

If market interest rates average 1% more in 2011 than in 2010, our interest expense would increase, and income before taxes would decrease by less than $0.5 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2010. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

 

Item 4.   Controls and Procedures

 

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2011.

 

There have been no changes in our internal control over financial reporting that occurred during the third quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II.  OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

Platte County Levee Lawsuit

 

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are 12% owners. This matter was set for trial beginning November 7, 2011, but has now been rescheduled for March 14, 2012. We are unable to predict the outcome of the law suit or estimate the amount of damages, if any.

 

Item 1A.  Risk Factors.

 

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010.

 

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Item 5.  Other Information.

 

For the twelve months ended September 30, 2011, our ratio of earnings to fixed charges was 2.89x.  See Exhibit (12) hereto.

 

Item 6.  Exhibits.

 

(a)           Exhibits.

 

(12) Computation of Ratio of Earnings to Fixed Charges.

 

(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

 

(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

 

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2011, filed with the SEC on November 8, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, nine and twelve month periods ended September 30, 2011 and 2010, (ii) the Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, (iii) the Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2011 and 2010, and (iv) Notes to Consolidated Financial Statements.**

 


*This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

 

**Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be filed by the Company for purposes of Section 18 or any other provision of the Exchange Act of 1934, as amended.

 

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Table of Contents

 

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.

 

 

THE EMPIRE DISTRICT ELECTRIC COMPANY

 

 

Registrant

 

 

 

 

 

 

 

By

/s/ Laurie A. Delano

 

 

Laurie A. Delano

 

 

Vice President — Finance and Chief Financial Officer

 

 

 

 

 

 

 

By

/s/ Robert W. Sager

 

 

Robert W. Sager

 

 

Controller, Assistant Secretary and Assistant Treasurer

 

 

 

November 7, 2011

 

 

 

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