Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Oct. 31, 2013 | |
Document and Entity Information | ' | ' |
Entity Registrant Name | 'EMPIRE DISTRICT ELECTRIC CO | ' |
Entity Central Index Key | '0000032689 | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Amendment Flag | 'false | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Current Reporting Status | 'Yes | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 42,968,104 |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Operating revenues: | ' | ' | ' | ' | ' | ' |
Electric | $150,370 | $152,730 | $406,158 | $396,546 | $520,265 | $514,515 |
Gas | 4,952 | 4,999 | 33,222 | 26,486 | 46,585 | 39,571 |
Other | 2,164 | 1,473 | 5,892 | 4,945 | 7,542 | 6,657 |
Total operating revenues | 157,486 | 159,202 | 445,272 | 427,977 | 574,392 | 560,743 |
Operating revenue deductions: | ' | ' | ' | ' | ' | ' |
Fuel and purchased power | 44,864 | 48,036 | 132,179 | 138,792 | 172,283 | 183,288 |
Cost of natural gas sold and transported | 1,191 | 1,251 | 16,229 | 11,601 | 23,262 | 18,384 |
Regulated operating expenses | 26,100 | 24,038 | 79,884 | 70,230 | 104,024 | 93,572 |
Other operating expenses | 805 | 776 | 2,470 | 2,145 | 3,056 | 2,763 |
Maintenance and repairs | 10,674 | 10,972 | 29,764 | 30,893 | 39,315 | 42,261 |
Loss on plant disallowance | ' | ' | 2,409 | ' | 2,409 | ' |
Depreciation and amortization | 17,735 | 15,108 | 51,471 | 45,111 | 66,807 | 59,669 |
Provision for income taxes | 14,197 | 15,428 | 28,693 | 28,185 | 34,603 | 33,727 |
Other taxes | 9,024 | 8,311 | 26,309 | 24,166 | 33,402 | 30,722 |
Total operating revenue deductions | 124,590 | 123,920 | 369,408 | 351,123 | 479,161 | 464,386 |
Operating income | 32,896 | 35,282 | 75,864 | 76,854 | 95,231 | 96,357 |
Other income and (deductions): | ' | ' | ' | ' | ' | ' |
Allowance for equity funds used during construction | 1,128 | 292 | 2,521 | 395 | 3,273 | 537 |
Interest income | 5 | 265 | 522 | 568 | 926 | 1,055 |
Benefit/(provision) for other income taxes | 47 | -49 | 12 | -251 | 201 | -531 |
Other - non-operating expense, net | -333 | -274 | -912 | -703 | -2,119 | -1,005 |
Total other income and (deductions) | 847 | 234 | 2,143 | 9 | 2,281 | 56 |
Interest charges: | ' | ' | ' | ' | ' | ' |
Long-term debt | 10,102 | 9,950 | 30,243 | 30,242 | 40,194 | 40,896 |
Short-term debt | ' | 16 | 59 | 175 | 71 | 192 |
Allowance for borrowed funds used during construction | -606 | -243 | -1,383 | -410 | -1,754 | -470 |
Other | 251 | 251 | 805 | 802 | 1,091 | 1,050 |
Total interest charges | 9,747 | 9,974 | 29,724 | 30,809 | 39,602 | 41,668 |
Net income | $23,996 | $25,542 | $48,283 | $46,054 | $57,910 | $54,745 |
Weighted average number of common shares outstanding - basic (in shares) | 42,869 | 42,345 | 42,715 | 42,197 | 42,644 | 42,141 |
Weighted average number of common shares outstanding - diluted (in shares) | 42,898 | 42,374 | 42,737 | 42,220 | 42,665 | 42,163 |
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share) | $0.56 | $0.60 | $1.13 | $1.09 | $1.36 | $1.30 |
Dividends declared per share of common stock (in dollars per share) | $0.25 | $0.25 | $0.75 | $0.75 | $1 | $0.75 |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Plant and property, at original cost: | ' | ' |
Electric | $2,207,736 | $2,176,188 |
Gas | 72,127 | 69,851 |
Other | 39,095 | 37,983 |
Construction work in progress | 129,219 | 56,347 |
Total plant and property, Gross | 2,448,177 | 2,340,369 |
Accumulated depreciation and amortization | 718,492 | 682,737 |
Total plant and property, Net | 1,729,685 | 1,657,632 |
Current assets: | ' | ' |
Cash and cash equivalents | 16,383 | 3,375 |
Restricted cash | 1,773 | 4,357 |
Accounts receivable - trade, net of allowance $988 and $1,388, respectively | 51,485 | 38,874 |
Accrued unbilled revenues | 16,335 | 23,254 |
Accounts receivable - other | 14,900 | 13,277 |
Fuel, materials and supplies | 53,050 | 61,870 |
Prepaid expenses and other | 20,360 | 21,806 |
Unrealized gain in fair value of derivative contracts | 333 | 96 |
Regulatory assets | 6,398 | 6,377 |
Total current assets | 181,017 | 173,286 |
Noncurrent assets and deferred charges: | ' | ' |
Regulatory assets | 231,950 | 243,958 |
Goodwill | 39,492 | 39,492 |
Unamortized debt issuance costs | 8,722 | 7,606 |
Unrealized gain in fair value of derivative contracts | ' | 191 |
Other | 4,942 | 4,204 |
Total noncurrent assets and deferred charges | 285,106 | 295,451 |
Total Assets | 2,195,808 | 2,126,369 |
Capitalization and Liabilities | ' | ' |
Common stock, $1 par value, 42,939,207 and 42,484,363 shares issued and outstanding, respectively | 42,939 | 42,484 |
Capital in excess of par value | 637,003 | 628,199 |
Retained earnings | 63,350 | 47,115 |
Total common stockholders' equity | 743,292 | 717,798 |
Long-term debt (net of current portion): | ' | ' |
Obligations under capital lease | 4,237 | 4,441 |
First mortgage bonds and secured debt | 637,569 | 487,541 |
Unsecured debt | 101,680 | 199,644 |
Total long-term debt | 743,486 | 691,626 |
Total long-term debt and common stockholders' equity | 1,486,778 | 1,409,424 |
Current liabilities: | ' | ' |
Accounts payable and accrued liabilities | 55,281 | 66,559 |
Current maturities of long-term debt | 327 | 714 |
Short-term debt | ' | 24,000 |
Regulatory liabilities | 4,295 | 6,303 |
Customer deposits | 12,518 | 12,001 |
Interest accrued | 13,766 | 5,902 |
Other current liabilities | 1,894 | ' |
Unrealized loss in fair value of derivative contracts | 3,078 | 3,403 |
Taxes accrued | 16,781 | 2,992 |
Total current liabilities | 107,940 | 121,874 |
Commitments and contingencies (Note 7) | ' | ' |
Noncurrent liabilities and deferred credits: | ' | ' |
Regulatory liabilities | 134,531 | 131,055 |
Deferred income taxes | 320,042 | 301,967 |
Unamortized investment tax credits | 18,708 | 18,897 |
Pension and other postretirement benefit obligations | 107,299 | 120,808 |
Unrealized loss in fair value of derivative contracts | 3,089 | 3,819 |
Other | 17,421 | 18,525 |
Total noncurrent liabilities and deferred credits | 601,090 | 595,071 |
Total Capitalization and Liabilities | $2,195,808 | $2,126,369 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, except Share data, unless otherwise specified | ||
CONSOLIDATED BALANCE SHEETS | ' | ' |
Accounts receivable - trade, allowance (in dollars) | $988 | $1,388 |
Common stock, par value (in dollars per share) | $1 | $1 |
Common stock, shares issued | 42,939,207 | 42,484,363 |
Common stock, shares outstanding | 42,939,207 | 42,484,363 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Operating activities: | ' | ' |
Net income | $48,283 | $46,054 |
Adjustments to reconcile net income to cash flows from operating activities: | ' | ' |
Depreciation and amortization including regulatory items | 53,048 | 55,043 |
Pension and other postretirement benefit costs, net of contributions | -5,458 | 1,486 |
Deferred income taxes and unamortized investment tax credit, net | 21,579 | 26,906 |
Allowance for equity funds used during construction | -2,521 | -395 |
Stock compensation expense | 2,334 | 1,893 |
Loss on plant disallowance | 2,409 | ' |
Regulatory reversal of gain on sale of assets | 1,236 | ' |
Non-cash loss on derivatives | 169 | 3,074 |
Other | ' | -16 |
Cash flows impacted by changes in: | ' | ' |
Accounts receivable and accrued unbilled revenues | -5,877 | 496 |
Fuel, materials and supplies | 6,652 | 1,300 |
Prepaid expenses, other current assets and deferred charges | 533 | -8,953 |
Accounts payable and accrued liabilities | -21,708 | -14,437 |
Asset retirement obligations | -363 | ' |
Interest, taxes accrued and customer deposits | 22,170 | 19,614 |
Other liabilities and other deferred credits | -4,845 | 4,001 |
Net cash provided by operating activities | 117,641 | 136,066 |
Investing activities: | ' | ' |
Capital expenditures - regulated | -107,074 | -99,036 |
Capital expenditures and other investments - non-regulated | -1,290 | -2,349 |
Decrease in restricted cash | 2,585 | ' |
Net cash used in investing activities | -105,779 | -101,385 |
Financing activities: | ' | ' |
Proceeds from first mortgage bonds, net | 150,000 | 88,000 |
Long-term debt issuance costs | -1,607 | -1,066 |
Proceeds from issuance of common stock, net of issuance costs | 7,391 | 6,522 |
Repayment of first mortgage bonds | ' | -88,029 |
Net short-term debt repayments | -24,000 | -10,000 |
Redemption of senior notes | -98,000 | ' |
Dividends | -32,048 | -31,665 |
Other | -590 | -680 |
Net cash provided by / (used in) financing activities | 1,146 | -36,918 |
Net increase (decrease) in cash and cash equivalents | 13,008 | -2,237 |
Cash and cash equivalents at beginning of period | 3,375 | 5,408 |
Cash and cash equivalents at end of period | $16,383 | $3,171 |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2013 | |
Summary of Significant Accounting Policies | ' |
Summary of Significant Accounting Policies | ' |
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 customers in 48 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, 2012. | |
The information furnished reflects all 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, 2012. |
Recently_Issued_and_Proposed_A
Recently Issued and Proposed Accounting Standards | 9 Months Ended |
Sep. 30, 2013 | |
Recently Issued and Proposed Accounting Standards | ' |
Recently Issued and Proposed Accounting Standards | ' |
Note 2 - Recently Issued and Proposed Accounting Standards | |
Balance Sheet Offsetting: The FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet. Under the revised guidance, an entity is required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement. This standard was effective for annual periods beginning after January 1, 2013. We implemented this standard in the first quarter of 2013 and it did not have a material impact on our results of operations, financial position or liquidity. |
Regulatory_Matters
Regulatory Matters | 9 Months Ended | |||||||
Sep. 30, 2013 | ||||||||
Regulatory Matters | ' | |||||||
Regulatory Matters | ' | |||||||
Note 3— Regulatory Matters | ||||||||
On February 27, 2013, the MPSC approved a joint settlement agreement for our 2012 Missouri rate case. The agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. The agreement also included an increase in depreciation rates, recovery of deferred tornado costs over the next ten years and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the agreement included a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014. | ||||||||
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, 2013 | December 31, 2012 | |||||||
Regulatory Assets: | ||||||||
Current: | ||||||||
Under recovered fuel costs(1) | $ | 302 | $ | 2,885 | ||||
Current portion of long-term regulatory assets(1) | 6,096 | 3,492 | ||||||
Regulatory assets, current(1) | 6,398 | 6,377 | ||||||
Long-term: | ||||||||
Pension and other postretirement benefits(2) | 129,110 | 136,480 | ||||||
Income taxes | 48,418 | 48,759 | ||||||
Deferred construction accounting costs | 16,385 | 16,717 | ||||||
Unamortized loss on reacquired debt | 11,246 | 12,142 | ||||||
Unsettled derivative losses — electric segment | 5,613 | 6,557 | ||||||
System reliability — vegetation management | 7,783 | 9,002 | ||||||
Storm costs(3) | 5,084 | 4,828 | ||||||
Asset retirement obligation | 4,616 | 4,430 | ||||||
Customer programs | 4,785 | 4,356 | ||||||
Unamortized loss on interest rate derivative | 1,001 | 1,147 | ||||||
Deferred operating and maintenance expense | 1,863 | 2,049 | ||||||
Under recovered fuel costs | 1,212 | 314 | ||||||
Current portion of long-term regulatory assets | (6,096 | ) | (3,492 | ) | ||||
Other | 930 | 669 | ||||||
Regulatory assets, long-term | 231,950 | 243,958 | ||||||
Total Regulatory Assets | $ | 238,348 | $ | 250,335 | ||||
September 30, 2013 | December 31, 2012 | |||||||
Regulatory Liabilities: | ||||||||
Current: | ||||||||
Over recovered fuel costs(1) | $ | 556 | $ | 3,214 | ||||
Current portion of long-term regulatory liabilities(1) | 3,739 | 3,089 | ||||||
Regulatory liabilities, current(1) | 4,295 | 6,303 | ||||||
Long-term: | ||||||||
Costs of removal | 92,058 | 83,368 | ||||||
SWPA payment for Ozark Beach lost generation | 20,105 | 22,242 | ||||||
Income taxes | 11,736 | 11,972 | ||||||
Deferred construction accounting costs — fuel | 8,047 | 8,156 | ||||||
Unamortized gain on interest rate derivative | 3,414 | 3,541 | ||||||
Pension and other postretirement benefits(4) | 2,377 | 2,007 | ||||||
Over recovered fuel costs | 533 | 2,858 | ||||||
Current portion of long-term regulatory liabilities(1) | (3,739 | ) | (3,089 | ) | ||||
Regulatory liabilities, long-term | 134,531 | 131,055 | ||||||
Total Regulatory Liabilities | $ | 138,826 | $ | 137,358 | ||||
(1) Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates. | ||||||||
(2) Includes the effect of costs incurred that are more or less than those allowed in rates for Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs. | ||||||||
(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado. | ||||||||
(4) 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. |
Risk_Management_and_Derivative
Risk Management and Derivative Financial Instruments | 9 Months Ended | |||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||
Risk Management and Derivative Financial Instruments | ' | |||||||||||||||||||||
Risk Management and Derivative Financial Instruments | ' | |||||||||||||||||||||
Note 4— Risk Management and Derivative Financial Instruments | ||||||||||||||||||||||
We engage in hedging activities in an effort to minimize our risk from volatile 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 with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (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 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, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands): | ||||||||||||||||||||||
ASSET DERIVATIVES | September 30, | December 31, | ||||||||||||||||||||
Non-designated hedging | 2013 | 2012 | ||||||||||||||||||||
instruments due to regulatory accounting | Balance Sheet Classification | Fair Value | Fair Value | |||||||||||||||||||
Natural gas contracts, gas segment | Current assets | $ | 11 | $ | 3 | |||||||||||||||||
Non-current assets and deferred charges - other | — | 17 | ||||||||||||||||||||
Natural gas contracts, electric segment | Current assets | 322 | 93 | |||||||||||||||||||
Non-current assets and deferred charges | — | 174 | ||||||||||||||||||||
Total derivatives assets | $ | 333 | $ | 287 | ||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||||
LIABILITY DERIVATIVES | 2013 | 2012 | ||||||||||||||||||||
Non-designated as hedging instruments | ||||||||||||||||||||||
due to regulatory accounting | ||||||||||||||||||||||
Natural gas contracts, gas segment | Current liabilities | $ | 22 | $ | 104 | |||||||||||||||||
Non-current liabilities and deferred credits | — | — | ||||||||||||||||||||
Natural gas contracts, electric segment | Current liabilities | 3,056 | 3,299 | |||||||||||||||||||
Non-current liabilities and deferred credits | 3,089 | 3,819 | ||||||||||||||||||||
Total derivatives liabilities | $ | 6,167 | $ | 7,222 | ||||||||||||||||||
Electric | ||||||||||||||||||||||
At September 30, 2013, approximately $3.1 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months. | ||||||||||||||||||||||
The following tables 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 | Balance Sheet | |||||||||||||||||||||
Instruments - Due to | Classification of | Amount of Gain / (Loss) Recognized on Balance Sheet | ||||||||||||||||||||
Regulatory Accounting | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Electric Segment | Derivatives | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Regulatory (assets)/liabilities | $ | (1,346 | ) | $ | 1,776 | $ | (1,778 | ) | $ | (52 | ) | $ | (4,174 | ) | $ | (4,259 | ) | ||||
Total Electric Segment | $ | (1,346 | ) | $ | 1,776 | $ | (1,778 | ) | $ | (52 | ) | $ | (4,174 | ) | $ | (4,259 | ) | |||||
Statement of | ||||||||||||||||||||||
Non-Designated Hedging | Income | |||||||||||||||||||||
Instruments - Due to | Classification of | Amount of Gain / (Loss) Recognized in Income on Derivative | ||||||||||||||||||||
Regulatory Accounting | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Electric Segment | Derivatives | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Fuel and purchased power expense | $ | (1,951 | ) | $ | (2,683 | ) | $ | (2,472 | ) | $ | (2,624 | ) | $ | (3,833 | ) | $ | (3,498 | ) | |||
Total Electric Segment | $ | (1,951 | ) | $ | (2,683 | ) | $ | (2,472 | ) | $ | (2,624 | ) | $ | (3,833 | ) | $ | (3,498 | ) | ||||
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 September 30, 2013, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 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 2013 | 14 | % | 420,000 | 410,000 | $ | 5.62 | ||||||||||||||||
2014 | 49 | % | 460,000 | 4,640,000 | $ | 4.57 | ||||||||||||||||
2015 | 41 | % | — | 4,010,000 | $ | 4.58 | ||||||||||||||||
2016 | 21 | % | — | 2,100,000 | $ | 4.42 | ||||||||||||||||
2017 | 10 | % | — | 1,050,000 | $ | 4.43 | ||||||||||||||||
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. These guidelines do not reflect any changes that might occur as a result of the implementation of the SPP Day-Ahead Market in 2014. | ||||||||||||||||||||||
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 progresses, gas is withdrawn from storage to serve our customers. As of September 30, 2013, we had 1.7 million Dths in storage on the three pipelines that serve our customers. This represents 83% 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, 2013 (in thousands). | ||||||||||||||||||||||
Season | Minimum % | Dth Hedged | Dth Hedged | Dth in Storage | Actual % Hedged | |||||||||||||||||
Hedged | Financial | Physical | ||||||||||||||||||||
Current | 50% | 220,000 | 127,721 | 1,671,231 | 63 | % | ||||||||||||||||
Second | Up to 50% | — | — | — | ||||||||||||||||||
Third | Up to 20% | — | — | — | ||||||||||||||||||
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). | ||||||||||||||||||||||
Balance Sheet | ||||||||||||||||||||||
Non-Designated Hedging | Classification of | Amount of Gain / (Loss) Recognized on Balance Sheet | ||||||||||||||||||||
Instruments Due to Regulatory | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Accounting - Gas Segment | Derivative | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Regulatory (assets)/liabilities | $ | (27 | ) | $ | 106 | $ | (45 | ) | $ | (384 | ) | $ | (122 | ) | $ | (1,458 | ) | ||||
Total - Gas Segment | $ | (27 | ) | $ | 106 | $ | (45 | ) | $ | (384 | ) | $ | (122 | ) | $ | (1,458 | ) | |||||
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, 2013 is $0.4 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, 2013, we would have been required to post $0.4 million of collateral with one of our counterparties. 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, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates. | ||||||||||||||||||||||
(in millions) | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||
Margin deposit assets | $ | 5.8 | $ | 4.2 | ||||||||||||||||||
Offsetting of derivative assets and liabilities | ||||||||||||||||||||||
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master trading and netting agreement level by the counterparty. | ||||||||||||||||||||||
As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the periods ended September 30, 2013 and December 31, 2012, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts. |
Fair_Value_Measurements
Fair Value Measurements | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Fair Value Measurements | ' | |||||||||||||
Fair Value Measurements | ' | |||||||||||||
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. | ||||||||||||||
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 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, 2013 and December 31, 2012. | ||||||||||||||
Fair Value Measurements at Reporting Date Using | ||||||||||||||
($ in 000’s) | Assets/(Liabilities) | Quoted Prices in | Significant | Significant | ||||||||||
Description | at Fair Value | Active Markets for | Other | Unobservable | ||||||||||
Identical Liabilities | Observable | Inputs | ||||||||||||
(Level 1) | Inputs | (Level 3) | ||||||||||||
(Level 2) | ||||||||||||||
September 30, 2013 | ||||||||||||||
Derivative assets | $ | 333 | $ | 333 | $ | — | $ | — | ||||||
Derivative liabilities | $ | (6,167 | ) | $ | (6,167 | ) | $ | — | $ | — | ||||
December 31, 2012 | ||||||||||||||
Derivative assets | $ | 287 | $ | 287 | $ | — | $ | — | ||||||
Derivative liabilities | $ | (7,222 | ) | $ | (7,222 | ) | $ | — | $ | — | ||||
Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The carrying amount of our total long-term debt exclusive of capital leases at September 30, 2013, was $739.3 million as compared to $687.6 million at December 31, 2012. The fair market value at September 30, 2013 was approximately $716.5 million as compared to $747.2 million at December 31, 2012. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include 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, 2013 or that will be realizable in the future. |
Financing
Financing | 9 Months Ended |
Sep. 30, 2013 | |
Financing | ' |
Financing | ' |
Note 6— Financing | |
On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The bonds have not been registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage. 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. | |
We used a portion of the proceeds from the sale of these bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. The remaining proceeds were used for general corporate purposes. | |
We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. 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 will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of September 30, 2013, we are in compliance with these ratios. Our total indebtedness is 50.0% of our total capitalization as of September 30, 2013 and our EBITDA is 5.0 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 and no outstanding commercial paper at September 30, 2013. |
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended | |||||||
Sep. 30, 2013 | ||||||||
Commitments and Contingencies | ' | |||||||
Commitments and Contingencies | ' | |||||||
Note 7— Commitments and Contingencies | ||||||||
Legal Proceedings | ||||||||
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. | ||||||||
A lawsuit was filed in Jasper County Circuit Court (the Court) against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers were seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. We filed a motion asking the Court to dismiss the case. On October 1, 2013, the Missouri Supreme Court denied the plaintiff’s appeal affirming the Court’s dismissal with prejudice which finalizes the case. | ||||||||
Coal, Natural Gas and Transportation Contracts | ||||||||
The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2013 (in millions). | ||||||||
Firm physical gas and | Coal and coal | |||||||
transportation contracts | transportation contracts | |||||||
October 1, 2013 through December 31, 2013 | $ | 10.6 | $ | 5.7 | ||||
January 1, 2014 through December 31, 2015 | 30.5 | 34.3 | ||||||
January 1, 2016 through December 31, 2017 | 22.2 | 22.6 | ||||||
January 1, 2018 and beyond | 8.3 | 22.6 | ||||||
Included in the table above is an agreement with Southern Star Central Pipeline, Inc., effective April 2011, to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years, expiring April 2016. The reservation charge for this storage capacity is approximately $1.1 million annually. | ||||||||
In addition to the above, subsequent to September 30, 2013, we extended our transportation contract with ANR Pipeline Company, expiring on March 31, 2014, for a period of ten years, expiring on March 31, 2024. Annual costs under this contract are expected to be approximately $0.5 million, depending on volume. | ||||||||
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 as of September 30, 2013, 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. | ||||||||
The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit’s capacity. We also have a long-term (30 year) agreement for the purchase of capacity from Plum Point. We began receiving purchased power under this agreement 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. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the MPSC on July 1, 2013. While it is not currently our intention to exercise this option in 2015, we will continue to evaluate this purchase option through the exercise date as well as explore other options with the purchase power agreement holder, Plum Point Energy Associates (PPEA), related to the timing of this option. Commitments under this agreement are approximately $299.6 million through August 31, 2039, the end date of the agreement. | ||||||||
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. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost. We also have a 20-year contract, which began on December 15, 2005, 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. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost. Although these agreements are considered operating leases under Generally Accepted Accounting Principles (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. We do not own any portion of these windfarms. | ||||||||
New Construction | ||||||||
On July 9, 2013, we signed a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion will include the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by Kansas Department of Health and Environment on July 11, 2013. See “Environmental Matters” below for additional information about this project and associated compliance measures. | ||||||||
On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the Mercury and Air Toxics Standard (MATS). See “Environmental Matters” below for more information and for project costs. | ||||||||
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 agreements 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. | ||||||||
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 | ||||||||
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, nitrogen oxides (NOx) and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO2). | ||||||||
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. As stated above, on July 11, 2013, we received the Air Emission Source Construction Permit necessary to begin construction on the Riverton 12 Combined Cycle Conversion project. | ||||||||
Compliance Plan | ||||||||
In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan). While the Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) that was set to take effect on January 1, 2012 was stayed in late December 2011 then vacated in August 2012 by the District of Columbia Circuit Court of Appeals, the Mercury Air Toxics Standard (MATS) was signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS requires compliance by April 2015 (with flexibility for extensions for reliability reasons). Our Compliance Plan largely follows the preferred plan presented in our 2010 Integrated Resource Plan (IRP) and is further supported by our recent IRP filing. As described above under New Construction, we have begun the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through September 30, 2013 were $43.2 million for 2013 and $73.5 million for the project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, a steam turbine currently rated at 14 megawatts that is used for peaking purposes. | ||||||||
In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal to operating completely on natural gas. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 or 8 for start-up, will be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our updated five-year capital expenditure plan disclosed in our 2013 third quarter 10-Q. Construction costs, consisting of pre-engineering and site preparation activities thus far, through September 30, 2013 were $5.3 million for 2013 and $5.9 million for the project to date, excluding AFUDC. | ||||||||
SO2 Emissions | ||||||||
The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR). But, as discussed above, CSAPR was subsequently vacated, and CAIR will remain in effect until the EPA develops a valid replacement. | ||||||||
On October 5, 2012, the Department of Justice, on behalf of the EPA, requested that the Court of Appeals grant a request for a re-hearing of CSAPR. On January 24, 2013, the request was denied by the Court of Appeals and on March 29, 2013, the EPA petitioned the United States Supreme Court (the Supreme Court) to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision with a hearing date set for December 6, 2013 and a decision expected by June 30, 2014. In the meantime, both the Title IV Acid Rain Program and CAIR will remain in effect. | ||||||||
The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this could also affect SO2 emissions at our facilities. 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 entitles 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 2012, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. We estimate our Title IV Acid Rain Program SO2 allowance bank plus annual allocations will be more than our projected emissions through 2017. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates. | ||||||||
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. For our Missouri units, beginning in 2010, CAIR required the SO2 allowances to be utilized at a 2:1 ratio and, beginning in 2015, will require the SO2 allowances to be utilized at a 2.86:1 ratio. As a result, based on current SO2 allowance usage projections, we expect to have sufficient allowances to take us through 2017. | ||||||||
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 Flue-Gas Desulfurization (FGD) scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was placed in service 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 was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals vacated CSAPR on August 21, 2012, and the EPA has subsequently petitioned the Supreme Court to review the D.C. Circuit Court’s decision. On June 24, 2013 the Supreme Court agreed to review the D.C. Circuit court’s decision, which is set to occur December 6, 2013. The CAIR will be in effect until a valid replacement is developed by the EPA. | ||||||||
When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program could not be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. Based on current projections, we would receive more SO2 allowances than would be emitted. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We anticipate compliance costs associated with CAIR or its subsequent replacement to be recoverable in our rates. | ||||||||
Mercury Air Toxics Standard (MATS): | ||||||||
The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms. Rather, it establishes 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 MATS 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 ambient SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state. In April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach for areas without ambient SO2 monitors, the compliance time-frame may be pushed back. 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 called the Data Requirements Rule (DRR) to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely that 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. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR as a result of the vacated CSPAR rule and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008. | ||||||||
CAIR: | ||||||||
The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2012 which were banked for future use and will be sufficient for compliance through at least the end of 2017. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because the D.C. Circuit Court vacated CSAPR and the case is being re-heard by the Supreme Court, CAIR will remain in effect until the EPA develops a valid replacement. | ||||||||
CSAPR: | ||||||||
As published, the CSAPR would have required a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR could not be used for compliance under CSAPR. New allowances would have been issued under CSAPR. However, as discussed above, CSPAR was vacated by the District of Columbia Circuit Court of Appeals on August 21, 2012 and the case is set to be re-heard by the Supreme Court on December 6, 2013. | ||||||||
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, to protect public health, the EPA proposed to lower the primary NAAQS for ozone to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone 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 moved forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory is designated as attainment, meaning that it is in compliance with the standard. | ||||||||
A revised Ozone NAAQS is expected to be proposed by the EPA early 2014 and is anticipated to be between 60 and 70 ppb. | ||||||||
PM NAAQS: | ||||||||
Particulate matter (PM) is the term for particles found in the air which comes from a variety of sources. On January 15, 2013, the EPA finalized the PM 2.5 primary annual standard at 12 ug/m(3) (micrograms per cubic meter of air). States are required to meet the primary standard in 2020. | ||||||||
The standard should have no impact on our existing generating fleet because the PM 2.5 ambient monitor results are below the required level. However, the proposed standards could impact future major modifications/construction projects that require a Prevention of Significant Deterioration (PSD) permit. | ||||||||
Mercury Air Toxics Standard (MATS) | ||||||||
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 Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009. | ||||||||
The EPA issued Information Collection Requests (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. The ICRs included our Iatan, Asbury and Riverton plants. All responses to the ICRs were submitted as required. The EPA ICRs were intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the national mercury and air toxics standards (MATS) in March 2011, which became effective April 16, 2012. MATS establishes 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. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants. On June 25, 2013, the startup, shutdown portion of the MATS was proposed for reconsideration in order to better define startup and shutdown periods (instances when the emission unit is on but the pollution control equipment is not in full operation) that will be excluded from emissions averaging for compliance purposes. | ||||||||
The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule. We expect compliance costs to be recoverable in our rates. | ||||||||
Greenhouse Gases | ||||||||
Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other Greenhouse Gases (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. EDE and EDG’s GHG emissions for 2011 and 2012 have been reported as required to the EPA. | ||||||||
On December 7, 2009, responding to a 2007 U.S. 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 did not itself trigger any EPA regulations, but was a necessary predicate for the EPA to proceed with regulations to control GHGs. Since that time, a series of rules including the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) have been issued by the EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging these rules. On June 26, 2012, the D.C. Circuit Court issued its opinion in the principal litigation of the EPA GHG rules (Endangerment, the Tailoring Rule, GHG emission standards for light-duty vehicles, and the EPA’s rule on reconsideration of the PSD Interpretive Memorandum). The three-judge panel upheld the EPA’s interpretation of the Clean Air Act provisions as unambiguously correct. This opinion solidifies the EPA’s position that the CAA requires PSD and Title V permits for major emitters of greenhouse gases, such as Empire. Our ongoing projects are currently being evaluated for the projected increase or decrease of CO2e emissions as required by the Tailoring Rule. | ||||||||
As the result of an agreement to settle litigation pending in the U.S. Court of Appeals, on April 13, 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by electric utility generating units (EGUs). In light of the more than 2.5 million comments received by the EPA, this standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was issued on September 20, 2013 as required by President Obama. The proposed rule sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. Limiting CO2 output to 1,000 or 1,100 pounds per megawatt hour based on size and fuel type, the standards apply only to new EGUs. It is expected that most new natural gas-fired combined cycle units will meet the new standard. The EPA believes fossil-fuel fired boilers can meet the standard through efficient technology or some level of carbon capture and sequestration, but the high cost, technical feasibility, and long term liability of stored carbon are issues that have not been resolved and limit this option for Empire and all electric utilities. | ||||||||
The proposal would not apply to existing units including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle. In response to President Obama’s June 25, 2013 memorandum to the EPA Administrator, the EPA is engaging states and stakeholders in a process to identify approaches to establish carbon pollution standards for currently operating power plants. | ||||||||
President Obama’s memorandum to the EPA Administrator requested the EPA issue proposed carbon pollution standards, regulations, or guidelines for modified, reconstructed, and existing power plants by no later than June 1, 2014; issue final standards, regulations, or guidelines, for modified, reconstructed, and existing power plants by no later than June 1, 2015; and include in the guidelines addressing existing power plants a requirement that states submit to the EPA implementation plans by no later than June 30, 2016. As of October 15, 2013, the U.S. Supreme Court agreed to review an appeals court decision that said the EPA could regulate greenhouse gas emissions from fixed sources based on a previous decision based on green house emissions from cars. | ||||||||
In addition, 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 the 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. | ||||||||
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 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. The EPA has secured an additional year to finalize the standards for cooling water intake structures under a modified settlement agreement. Following a recent court approved delay, the EPA is now obligated to finalize the rule by November 4, 2013. 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 a limited impact at Riverton. The retirement of units 7 and 8 is scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. 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% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. 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 our 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 2014. 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. | ||||||||
On September 23, 2010 and on November 4, 2010 EPA consultants 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. In response to the inspection comments, the recommended geotechnical studies have been completed and new flow monitoring devices and settlement monuments at both coal ash impoundments have been installed. As a result of the transition from coal to natural gas, closure of the Riverton impoundment is in progress in compliance with KDHE Bureau of Waste Management regulations. We expect to complete the closure by late 2013. The final design for additional recommendations that will improve safety for slope stability at the Asbury impoundment is under review. We have received preliminary approval by the MDNR for the site permitting of a new utility waste landfill adjacent to the Asbury plant. Additionally, the work plan for the detailed site investigation (DSI) to include geologic and hydrologic investigations has been approved by the MDNR Division of Geology and Land Survey. Construction of the new landfill is expected in 2016. | ||||||||
Renewable Energy | ||||||||
As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm. More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). 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. | ||||||||
Missouri regulations currently require 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 in 2012, increasing to at least 5% by 2014 and ultimately to at least 15% by 2021. We are currently in compliance with this regulatory requirement. The regulations require that 2% of the renewable energy source must be solar; however, 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. On January 30, 2013, a complaint was filed with the MPSC by Renew Missouri and others regarding several points of our 2011 RES Compliance Report and the 2012-2014 Compliance Plan. The complaint, which was lodged against four investor-owned utilities (Ameren Missouri, Kansas City Power & Light Company (KCP&L), KCP&L Greater Missouri Operations, and Empire), is currently under consideration by the MPSC. On October 3, 2013, the MPSC issued an order denying motions for summary determination of Renew Missouri and KCP&L/GMO, but granting motion for summary determination of Empire. In this order, the MPSC determined the provisions of the rule exempt Empire from the obligation to provide a detailed explanation of the calculation of the RES retail impact limit for its 2012 Plan. By granting Empire’s motion, the MPSC unconsolidated the complaint against Empire and ordered that it would proceed independently. Items remaining under consideration from the original complaint include the qualification of Empire’s Ozark Beach facility as a hydropower renewable energy resource, the use of early RECs for compliance and Empire’s exemption from the use of solar RECs for compliance. | ||||||||
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 and the entire order was stayed. On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. The MPSC appealed this decision and in November of 2012 the court dismissed lawsuits brought against the RES and affirmed the MPSC rules that were finalized in July 2010. 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 in 2012, increasing to 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 in the future. 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. At the end of 2012, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2012. Additional RECs were retired in January of 2013 to complete the process for 2012. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future requirements. | ||||||||
Gas Segment | ||||||||
The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites owned by predecessors. 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 Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP sites to be minimal. |
Retirement_Benefits
Retirement Benefits | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Retirement Benefits | ' | |||||||||||||||||||
Retirement Benefits | ' | |||||||||||||||||||
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 | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 1,863 | $ | 1,439 | $ | 34 | $ | 23 | $ | 735 | $ | 671 | ||||||||
Interest cost | 2,516 | 2,591 | 78 | 86 | 957 | 962 | ||||||||||||||
Expected return on plan assets | (3,107 | ) | (3,080 | ) | — | — | (1,088 | ) | (1,018 | ) | ||||||||||
Amortization of prior service cost (1) | 133 | 133 | (2 | ) | (2 | ) | (253 | ) | (253 | ) | ||||||||||
Amortization of net actuarial loss (1) | 2,611 | 2,052 | 142 | 139 | 565 | 311 | ||||||||||||||
Net periodic benefit cost | $ | 4,016 | $ | 3,135 | $ | 252 | $ | 246 | $ | 916 | $ | 673 | ||||||||
Nine months ended September 30, | ||||||||||||||||||||
Pension Benefits | SERP | OPEB | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 5,590 | $ | 4,696 | $ | 101 | $ | 39 | $ | 2,206 | $ | 1,801 | ||||||||
Interest cost | 7,547 | 7,693 | 236 | 197 | 2,870 | 3,027 | ||||||||||||||
Expected return on plan assets | (9,321 | ) | (9,232 | ) | — | — | (3,265 | ) | (3,101 | ) | ||||||||||
Amortization of prior service cost (1) | 399 | 398 | (6 | ) | (6 | ) | (758 | ) | (758 | ) | ||||||||||
Amortization of net actuarial loss (1) | 7,834 | 5,952 | 426 | 291 | 1,696 | 1,246 | ||||||||||||||
Net periodic benefit cost | $ | 12,049 | $ | 9,507 | $ | 757 | $ | 521 | $ | 2,749 | $ | 2,215 | ||||||||
Twelve months ended September 30, | ||||||||||||||||||||
Pension Benefits | SERP | OPEB | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 7,156 | $ | 6,094 | $ | 114 | $ | 62 | $ | 2,806 | $ | 2,367 | ||||||||
Interest cost | 10,111 | 10,295 | 301 | 243 | 3,879 | 4,123 | ||||||||||||||
Expected return on plan assets | (12,398 | ) | (12,017 | ) | — | — | (4,299 | ) | (4,140 | ) | ||||||||||
Amortization of prior service cost (1) | 531 | 532 | (8 | ) | (8 | ) | (1,011 | ) | (1,011 | ) | ||||||||||
Amortization of net actuarial loss (1) | 9,818 | 7,325 | 523 | 334 | 2,112 | 1,687 | ||||||||||||||
Net periodic benefit cost | $ | 15,218 | $ | 12,229 | $ | 930 | $ | 631 | $ | 3,487 | $ | 3,026 | ||||||||
(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 pension 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 pension contributions of approximately $16.2 million in July 2013, which are expected to satisfy our funding requirements for the year. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. |
StockBased_Awards_and_Programs
Stock-Based Awards and Programs | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Stock-Based Awards and Programs | ' | |||||||||||||||||||
Stock-Based Awards and Programs | ' | |||||||||||||||||||
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. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. 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. Grants were made in the first quarter of 2013 (the effect of which is included in the table below) but did not have a material impact on our results of operations. We had unrecognized compensation expense of $0.7 million as of September 30, 2013. | ||||||||||||||||||||
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): | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Compensation Expense | $ | 363 | $ | 431 | $ | 2,057 | $ | 1,629 | $ | 2,305 | $ | 2,077 | ||||||||
Tax Benefit Recognized | 127 | 148 | 743 | 575 | 821 | 730 | ||||||||||||||
Performance-Based Restricted Stock Awards | ||||||||||||||||||||
Performance-based restricted stock awards 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) are granted to qualified individuals. We estimate the fair value of outstanding restricted stock awards using a Monte Carlo option valuation model. | ||||||||||||||||||||
Time-Vested Restricted Stock Awards | ||||||||||||||||||||
Beginning in 2011, we began granting time-vested restricted stock awards that vest after a three-year period, to qualified individuals in lieu of stock options. 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 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, which is distributed six months following the date of termination, with the remainder of the award forfeited. 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. | ||||||||||||||||||||
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, 2013 and 2012, under a Black-Scholes methodology. |
Regulated_Operating_Expenses
Regulated Operating Expenses | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Regulated Operating Expenses | ' | |||||||||||||||||||
Regulated Operating Expenses | ' | |||||||||||||||||||
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 | Three | Nine | Nine | Twelve | Twelve | |||||||||||||||
Months | Months | Months | Months | Months | Months | |||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Electric transmission and distribution expense | $ | 5,530 | $ | 4,392 | $ | 16,509 | $ | 12,764 | $ | 20,828 | $ | 16,784 | ||||||||
Natural gas transmission and distribution expense | 681 | 554 | 1,803 | 1,870 | 2,376 | 2,463 | ||||||||||||||
Power operation expense (other than fuel) | 3,942 | 4,129 | 11,953 | 11,232 | 15,766 | 14,898 | ||||||||||||||
Customer accounts and assistance expense | 3,124 | 2,621 | 8,322 | 7,639 | 10,894 | 10,304 | ||||||||||||||
Employee pension expense (1) | 2,662 | 2,562 | 8,062 | 7,637 | 10,605 | 10,118 | ||||||||||||||
Employee healthcare expense (1) | 2,662 | 2,442 | 7,857 | 7,004 | 10,678 | 9,108 | ||||||||||||||
General office supplies and expense | 2,997 | 2,530 | 9,589 | 7,805 | 12,560 | 10,445 | ||||||||||||||
Administrative and general expense | 3,375 | 3,675 | 11,292 | 11,466 | 14,917 | 15,521 | ||||||||||||||
Allowance for uncollectible accounts | 975 | 968 | 2,765 | 2,313 | 3,489 | 3,245 | ||||||||||||||
Regulatory reversal of gain on sale of assets | — | — | 1,236 | — | 1,236 | — | ||||||||||||||
Miscellaneous expense | 152 | 165 | 496 | 500 | 675 | 686 | ||||||||||||||
Total | $ | 26,100 | $ | 24,038 | $ | 79,884 | $ | 70,230 | $ | 104,024 | $ | 93,572 | ||||||||
(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, Kansas and Oklahoma jurisdictions. |
Segment_Information
Segment Information | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Segment Information | ' | ||||||||||||||||
Segment Information | ' | ||||||||||||||||
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 income information, balance sheet information and capital expenditures of our business segments. | |||||||||||||||||
For the quarter ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 150,370 | $ | 4,952 | $ | 2,819 | $ | (655 | ) | $ | 157,486 | ||||||
Depreciation and amortization | 16,328 | 928 | 479 | — | 17,735 | ||||||||||||
Federal and state income taxes | 13,939 | (369 | ) | 580 | — | 14,150 | |||||||||||
Operating income | 31,589 | 364 | 943 | — | 32,896 | ||||||||||||
Interest income | 1 | 4 | — | 0 | 5 | ||||||||||||
Interest expense | 9,380 | 973 | — | 0 | 10,353 | ||||||||||||
Income from AFUDC (debt and equity) | 1,722 | 12 | — | — | 1,734 | ||||||||||||
Net income | 23,652 | (599 | ) | 943 | — | 23,996 | |||||||||||
Capital Expenditures | $ | 45,164 | $ | 628 | $ | 334 | $ | 46,126 | |||||||||
For the quarter ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 152,730 | $ | 4,999 | $ | 1,621 | $ | (148 | ) | $ | 159,202 | ||||||
Depreciation and amortization | 13,757 | 895 | 456 | — | 15,108 | ||||||||||||
Federal and state income taxes | 15,564 | (232 | ) | 145 | — | 15,477 | |||||||||||
Operating income | 34,517 | 532 | 233 | — | 35,282 | ||||||||||||
Interest income | 261 | 88 | 2 | (86 | ) | 265 | |||||||||||
Interest expense | 9,328 | 975 | — | (86 | ) | 10,217 | |||||||||||
Income from AFUDC (debt and equity) | 532 | 3 | — | — | 535 | ||||||||||||
Net income | 25,705 | (399 | ) | 236 | — | 25,542 | |||||||||||
Capital Expenditures | $ | 39,794 | $ | 783 | $ | 715 | $ | 41,292 | |||||||||
For the nine months ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 406,158 | $ | 33,222 | $ | 6,844 | $ | (952 | ) | $ | 445,272 | ||||||
Depreciation and amortization | 47,216 | 2,778 | 1,477 | — | 51,471 | ||||||||||||
Federal and state income taxes | 26,882 | 707 | 1,092 | — | 28,681 | ||||||||||||
Operating income | 70,097 | 4,004 | 1,763 | — | 75,864 | ||||||||||||
Interest income | 498 | 109 | 7 | (92 | ) | 522 | |||||||||||
Interest expense | 28,273 | 2,926 | — | (92 | ) | 31,107 | |||||||||||
Income from AFUDC (debt and equity) | 3,883 | 21 | — | — | 3,904 | ||||||||||||
Net income | 45,373 | 1,136 | 1,774 | — | 48,283 | ||||||||||||
Capital Expenditures | $ | 114,734 | $ | 2,824 | $ | 1,276 | $ | 118,834 | |||||||||
For the nine months ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 396,546 | $ | 26,486 | $ | 5,389 | $ | (444 | ) | $ | 427,977 | ||||||
Depreciation and amortization | 41,086 | 2,675 | 1,350 | — | 45,111 | ||||||||||||
Federal and state income taxes | 27,497 | 226 | 713 | — | 28,436 | ||||||||||||
Operating income | 72,594 | 3,120 | 1,140 | — | 76,854 | ||||||||||||
Interest income | 549 | 255 | 3 | (239 | ) | 568 | |||||||||||
Interest expense | 28,530 | 2,928 | — | (239 | ) | 31,219 | |||||||||||
Income from AFUDC (debt and equity) | 800 | 5 | — | — | 805 | ||||||||||||
Net income | 44,569 | 326 | 1,159 | — | 46,054 | ||||||||||||
Capital Expenditures | $ | 103,361 | $ | 2,352 | $ | 2,253 | $ | 107,966 | |||||||||
For the twelve months ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 520,265 | $ | 46,585 | $ | 8,641 | $ | (1,099 | ) | $ | 574,392 | ||||||
Depreciation and amortization | 61,441 | 3,702 | 1,664 | — | 66,807 | ||||||||||||
Federal and state income taxes | 31,651 | 1,269 | 1,482 | — | 34,402 | ||||||||||||
Operating income | 86,948 | 5,889 | 2,394 | — | 95,231 | ||||||||||||
Interest income | 895 | 177 | 10 | (156 | ) | 926 | |||||||||||
Interest expense | 37,610 | 3,902 | — | (156 | ) | 41,356 | |||||||||||
Income from AFUDC (debt and equity) | 5,002 | 25 | — | — | 5,027 | ||||||||||||
Net income | 53,435 | 2,066 | 2,409 | — | 57,910 | ||||||||||||
Capital Expenditures | $ | 151,490 | $ | 4,043 | $ | 1,622 | $ | 157,155 | |||||||||
For the twelve months ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 514,515 | $ | 39,571 | $ | 7,249 | $ | (592 | ) | $ | 560,743 | ||||||
Depreciation and amortization | 54,295 | 3,552 | 1,822 | — | 59,669 | ||||||||||||
Federal and state income taxes | 32,464 | 791 | 1,003 | — | 34,258 | ||||||||||||
Operating income | 89,754 | 4,995 | 1,608 | — | 96,357 | ||||||||||||
Interest income | 1,035 | 310 | 4 | (294 | ) | 1,055 | |||||||||||
Interest expense | 38,525 | 3,906 | 2 | (294 | ) | 42,139 | |||||||||||
Income from AFUDC (debt and equity) | 1,000 | 7 | — | — | 1,007 | ||||||||||||
Net Income | 51,870 | 1,244 | 1,631 | — | 54,745 | ||||||||||||
Capital Expenditures | $ | 126,176 | $ | 3,599 | $ | 2,909 | $ | 132,684 | |||||||||
As of September 30, 2013 | |||||||||||||||||
Electric | Gas(1) | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Balance Sheet Information | |||||||||||||||||
Total assets | $ | 2,085,805 | $ | 120,608 | $ | 30,295 | $ | (40,900 | ) | $ | 2,195,808 | ||||||
(1) Includes goodwill of $39,492 and reflects the payment of a dividend and return of capital from the EDG subsidiary to the parent in the third quarter of 2013. | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||
Electric | Gas(1) | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Balance Sheet Information | |||||||||||||||||
Total assets | $ | 2,034,399 | $ | 148,814 | $ | 28,871 | $ | (85,715 | ) | $ | 2,126,369 | ||||||
(1) Includes goodwill of $39,492. |
Income_Taxes
Income Taxes | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Income Taxes | ' | |||||||||||||||||||
Income Taxes | ' | |||||||||||||||||||
Note 12— Income Taxes | ||||||||||||||||||||
The following table shows 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 | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Consolidated provision for income taxes | $ | 14.1 | $ | 15.5 | $ | 28.7 | $ | 28.4 | $ | 34.4 | $ | 34.3 | ||||||||
Consolidated effective federal and state income tax rates | 37.1 | % | 37.7 | % | 37.3 | % | 38.2 | % | 37.3 | % | 38.5 | % | ||||||||
The effective income tax rate for the three, nine and twelve month periods ended September 30, 2013 is lower than comparable periods in 2012 primarily due to higher equity AFUDC income in 2013 compared with 2012. | ||||||||||||||||||||
On September 13, 2013, the Internal Revenue Service and the Treasury Department released final regulations under Code Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014. We are currently analyzing their impact on our financial statements. We do not expect the regulations to have a material impact to our effective tax rate. | ||||||||||||||||||||
We do not have any unrecognized tax benefits as of September 30, 2013. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. |
Regulatory_Matters_Tables
Regulatory Matters (Tables) | 9 Months Ended | |||||||
Sep. 30, 2013 | ||||||||
Regulatory Matters | ' | |||||||
Components of regulatory assets and liabilities | ' | |||||||
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, 2013 | December 31, 2012 | |||||||
Regulatory Assets: | ||||||||
Current: | ||||||||
Under recovered fuel costs(1) | $ | 302 | $ | 2,885 | ||||
Current portion of long-term regulatory assets(1) | 6,096 | 3,492 | ||||||
Regulatory assets, current(1) | 6,398 | 6,377 | ||||||
Long-term: | ||||||||
Pension and other postretirement benefits(2) | 129,110 | 136,480 | ||||||
Income taxes | 48,418 | 48,759 | ||||||
Deferred construction accounting costs | 16,385 | 16,717 | ||||||
Unamortized loss on reacquired debt | 11,246 | 12,142 | ||||||
Unsettled derivative losses — electric segment | 5,613 | 6,557 | ||||||
System reliability — vegetation management | 7,783 | 9,002 | ||||||
Storm costs(3) | 5,084 | 4,828 | ||||||
Asset retirement obligation | 4,616 | 4,430 | ||||||
Customer programs | 4,785 | 4,356 | ||||||
Unamortized loss on interest rate derivative | 1,001 | 1,147 | ||||||
Deferred operating and maintenance expense | 1,863 | 2,049 | ||||||
Under recovered fuel costs | 1,212 | 314 | ||||||
Current portion of long-term regulatory assets | (6,096 | ) | (3,492 | ) | ||||
Other | 930 | 669 | ||||||
Regulatory assets, long-term | 231,950 | 243,958 | ||||||
Total Regulatory Assets | $ | 238,348 | $ | 250,335 | ||||
September 30, 2013 | December 31, 2012 | |||||||
Regulatory Liabilities: | ||||||||
Current: | ||||||||
Over recovered fuel costs(1) | $ | 556 | $ | 3,214 | ||||
Current portion of long-term regulatory liabilities(1) | 3,739 | 3,089 | ||||||
Regulatory liabilities, current(1) | 4,295 | 6,303 | ||||||
Long-term: | ||||||||
Costs of removal | 92,058 | 83,368 | ||||||
SWPA payment for Ozark Beach lost generation | 20,105 | 22,242 | ||||||
Income taxes | 11,736 | 11,972 | ||||||
Deferred construction accounting costs — fuel | 8,047 | 8,156 | ||||||
Unamortized gain on interest rate derivative | 3,414 | 3,541 | ||||||
Pension and other postretirement benefits(4) | 2,377 | 2,007 | ||||||
Over recovered fuel costs | 533 | 2,858 | ||||||
Current portion of long-term regulatory liabilities(1) | (3,739 | ) | (3,089 | ) | ||||
Regulatory liabilities, long-term | 134,531 | 131,055 | ||||||
Total Regulatory Liabilities | $ | 138,826 | $ | 137,358 | ||||
(1) Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates. | ||||||||
(2) Includes the effect of costs incurred that are more or less than those allowed in rates for Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs. | ||||||||
(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado. | ||||||||
(4) 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. |
Risk_Management_and_Derivative1
Risk Management and Derivative Financial Instruments (Tables) | 9 Months Ended | |||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||
Risk Management and Derivative Financial Instruments | ' | |||||||||||||||||||||
Schedule of fair value of derivative financial instruments, balance sheet classification | ' | |||||||||||||||||||||
As of September 30, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands): | ||||||||||||||||||||||
ASSET DERIVATIVES | September 30, | December 31, | ||||||||||||||||||||
Non-designated hedging | 2013 | 2012 | ||||||||||||||||||||
instruments due to regulatory accounting | Balance Sheet Classification | Fair Value | Fair Value | |||||||||||||||||||
Natural gas contracts, gas segment | Current assets | $ | 11 | $ | 3 | |||||||||||||||||
Non-current assets and deferred charges - other | — | 17 | ||||||||||||||||||||
Natural gas contracts, electric segment | Current assets | 322 | 93 | |||||||||||||||||||
Non-current assets and deferred charges | — | 174 | ||||||||||||||||||||
Total derivatives assets | $ | 333 | $ | 287 | ||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||||
LIABILITY DERIVATIVES | 2013 | 2012 | ||||||||||||||||||||
Non-designated as hedging instruments | ||||||||||||||||||||||
due to regulatory accounting | ||||||||||||||||||||||
Natural gas contracts, gas segment | Current liabilities | $ | 22 | $ | 104 | |||||||||||||||||
Non-current liabilities and deferred credits | — | — | ||||||||||||||||||||
Natural gas contracts, electric segment | Current liabilities | 3,056 | 3,299 | |||||||||||||||||||
Non-current liabilities and deferred credits | 3,089 | 3,819 | ||||||||||||||||||||
Total derivatives liabilities | $ | 6,167 | $ | 7,222 | ||||||||||||||||||
Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - electric segment | ' | |||||||||||||||||||||
The following tables 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 | Balance Sheet | |||||||||||||||||||||
Instruments - Due to | Classification of | Amount of Gain / (Loss) Recognized on Balance Sheet | ||||||||||||||||||||
Regulatory Accounting | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Electric Segment | Derivatives | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Regulatory (assets)/liabilities | $ | (1,346 | ) | $ | 1,776 | $ | (1,778 | ) | $ | (52 | ) | $ | (4,174 | ) | $ | (4,259 | ) | ||||
Total Electric Segment | $ | (1,346 | ) | $ | 1,776 | $ | (1,778 | ) | $ | (52 | ) | $ | (4,174 | ) | $ | (4,259 | ) | |||||
Statement of | ||||||||||||||||||||||
Non-Designated Hedging | Income | |||||||||||||||||||||
Instruments - Due to | Classification of | Amount of Gain / (Loss) Recognized in Income on Derivative | ||||||||||||||||||||
Regulatory Accounting | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Electric Segment | Derivatives | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Fuel and purchased power expense | $ | (1,951 | ) | $ | (2,683 | ) | $ | (2,472 | ) | $ | (2,624 | ) | $ | (3,833 | ) | $ | (3,498 | ) | |||
Total Electric Segment | $ | (1,951 | ) | $ | (2,683 | ) | $ | (2,472 | ) | $ | (2,624 | ) | $ | (3,833 | ) | $ | (3,498 | |||||
Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations | ' | |||||||||||||||||||||
Dth Hedged | ||||||||||||||||||||||
Year | % Hedged | Physical | Financial | Average Price | ||||||||||||||||||
Remainder 2013 | 14 | % | 420,000 | 410,000 | $ | 5.62 | ||||||||||||||||
2014 | 49 | % | 460,000 | 4,640,000 | $ | 4.57 | ||||||||||||||||
2015 | 41 | % | — | 4,010,000 | $ | 4.58 | ||||||||||||||||
2016 | 21 | % | — | 2,100,000 | $ | 4.42 | ||||||||||||||||
2017 | 10 | % | — | 1,050,000 | $ | 4.43 | ||||||||||||||||
Schedule of minimum percentage hedged by year in the entity's procurement guidelines | ' | |||||||||||||||||||||
Year | Minimum % Hedged | |||||||||||||||||||||
Current | Up to 100% | |||||||||||||||||||||
First | 60% | |||||||||||||||||||||
Second | 40% | |||||||||||||||||||||
Third | 20% | |||||||||||||||||||||
Fourth | 10% | |||||||||||||||||||||
Schedule of minimum percentage of winter season usage hedged by year of the entity's gas operations | ' | |||||||||||||||||||||
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, 2013 (in thousands). | ||||||||||||||||||||||
Season | Minimum % | Dth Hedged | Dth Hedged | Dth in Storage | Actual % Hedged | |||||||||||||||||
Hedged | Financial | Physical | ||||||||||||||||||||
Current | 50% | 220,000 | 127,721 | 1,671,231 | 63 | % | ||||||||||||||||
Second | Up to 50% | — | — | — | ||||||||||||||||||
Third | Up to 20% | — | — | — | ||||||||||||||||||
Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - gas segment | ' | |||||||||||||||||||||
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). | ||||||||||||||||||||||
Balance Sheet | ||||||||||||||||||||||
Non-Designated Hedging | Classification of | Amount of Gain / (Loss) Recognized on Balance Sheet | ||||||||||||||||||||
Instruments Due to Regulatory | Gain / (Loss) on | Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
Accounting - Gas Segment | Derivative | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Commodity contracts | Regulatory (assets)/liabilities | $ | (27 | ) | $ | 106 | $ | (45 | ) | $ | (384 | ) | $ | (122 | ) | $ | (1,458 | ) | ||||
Total - Gas Segment | $ | (27 | ) | $ | 106 | $ | (45 | ) | $ | (384 | ) | $ | (122 | ) | $ | (1,458 | ) | |||||
Schedule of margin deposit assets | ' | |||||||||||||||||||||
(in millions) | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||
Margin deposit assets | $ | 5.8 | $ | 4.2 | ||||||||||||||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Fair Value Measurements | ' | |||||||||||||
Schedule of assets measured at fair value using the market value approach on a recurring basis | ' | |||||||||||||
Fair Value Measurements at Reporting Date Using | ||||||||||||||
($ in 000’s) | Assets/(Liabilities) | Quoted Prices in | Significant | Significant | ||||||||||
Description | at Fair Value | Active Markets for | Other | Unobservable | ||||||||||
Identical Liabilities | Observable | Inputs | ||||||||||||
(Level 1) | Inputs | (Level 3) | ||||||||||||
(Level 2) | ||||||||||||||
September 30, 2013 | ||||||||||||||
Derivative assets | $ | 333 | $ | 333 | $ | — | $ | — | ||||||
Derivative liabilities | $ | (6,167 | ) | $ | (6,167 | ) | $ | — | $ | — | ||||
December 31, 2012 | ||||||||||||||
Derivative assets | $ | 287 | $ | 287 | $ | — | $ | — | ||||||
Derivative liabilities | $ | (7,222 | ) | $ | (7,222 | ) | $ | — | $ | — |
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 9 Months Ended | |||||||
Sep. 30, 2013 | ||||||||
Commitments and Contingencies | ' | |||||||
Schedule of coal, natural gas and transportation contracts | ' | |||||||
The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2013 (in millions). | ||||||||
Firm physical gas and | Coal and coal | |||||||
transportation contracts | transportation contracts | |||||||
October 1, 2013 through December 31, 2013 | $ | 10.6 | $ | 5.7 | ||||
January 1, 2014 through December 31, 2015 | 30.5 | 34.3 | ||||||
January 1, 2016 through December 31, 2017 | 22.2 | 22.6 | ||||||
January 1, 2018 and beyond | 8.3 | 22.6 | ||||||
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Retirement Benefits | ' | |||||||||||||||||||
Schedule of net periodic benefit cost | ' | |||||||||||||||||||
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 | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 1,863 | $ | 1,439 | $ | 34 | $ | 23 | $ | 735 | $ | 671 | ||||||||
Interest cost | 2,516 | 2,591 | 78 | 86 | 957 | 962 | ||||||||||||||
Expected return on plan assets | (3,107 | ) | (3,080 | ) | — | — | (1,088 | ) | (1,018 | ) | ||||||||||
Amortization of prior service cost (1) | 133 | 133 | (2 | ) | (2 | ) | (253 | ) | (253 | ) | ||||||||||
Amortization of net actuarial loss (1) | 2,611 | 2,052 | 142 | 139 | 565 | 311 | ||||||||||||||
Net periodic benefit cost | $ | 4,016 | $ | 3,135 | $ | 252 | $ | 246 | $ | 916 | $ | 673 | ||||||||
Nine months ended September 30, | ||||||||||||||||||||
Pension Benefits | SERP | OPEB | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 5,590 | $ | 4,696 | $ | 101 | $ | 39 | $ | 2,206 | $ | 1,801 | ||||||||
Interest cost | 7,547 | 7,693 | 236 | 197 | 2,870 | 3,027 | ||||||||||||||
Expected return on plan assets | (9,321 | ) | (9,232 | ) | — | — | (3,265 | ) | (3,101 | ) | ||||||||||
Amortization of prior service cost (1) | 399 | 398 | (6 | ) | (6 | ) | (758 | ) | (758 | ) | ||||||||||
Amortization of net actuarial loss (1) | 7,834 | 5,952 | 426 | 291 | 1,696 | 1,246 | ||||||||||||||
Net periodic benefit cost | $ | 12,049 | $ | 9,507 | $ | 757 | $ | 521 | $ | 2,749 | $ | 2,215 | ||||||||
Twelve months ended September 30, | ||||||||||||||||||||
Pension Benefits | SERP | OPEB | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Service cost | $ | 7,156 | $ | 6,094 | $ | 114 | $ | 62 | $ | 2,806 | $ | 2,367 | ||||||||
Interest cost | 10,111 | 10,295 | 301 | 243 | 3,879 | 4,123 | ||||||||||||||
Expected return on plan assets | (12,398 | ) | (12,017 | ) | — | — | (4,299 | ) | (4,140 | ) | ||||||||||
Amortization of prior service cost (1) | 531 | 532 | (8 | ) | (8 | ) | (1,011 | ) | (1,011 | ) | ||||||||||
Amortization of net actuarial loss (1) | 9,818 | 7,325 | 523 | 334 | 2,112 | 1,687 | ||||||||||||||
Net periodic benefit cost | $ | 15,218 | $ | 12,229 | $ | 930 | $ | 631 | $ | 3,487 | $ | 3,026 | ||||||||
(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet. |
StockBased_Awards_and_Programs1
Stock-Based Awards and Programs (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Stock-Based Awards and Programs | ' | |||||||||||||||||||
Schedule of compensation expense and tax benefits for stock-based awards and programs | ' | |||||||||||||||||||
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): | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | Twelve Months Ended | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Compensation Expense | $ | 363 | $ | 431 | $ | 2,057 | $ | 1,629 | $ | 2,305 | $ | 2,077 | ||||||||
Tax Benefit Recognized | 127 | 148 | 743 | 575 | 821 | 730 | ||||||||||||||
Regulated_Operating_Expenses_T
Regulated Operating Expenses (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Regulated Operating Expenses | ' | |||||||||||||||||||
Schedule of 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 | Three | Nine | Nine | Twelve | Twelve | |||||||||||||||
Months | Months | Months | Months | Months | Months | |||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Electric transmission and distribution expense | $ | 5,530 | $ | 4,392 | $ | 16,509 | $ | 12,764 | $ | 20,828 | $ | 16,784 | ||||||||
Natural gas transmission and distribution expense | 681 | 554 | 1,803 | 1,870 | 2,376 | 2,463 | ||||||||||||||
Power operation expense (other than fuel) | 3,942 | 4,129 | 11,953 | 11,232 | 15,766 | 14,898 | ||||||||||||||
Customer accounts and assistance expense | 3,124 | 2,621 | 8,322 | 7,639 | 10,894 | 10,304 | ||||||||||||||
Employee pension expense (1) | 2,662 | 2,562 | 8,062 | 7,637 | 10,605 | 10,118 | ||||||||||||||
Employee healthcare expense (1) | 2,662 | 2,442 | 7,857 | 7,004 | 10,678 | 9,108 | ||||||||||||||
General office supplies and expense | 2,997 | 2,530 | 9,589 | 7,805 | 12,560 | 10,445 | ||||||||||||||
Administrative and general expense | 3,375 | 3,675 | 11,292 | 11,466 | 14,917 | 15,521 | ||||||||||||||
Allowance for uncollectible accounts | 975 | 968 | 2,765 | 2,313 | 3,489 | 3,245 | ||||||||||||||
Regulatory reversal of gain on sale of assets | — | — | 1,236 | — | 1,236 | — | ||||||||||||||
Miscellaneous expense | 152 | 165 | 496 | 500 | 675 | 686 | ||||||||||||||
Total | $ | 26,100 | $ | 24,038 | $ | 79,884 | $ | 70,230 | $ | 104,024 | $ | 93,572 | ||||||||
(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, Kansas and Oklahoma jurisdictions. |
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Segment Information | ' | ||||||||||||||||
Schedule of statement of income information, balance sheet information and capital expenditures by business segments | ' | ||||||||||||||||
For the quarter ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 150,370 | $ | 4,952 | $ | 2,819 | $ | (655 | ) | $ | 157,486 | ||||||
Depreciation and amortization | 16,328 | 928 | 479 | — | 17,735 | ||||||||||||
Federal and state income taxes | 13,939 | (369 | ) | 580 | — | 14,150 | |||||||||||
Operating income | 31,589 | 364 | 943 | — | 32,896 | ||||||||||||
Interest income | 1 | 4 | — | 0 | 5 | ||||||||||||
Interest expense | 9,380 | 973 | — | 0 | 10,353 | ||||||||||||
Income from AFUDC (debt and equity) | 1,722 | 12 | — | — | 1,734 | ||||||||||||
Net income | 23,652 | (599 | ) | 943 | — | 23,996 | |||||||||||
Capital Expenditures | $ | 45,164 | $ | 628 | $ | 334 | $ | 46,126 | |||||||||
For the quarter ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 152,730 | $ | 4,999 | $ | 1,621 | $ | (148 | ) | $ | 159,202 | ||||||
Depreciation and amortization | 13,757 | 895 | 456 | — | 15,108 | ||||||||||||
Federal and state income taxes | 15,564 | (232 | ) | 145 | — | 15,477 | |||||||||||
Operating income | 34,517 | 532 | 233 | — | 35,282 | ||||||||||||
Interest income | 261 | 88 | 2 | (86 | ) | 265 | |||||||||||
Interest expense | 9,328 | 975 | — | (86 | ) | 10,217 | |||||||||||
Income from AFUDC (debt and equity) | 532 | 3 | — | — | 535 | ||||||||||||
Net income | 25,705 | (399 | ) | 236 | — | 25,542 | |||||||||||
Capital Expenditures | $ | 39,794 | $ | 783 | $ | 715 | $ | 41,292 | |||||||||
For the nine months ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 406,158 | $ | 33,222 | $ | 6,844 | $ | (952 | ) | $ | 445,272 | ||||||
Depreciation and amortization | 47,216 | 2,778 | 1,477 | — | 51,471 | ||||||||||||
Federal and state income taxes | 26,882 | 707 | 1,092 | — | 28,681 | ||||||||||||
Operating income | 70,097 | 4,004 | 1,763 | — | 75,864 | ||||||||||||
Interest income | 498 | 109 | 7 | (92 | ) | 522 | |||||||||||
Interest expense | 28,273 | 2,926 | — | (92 | ) | 31,107 | |||||||||||
Income from AFUDC (debt and equity) | 3,883 | 21 | — | — | 3,904 | ||||||||||||
Net income | 45,373 | 1,136 | 1,774 | — | 48,283 | ||||||||||||
Capital Expenditures | $ | 114,734 | $ | 2,824 | $ | 1,276 | $ | 118,834 | |||||||||
For the nine months ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 396,546 | $ | 26,486 | $ | 5,389 | $ | (444 | ) | $ | 427,977 | ||||||
Depreciation and amortization | 41,086 | 2,675 | 1,350 | — | 45,111 | ||||||||||||
Federal and state income taxes | 27,497 | 226 | 713 | — | 28,436 | ||||||||||||
Operating income | 72,594 | 3,120 | 1,140 | — | 76,854 | ||||||||||||
Interest income | 549 | 255 | 3 | (239 | ) | 568 | |||||||||||
Interest expense | 28,530 | 2,928 | — | (239 | ) | 31,219 | |||||||||||
Income from AFUDC (debt and equity) | 800 | 5 | — | — | 805 | ||||||||||||
Net income | 44,569 | 326 | 1,159 | — | 46,054 | ||||||||||||
Capital Expenditures | $ | 103,361 | $ | 2,352 | $ | 2,253 | $ | 107,966 | |||||||||
For the twelve months ended September 30, 2013 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 520,265 | $ | 46,585 | $ | 8,641 | $ | (1,099 | ) | $ | 574,392 | ||||||
Depreciation and amortization | 61,441 | 3,702 | 1,664 | — | 66,807 | ||||||||||||
Federal and state income taxes | 31,651 | 1,269 | 1,482 | — | 34,402 | ||||||||||||
Operating income | 86,948 | 5,889 | 2,394 | — | 95,231 | ||||||||||||
Interest income | 895 | 177 | 10 | (156 | ) | 926 | |||||||||||
Interest expense | 37,610 | 3,902 | — | (156 | ) | 41,356 | |||||||||||
Income from AFUDC (debt and equity) | 5,002 | 25 | — | — | 5,027 | ||||||||||||
Net income | 53,435 | 2,066 | 2,409 | — | 57,910 | ||||||||||||
Capital Expenditures | $ | 151,490 | $ | 4,043 | $ | 1,622 | $ | 157,155 | |||||||||
For the twelve months ended September 30, 2012 | |||||||||||||||||
Electric | Gas | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Statement of Income Information | |||||||||||||||||
Revenues | $ | 514,515 | $ | 39,571 | $ | 7,249 | $ | (592 | ) | $ | 560,743 | ||||||
Depreciation and amortization | 54,295 | 3,552 | 1,822 | — | 59,669 | ||||||||||||
Federal and state income taxes | 32,464 | 791 | 1,003 | — | 34,258 | ||||||||||||
Operating income | 89,754 | 4,995 | 1,608 | — | 96,357 | ||||||||||||
Interest income | 1,035 | 310 | 4 | (294 | ) | 1,055 | |||||||||||
Interest expense | 38,525 | 3,906 | 2 | (294 | ) | 42,139 | |||||||||||
Income from AFUDC (debt and equity) | 1,000 | 7 | — | — | 1,007 | ||||||||||||
Net Income | 51,870 | 1,244 | 1,631 | — | 54,745 | ||||||||||||
Capital Expenditures | $ | 126,176 | $ | 3,599 | $ | 2,909 | $ | 132,684 | |||||||||
As of September 30, 2013 | |||||||||||||||||
Electric | Gas(1) | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Balance Sheet Information | |||||||||||||||||
Total assets | $ | 2,085,805 | $ | 120,608 | $ | 30,295 | $ | (40,900 | ) | $ | 2,195,808 | ||||||
(1) Includes goodwill of $39,492 and reflects the payment of a dividend and return of capital from the EDG subsidiary to the parent in the third quarter of 2013. | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||
Electric | Gas(1) | Other | Eliminations | Total | |||||||||||||
($-000’s) | |||||||||||||||||
Balance Sheet Information | |||||||||||||||||
Total assets | $ | 2,034,399 | $ | 148,814 | $ | 28,871 | $ | (85,715 | ) | $ | 2,126,369 | ||||||
(1) Includes goodwill of $39,492. |
Income_Taxes_Tables
Income Taxes (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Income Taxes | ' | |||||||||||||||||||
Schedule of provision for income taxes and consolidated effective federal and state income tax rates | ' | |||||||||||||||||||
The following table shows 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 | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||
Consolidated provision for income taxes | $ | 14.1 | $ | 15.5 | $ | 28.7 | $ | 28.4 | $ | 34.4 | $ | 34.3 | ||||||||
Consolidated effective federal and state income tax rates | 37.1 | % | 37.7 | % | 37.3 | % | 38.2 | % | 37.3 | % | 38.5 | % | ||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Details) | 9 Months Ended |
Sep. 30, 2013 | |
town | |
segment | |
item | |
Summary of Significant Accounting Policies | ' |
Number of business segments | 3 |
Number of towns to which water service is provided | 3 |
Number of communities provided natural gas distribution | 48 |
Regulatory_Matters_Details
Regulatory Matters (Details) (USD $) | 9 Months Ended | 12 Months Ended | 0 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2013 | Feb. 27, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Feb. 27, 2013 | |
Missouri Public Service Commission (MPSC) | Missouri Public Service Commission (MPSC) | Missouri Public Service Commission (MPSC) | Missouri Public Service Commission (MPSC) | |||
Missouri 2012 Rate Case | Missouri 2012 Rate Case | Missouri 2012 Rate Case | Electric | |||
Iatan 2 | Missouri 2012 Rate Case | |||||
RATE MATTERS | ' | ' | ' | ' | ' | ' |
Approved amount of annual increase in base rate | ' | ' | ' | ' | ' | $27,500,000 |
Deferred tornado costs recovery period | ' | ' | '10 years | ' | ' | ' |
Write-off of various items including disallowance for the prudency of certain construction expenditures | ' | ' | ' | 3,600,000 | ' | ' |
Write-off of various items | 2,409,000 | 2,409,000 | ' | ' | 2,400,000 | ' |
Reverse gain on sale of Asbury unit train | $1,236,000 | $1,236,000 | ' | $1,200,000 | ' | ' |
Regulatory_Matters_Details_2
Regulatory Matters (Details 2) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | Current Recovery Period | Cost of removal | Cost of removal | SWPA payment for Ozark Beach lost generation | SWPA payment for Ozark Beach lost generation | Income taxes | Income taxes | Deferred construction accounting costs - fuel | Deferred construction accounting costs - fuel | Unamortized gain on interest rate derivative | Unamortized gain on interest rate derivative | Pension and other postretirement benefits | Pension and other postretirement benefits | Over recovered fuel costs | Over recovered fuel costs | Current portion of long-term regulatory liabilities | Current portion of long-term regulatory liabilities | Pension and other postretirement benefits | Pension and other postretirement benefits | Income taxes | Income taxes | Deferred construction accounting costs | Deferred construction accounting costs | Unamortized loss on reacquired debt | Unamortized loss on reacquired debt | System reliability - vegetation management | System reliability - vegetation management | Storm costs | Storm costs | Asset retirement obligation | Asset retirement obligation | Customer programs | Customer programs | Unamortized loss on interest rate derivative | Unamortized loss on interest rate derivative | Deferred operating and maintenance expense | Deferred operating and maintenance expense | Under recovered fuel costs | Under recovered fuel costs | Current portion of long-term regulatory assets | Current portion of long-term regulatory assets | Other | Other | Electric | Electric | ||
Unsettled derivative losses | Unsettled derivative losses | ||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory assets, current | $6,398 | $6,377 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $302 | $2,885 | $6,096 | $3,492 | ' | ' | ' | ' |
Regulatory assets, long-term | 231,950 | 243,958 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 129,110 | 136,480 | 48,418 | 48,759 | 16,385 | 16,717 | 11,246 | 12,142 | 7,783 | 9,002 | 5,084 | 4,828 | 4,616 | 4,430 | 4,785 | 4,356 | 1,001 | 1,147 | 1,863 | 2,049 | 1,212 | 314 | -6,096 | -3,492 | 930 | 669 | 5,613 | 6,557 |
Regulatory assets, total | 238,348 | 250,335 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period to recover costs in Missouri, Kansas and Oklahoma rates | ' | ' | '12 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities, current | 4,295 | 6,303 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 556 | 3,214 | 3,739 | 3,089 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities, long-term | 134,531 | 131,055 | ' | 92,058 | 83,368 | 20,105 | 22,242 | 11,736 | 11,972 | 8,047 | 8,156 | 3,414 | 3,541 | 2,377 | 2,007 | 533 | 2,858 | -3,739 | -3,089 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities, total | $138,826 | $137,358 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Risk_Management_and_Derivative2
Risk Management and Derivative Financial Instruments (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Fair value of derivative financial instruments | ' | ' |
Current assets | $333,000 | $96,000 |
Total derivatives assets | 333,000 | 287,000 |
Current liabilities | 3,078,000 | 3,403,000 |
Non-current liabilities and deferred credits | 3,089,000 | 3,819,000 |
Total derivatives liabilities | 6,167,000 | 7,222,000 |
Contingent Features | ' | ' |
Margin deposit assets | 5,800,000 | 4,200,000 |
Deposit liability | ' | ' |
Margin deposit liabilities | 0 | 0 |
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas | ' | ' |
Fair value of derivative financial instruments | ' | ' |
Current assets | 11,000 | 3,000 |
Non-current assets and deferred charges- other | ' | 17,000 |
Current liabilities | 22,000 | 104,000 |
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric | ' | ' |
Fair value of derivative financial instruments | ' | ' |
Current assets | 322,000 | 93,000 |
Non-current assets and deferred charges- other | ' | 174,000 |
Current liabilities | 3,056,000 | 3,299,000 |
Non-current liabilities and deferred credits | $3,089,000 | $3,819,000 |
Risk_Management_and_Derivative3
Risk Management and Derivative Financial Instruments (Details 2) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Electric | ' | ' | ' | ' | ' | ' |
Gain / (Loss) on derivatives | ' | ' | ' | ' | ' | ' |
Unrealized losses applicable to financial instruments which will settle in next twelve months | $3,100,000 | ' | $3,100,000 | ' | $3,100,000 | ' |
Period within which financial instruments will settle | ' | ' | '12 months | ' | ' | ' |
Amount of Gain/(Loss) Recognized on Balance Sheet | -1,346,000 | 1,776,000 | -1,778,000 | -52,000 | -4,174,000 | -4,259,000 |
Amount of Gain / (Loss) Recognized in Income on Derivative | -1,951,000 | -2,683,000 | -2,472,000 | -2,624,000 | -3,833,000 | -3,498,000 |
Gas | ' | ' | ' | ' | ' | ' |
Gain / (Loss) on derivatives | ' | ' | ' | ' | ' | ' |
Amount of Gain/(Loss) Recognized on Balance Sheet | -27,000 | 106,000 | -45,000 | -384,000 | -122,000 | -1,458,000 |
Commodity contracts | Electric | ' | ' | ' | ' | ' | ' |
Gain / (Loss) on derivatives | ' | ' | ' | ' | ' | ' |
Amount of Gain/(Loss) Recognized on Balance Sheet | -1,346,000 | 1,776,000 | -1,778,000 | -52,000 | -4,174,000 | -4,259,000 |
Amount of Gain / (Loss) Recognized in Income on Derivative | -1,951,000 | -2,683,000 | -2,472,000 | -2,624,000 | -3,833,000 | -3,498,000 |
Commodity contracts | Gas | ' | ' | ' | ' | ' | ' |
Gain / (Loss) on derivatives | ' | ' | ' | ' | ' | ' |
Amount of Gain/(Loss) Recognized on Balance Sheet | ($27,000) | $106,000 | ($45,000) | ($384,000) | ($122,000) | ($1,458,000) |
Risk_Management_and_Derivative4
Risk Management and Derivative Financial Instruments (Details 3) (Electric) | 9 Months Ended |
Sep. 30, 2013 | |
Dth | |
Natural Gas Usage - Remainder 2013 | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 14.00% |
Physical | 420,000 |
Financial | 410,000 |
Average Price (in dollars per dth) | 5.62 |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 14.00% |
Natural Gas Usage - 2014 | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 49.00% |
Physical | 460,000 |
Financial | 4,640,000 |
Average Price (in dollars per dth) | 4.57 |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 49.00% |
Natural Gas Usage - 2015 | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 41.00% |
Financial | 4,010,000 |
Average Price (in dollars per dth) | 4.58 |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 41.00% |
Natural Gas Usage - 2016 | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 21.00% |
Financial | 2,100,000 |
Average Price (in dollars per dth) | 4.42 |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 21.00% |
Natural Gas Usage - 2017 | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 10.00% |
Financial | 1,050,000 |
Average Price (in dollars per dth) | 4.43 |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 10.00% |
Current Year Procurement Guidelines | ' |
Procurement guidelines | ' |
Maximum flexibility to hedge any future year's expected requirements (as a percent) | 80.00% |
Maximum percentage of volume to be hedged in any given month | 100.00% |
First Year Procurement Guidelines | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 60.00% |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 60.00% |
Second Year Procurement Guidelines | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 40.00% |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 40.00% |
Third Year Procurement Guidelines | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 20.00% |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 20.00% |
Fourth Year Procurement Guidelines | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 10.00% |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 10.00% |
Maximum | Current Year Procurement Guidelines | ' |
Volumes and percentage of anticipated volume of natural gas usage | ' |
% Hedged | 100.00% |
Minimum Percentage Hedged for Electric Segment | ' |
End of Year Minimum % Hedged | 100.00% |
Risk_Management_and_Derivative5
Risk Management and Derivative Financial Instruments (Details 4) (USD $) | 9 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2013 |
season | |
pipeline | |
Dth | |
Contingent Features | ' |
Aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position | 0.4 |
Collateral posted | 0 |
Collateral which the entity would have been required to post with the counterparty if the credit-risk-related contingent features were triggered | 0.4 |
Gas | ' |
Price Risk Mitigation for Gas Segment | ' |
Target percentage of storage capacity utilization | 95.00% |
Volume of storage in pipelines that serve customers (in Dth) | 1,700,000 |
Number of pipelines that serve customers (in units) | 3 |
Storage capacity utilized (as a percent) | 83.00% |
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons) | 2 |
Gas | Current Winter Season | ' |
Gas Usage Hedged By Winter Season | ' |
End of Year Minimum % Hedged | 50.00% |
Dth Hedged Financial | 220,000,000 |
Dth Hedged Physical | 127,721,000 |
Dth in Storage | 1,671,231,000 |
Actual % Hedged | 63.00% |
Gas | Maximum | Second Winter Season | ' |
Gas Usage Hedged By Winter Season | ' |
End of Year Minimum % Hedged | 50.00% |
Gas | Maximum | Third Winter Season | ' |
Gas Usage Hedged By Winter Season | ' |
End of Year Minimum % Hedged | 20.00% |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (Recurring basis, USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Assets/(Liabilities) at Fair Value | ' | ' |
Fair Value Measurements at Reporting Date | ' | ' |
Derivative assets | $333 | $287 |
Derivative liabilities | -6,167 | -7,222 |
Quoted Prices in Active Markets for Identical Liabilities (Level 1) | ' | ' |
Fair Value Measurements at Reporting Date | ' | ' |
Derivative assets | 333 | 287 |
Derivative liabilities | ($6,167) | ($7,222) |
Fair_Value_Measurements_Detail1
Fair Value Measurements (Details 2) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Long-Term Debt | ' | ' |
Carrying amount of total long-term debt exclusive of capital leases | $739.30 | $687.60 |
Fair market value | $716.50 | $747.20 |
Financing_Details
Financing (Details) (USD $) | 9 Months Ended | 0 Months Ended | 0 Months Ended | 0 Months Ended | |||
Sep. 30, 2013 | Jun. 15, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 30, 2012 | Sep. 30, 2013 | Oct. 30, 2012 | |
First mortgage bonds | 4.50% Series due 2013 | 4.50% Series due 2013 | 3.73% First Mortgage Bonds due May 30, 2033 | 3.73% First Mortgage Bonds due May 30, 2033 | 4.32% First Mortgage Bonds due May 30, 2043 | 4.32% First Mortgage Bonds due May 30, 2043 | |
EDE | Issuance of debt | Issuance of debt | |||||
Financing | ' | ' | ' | ' | ' | ' | ' |
Interest rate, stated percentage | ' | ' | 4.50% | 3.73% | ' | 4.32% | ' |
Aggregate principal amount of debt entered into in private placement | ' | ' | ' | ' | $30,000,000 | ' | $120,000,000 |
Maximum principal amount outstanding at any one time | 1,000,000,000 | ' | ' | ' | ' | ' | ' |
Principal amount of debt redeemed | ' | $98,000,000 | ' | ' | ' | ' | ' |
Financing_Details_2
Financing (Details 2) (USD $) | 9 Months Ended |
Sep. 30, 2013 | |
item | |
Unsecured revolving credit facility | ' |
SHORT-TERM BORROWINGS | ' |
Unsecured revolving credit facility | $150,000,000 |
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement | 0.625 |
Minimum interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement | 2 |
Number of trailing fiscal quarters used for calculating the interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement | 4 |
Total indebtedness as a percent of total capitalization | 50.00% |
EBITDA coverage ratio over interest charges | 5 |
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility. | 10,000,000 |
Outstanding borrowings | 0 |
Commercial paper | ' |
SHORT-TERM BORROWINGS | ' |
Outstanding borrowings | $0 |
Commitments_and_Contingencies_1
Commitments and Contingencies (Details) (USD $) | 9 Months Ended | 30 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | |||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2008 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2005 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 |
item | Electric | Electric | Electric | Electric | Southern Star Central Pipeline, Inc. | Southern Star Central Pipeline, Inc. | Firm Physical gas and transportation contracts | Coal and coal transportation contracts | Purchased power | Purchased power | Purchased power | Purchased power | Purchased power | Purchased power | Purchased power | Purchased power | Purchased power | Leases | Leases | Leases | Transportation contracts | |
Compliance Plan | Power Plant Mercury And Air Toxics Rule | Maximum | Minimum | Electric | Electric | Plum Point Energy Station | Cloud County Windfarm | Cloud County Windfarm | Cloud County Windfarm | Cloud County Windfarm | Elk River Windfarm | Elk River Windfarm | Elk River Windfarm | Elk River Windfarm | Electric | Gas | Plum Point Energy Station | ANR Pipeline Company | ||||
MW | Power Plant Mercury And Air Toxics Rule | Power Plant Mercury And Air Toxics Rule | Dth | MW | MW | Maximum | Minimum | MW | Maximum | Minimum | train | office | railcar | |||||||||
Commitments and Contingencies | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
October 1, 2013 through December 31, 2013 | ' | ' | ' | ' | ' | ' | ' | $10.60 | $5.70 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
January 1, 2014 through December 31, 2015 | ' | ' | ' | ' | ' | ' | ' | 30.5 | 34.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
January 1, 2016 through December 31, 2017 | ' | ' | ' | ' | ' | ' | ' | 22.2 | 22.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
January 1, 2018 and beyond | ' | ' | ' | ' | ' | ' | ' | 8.3 | 22.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Term of long-term contract agreement | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | '30 years | '20 years | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' |
Agreement to purchase firm gas storage capacity (in Dths) | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of annual storage capacity reservation | ' | ' | ' | ' | ' | 1.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Extension period of contract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '10 years |
Contractual annual payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.5 |
Amount of long-term contract obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 299.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of annual payments contingent upon output of the facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14.6 | 0 | ' | ' | 16.9 | 0 | ' | ' | ' | ' |
Period of the average cost that is used as a basis for determining annual payments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' |
Energy capacity (in megawatts) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 670 | ' | 105 | ' | ' | ' | 150 | ' | ' | ' | ' | ' | ' |
Amount of energy capacity owned (in megawatts) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of energy capacity under option to purchase (in megawatts) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of total power capacity of generating facility (in megawatts) | ' | 14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of unit trains under short-term operating leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' |
Number of office facilities under short-term operating leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' |
Number of railcars under capital leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 108 | ' |
Estimated project cost | ' | ' | ' | 175 | 165 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Term of long-term contract agreement | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cost related to pre-engineering and site preparation activities year to date | ' | 5.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Project to date costs related to pre-engineering and site preparation activities | ' | $5.90 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of plaintiffs | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_and_Contingencies_2
Commitments and Contingencies (Details 2) (USD $) | 1 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 9 Months Ended | 0 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | ||||||||||||||||||
In Millions, unless otherwise specified | Jun. 30, 2006 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 15, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jan. 06, 2010 | Sep. 30, 2013 | Jan. 06, 2010 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 22, 2009 | Apr. 13, 2012 | Nov. 30, 2010 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2011 | Sep. 30, 2013 | Sep. 30, 2013 |
Gas | Gas | Permits | Title IV Acid Rain Program | Clean Air Interstate Rule | NAAQS | NAAQS | NAAQS | NAAQS | NAAQS | NAAQS | Power Plant Mercury And Air Toxics Rule | Power Plant Mercury And Air Toxics Rule | Power Plant Mercury And Air Toxics Rule | Surface Impoundments | Surface Impoundments | Surface Impoundments | Surface Impoundments | Green House Gases | Green House Gases | Green House Gases | Green House Gases | Renewable Energy | Renewable Energy | Renewable Energy | National Emission Standards for Hazardous Air Pollutants | Compliance Plan | Clean Air Transport Rule | |
site | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Iatan | Plum point | Minimum | Maximum | Electric | Electric | Electric | Electric | Electric | Electric | Electric | Electric | ||
T | MW | item | ppb | Minimum | Minimum | Maximum | Maximum | phase | Minimum | Maximum | option | Maximum | Electric | Electric | t | Minimum | MWh | Investor-owned utilities | T | |||||||||
state | ppb | ppb | ppb | ppb | item | certificate | item | |||||||||||||||||||||
customer | ||||||||||||||||||||||||||||
Environmental Laws And Regulations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of years site operating permits are valid | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected cost of adding Carbon injection system | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $112 | $130 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Construction costs year to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43.2 | ' |
Construction costs project to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73.5 | ' |
Amount of SO2 emission permitted under each SO2 allowance per affected unit (in tons) | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 |
Minimum capacity of power plant called to reduce emission levels of SO2 and NOx (in megawatts) | ' | ' | ' | ' | 25 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR | ' | ' | ' | ' | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ratio of S02 allowances that to be utilized in beginning of 2010 | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ratio of S02 allowances that to be utilized in beginning of 2015 | ' | ' | ' | ' | 2.86 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of SO2 reduction from 2005 levels by 2014, required by the proposed CATR | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73.00% |
Percentage of NOx reduction from 2005 levels by 2014, required by the proposed CSAPR | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 54.00% |
Proposed primary standard | ' | ' | ' | ' | ' | ' | ' | 60 | 60 | 70 | 70 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Normal reconsideration period for ozone standards | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
2008 standard at which states will continue to identify and designate all non-attainment areas | ' | ' | ' | ' | ' | ' | 75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Phase-in period for proposed standards | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' |
Period for compliance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '4 years | ' | ' |
Number of phases expected to reduce nationwide mercury emissions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum emission threshold of CO2e from power generating and certain other facilities requires to report Greenhouse Gases (in metric tons) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000 | ' | ' | ' | ' | ' | ' | ' |
Particulate matter primary annual standard (in micrograms per cubic meter of air) | ' | ' | ' | ' | ' | 12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of comments on proposed regulation for Carbon Pollution Standards for new power plants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500,000 | ' | ' | ' | ' | ' | ' |
Limit of CO2 emissions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000 | 1,100 | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of ownership in a coal ash impoundment at a generating facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12.00% | 7.52% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of options in the EPA proposal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum percentage of energy purchased through long-term Purchased Power Agreements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' |
Amount of renewable energy certificates generated each year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 900,000 | ' | ' | ' | ' |
Represents the megawatt-hour of renewable energy per renewable energy certificate (REC) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' |
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' |
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | ' | ' | ' | ' |
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' |
Number of customers who have challenged exemption from solar requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' |
Percentage of Missouri retail sales required to generate or purchase solar energy | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' |
Number of investor-owned utilities for whom complaint was lodged regarding several points of the entity's 2011 RES Compliance Report and the 2012-2014 Compliance Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | ' |
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy in 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' |
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2016 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' | ' |
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' |
Number of former manufactured plant sites with potential future remediation | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remediation costs | ' | $0.20 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Retirement_Benefits_Details
Retirement Benefits (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||
Jul. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Pension Benefits | Pension Benefits | Pension Benefits | Pension Benefits | Pension Benefits | Pension Benefits | SERP | SERP | SERP | SERP | SERP | SERP | OPEB | OPEB | OPEB | OPEB | OPEB | OPEB | ||
Net Periodic Pension Benefit Cost: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Service cost | ' | $1,863,000 | $1,439,000 | $5,590,000 | $4,696,000 | $7,156,000 | $6,094,000 | $34,000 | $23,000 | $101,000 | $39,000 | $114,000 | $62,000 | $735,000 | $671,000 | $2,206,000 | $1,801,000 | $2,806,000 | $2,367,000 |
Interest cost | ' | 2,516,000 | 2,591,000 | 7,547,000 | 7,693,000 | 10,111,000 | 10,295,000 | 78,000 | 86,000 | 236,000 | 197,000 | 301,000 | 243,000 | 957,000 | 962,000 | 2,870,000 | 3,027,000 | 3,879,000 | 4,123,000 |
Expected return on plan assets | ' | -3,107,000 | -3,080,000 | -9,321,000 | -9,232,000 | -12,398,000 | -12,017,000 | ' | ' | ' | ' | ' | ' | -1,088,000 | -1,018,000 | -3,265,000 | -3,101,000 | -4,299,000 | -4,140,000 |
Amortization of prior service cost | ' | 133,000 | 133,000 | 399,000 | 398,000 | 531,000 | 532,000 | -2,000 | -2,000 | -6,000 | -6,000 | -8,000 | -8,000 | -253,000 | -253,000 | -758,000 | -758,000 | -1,011,000 | -1,011,000 |
Amortization of net actuarial loss | ' | 2,611,000 | 2,052,000 | 7,834,000 | 5,952,000 | 9,818,000 | 7,325,000 | 142,000 | 139,000 | 426,000 | 291,000 | 523,000 | 334,000 | 565,000 | 311,000 | 1,696,000 | 1,246,000 | 2,112,000 | 1,687,000 |
Net periodic benefit cost | ' | 4,016,000 | 3,135,000 | 12,049,000 | 9,507,000 | 15,218,000 | 12,229,000 | 252,000 | 246,000 | 757,000 | 521,000 | 930,000 | 631,000 | 916,000 | 673,000 | 2,749,000 | 2,215,000 | 3,487,000 | 3,026,000 |
Employer contribution | $16,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
StockBased_Awards_and_Programs2
Stock-Based Awards and Programs (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Stock-Based Awards and Programs | ' | ' | ' | ' | ' | ' |
Unrecognized Compensation Expense | $700,000 | ' | $700,000 | ' | $700,000 | ' |
Compensation Expense | 363,000 | 431,000 | 2,057,000 | 1,629,000 | 2,305,000 | 2,077,000 |
Tax Benefit Recognized | $127,000 | $148,000 | $743,000 | $575,000 | $821,000 | $730,000 |
Time-Vested Restricted Stock Awards | ' | ' | ' | ' | ' | ' |
Assumptions used for estimating fair value of grants outstanding | ' | ' | ' | ' | ' | ' |
Vesting period | ' | ' | '3 years | ' | ' | ' |
Period from the date of termination of employment due to death, retirement or disability during which the pro-rata portion of the awards are distributed | ' | ' | '6 months | ' | ' | ' |
Regulated_Operating_Expenses_D
Regulated Operating Expenses (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Regulated Operating Expenses | ' | ' | ' | ' | ' | ' |
Electric transmission and distribution expense | $5,530 | $4,392 | $16,509 | $12,764 | $20,828 | $16,784 |
Natural gas transmission and distribution expense | 681 | 554 | 1,803 | 1,870 | 2,376 | 2,463 |
Power operation expense (other than fuel) | 3,942 | 4,129 | 11,953 | 11,232 | 15,766 | 14,898 |
Customer accounts and assistance expense | 3,124 | 2,621 | 8,322 | 7,639 | 10,894 | 10,304 |
Employee pension expense | 2,662 | 2,562 | 8,062 | 7,637 | 10,605 | 10,118 |
Employee healthcare expense | 2,662 | 2,442 | 7,857 | 7,004 | 10,678 | 9,108 |
General office supplies and expense | 2,997 | 2,530 | 9,589 | 7,805 | 12,560 | 10,445 |
Administrative and general expense | 3,375 | 3,675 | 11,292 | 11,466 | 14,917 | 15,521 |
Allowance for uncollectible accounts | 975 | 968 | 2,765 | 2,313 | 3,489 | 3,245 |
Regulatory reversal of gain on sale of assets | ' | ' | 1,236 | ' | 1,236 | ' |
Miscellaneous expense | 152 | 165 | 496 | 500 | 675 | 686 |
Total | $26,100 | $24,038 | $79,884 | $70,230 | $104,024 | $93,572 |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
segment | |||||||
town | |||||||
Segment Information | ' | ' | ' | ' | ' | ' | ' |
Number of business segments | ' | ' | 3 | ' | ' | ' | ' |
Number of towns to which water service is provided | ' | ' | 3 | ' | ' | ' | ' |
Statement of Income Information, balance sheet information and capital expenditures of business segments | ' | ' | ' | ' | ' | ' | ' |
Revenues | $157,486 | $159,202 | $445,272 | $427,977 | $574,392 | $560,743 | ' |
Depreciation and amortization | 17,735 | 15,108 | 51,471 | 45,111 | 66,807 | 59,669 | ' |
Federal and state income taxes | 14,150 | 15,477 | 28,681 | 28,436 | 34,402 | 34,258 | ' |
Operating income | 32,896 | 35,282 | 75,864 | 76,854 | 95,231 | 96,357 | ' |
Interest income | 5 | 265 | 522 | 568 | 926 | 1,055 | ' |
Interest expense | 10,353 | 10,217 | 31,107 | 31,219 | 41,356 | 42,139 | ' |
Income from AFUDC (debt and equity) | 1,734 | 535 | 3,904 | 805 | 5,027 | 1,007 | ' |
Net income | 23,996 | 25,542 | 48,283 | 46,054 | 57,910 | 54,745 | ' |
Capital Expenditures | 46,126 | 41,292 | 118,834 | 107,966 | 157,155 | 132,684 | ' |
Total assets | 2,195,808 | ' | 2,195,808 | ' | 2,195,808 | ' | 2,126,369 |
Goodwill | 39,492 | ' | 39,492 | ' | 39,492 | ' | 39,492 |
Electric | ' | ' | ' | ' | ' | ' | ' |
Statement of Income Information, balance sheet information and capital expenditures of business segments | ' | ' | ' | ' | ' | ' | ' |
Revenues | 150,370 | 152,730 | 406,158 | 396,546 | 520,265 | 514,515 | ' |
Depreciation and amortization | 16,328 | 13,757 | 47,216 | 41,086 | 61,441 | 54,295 | ' |
Federal and state income taxes | 13,939 | 15,564 | 26,882 | 27,497 | 31,651 | 32,464 | ' |
Operating income | 31,589 | 34,517 | 70,097 | 72,594 | 86,948 | 89,754 | ' |
Interest income | 1 | 261 | 498 | 549 | 895 | 1,035 | ' |
Interest expense | 9,380 | 9,328 | 28,273 | 28,530 | 37,610 | 38,525 | ' |
Income from AFUDC (debt and equity) | 1,722 | 532 | 3,883 | 800 | 5,002 | 1,000 | ' |
Net income | 23,652 | 25,705 | 45,373 | 44,569 | 53,435 | 51,870 | ' |
Capital Expenditures | 45,164 | 39,794 | 114,734 | 103,361 | 151,490 | 126,176 | ' |
Total assets | 2,085,805 | ' | 2,085,805 | ' | 2,085,805 | ' | 2,034,399 |
Gas | ' | ' | ' | ' | ' | ' | ' |
Statement of Income Information, balance sheet information and capital expenditures of business segments | ' | ' | ' | ' | ' | ' | ' |
Revenues | 4,952 | 4,999 | 33,222 | 26,486 | 46,585 | 39,571 | ' |
Depreciation and amortization | 928 | 895 | 2,778 | 2,675 | 3,702 | 3,552 | ' |
Federal and state income taxes | -369 | -232 | 707 | 226 | 1,269 | 791 | ' |
Operating income | 364 | 532 | 4,004 | 3,120 | 5,889 | 4,995 | ' |
Interest income | 4 | 88 | 109 | 255 | 177 | 310 | ' |
Interest expense | 973 | 975 | 2,926 | 2,928 | 3,902 | 3,906 | ' |
Income from AFUDC (debt and equity) | 12 | 3 | 21 | 5 | 25 | 7 | ' |
Net income | -599 | -399 | 1,136 | 326 | 2,066 | 1,244 | ' |
Capital Expenditures | 628 | 783 | 2,824 | 2,352 | 4,043 | 3,599 | ' |
Total assets | 120,608 | ' | 120,608 | ' | 120,608 | ' | 148,814 |
Other | ' | ' | ' | ' | ' | ' | ' |
Statement of Income Information, balance sheet information and capital expenditures of business segments | ' | ' | ' | ' | ' | ' | ' |
Revenues | 2,819 | 1,621 | 6,844 | 5,389 | 8,641 | 7,249 | ' |
Depreciation and amortization | 479 | 456 | 1,477 | 1,350 | 1,664 | 1,822 | ' |
Federal and state income taxes | 580 | 145 | 1,092 | 713 | 1,482 | 1,003 | ' |
Operating income | 943 | 233 | 1,763 | 1,140 | 2,394 | 1,608 | ' |
Interest income | ' | 2 | 7 | 3 | 10 | 4 | ' |
Interest expense | ' | ' | ' | ' | ' | 2 | ' |
Net income | 943 | 236 | 1,774 | 1,159 | 2,409 | 1,631 | ' |
Capital Expenditures | 334 | 715 | 1,276 | 2,253 | 1,622 | 2,909 | ' |
Total assets | 30,295 | ' | 30,295 | ' | 30,295 | ' | 28,871 |
Eliminations | ' | ' | ' | ' | ' | ' | ' |
Statement of Income Information, balance sheet information and capital expenditures of business segments | ' | ' | ' | ' | ' | ' | ' |
Revenues | -655 | -148 | -952 | -444 | -1,099 | -592 | ' |
Interest income | 0 | -86 | -92 | -239 | -156 | -294 | ' |
Interest expense | 0 | -86 | -92 | -239 | -156 | -294 | ' |
Total assets | ($40,900) | ' | ($40,900) | ' | ($40,900) | ' | ($85,715) |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Income Taxes | ' | ' | ' | ' | ' | ' |
Consolidated provision for income taxes | $14.10 | $15.50 | $28.70 | $28.40 | $34.40 | $34.30 |
Consolidated effective federal and state income tax rates (as a percent) | 37.10% | 37.70% | 37.30% | 38.20% | 37.30% | 38.50% |