Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 23, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | PUBLIC SERVICE CO OF COLORADO | ||
Entity Central Index Key | 81,018 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 100 | ||
Document Type | 10-K | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating revenues | |||
Electric | $ 3,003,808 | $ 3,049,352 | $ 3,115,257 |
Natural gas | 995,214 | 957,721 | 1,006,666 |
Steam and other | 43,487 | 40,723 | 41,590 |
Total operating revenues | 4,042,509 | 4,047,796 | 4,163,513 |
Operating expenses | |||
Electric fuel and purchased power | 1,126,660 | 1,196,417 | 1,246,666 |
Cost of natural gas sold and transported | 458,717 | 425,410 | 501,824 |
Cost of sales — steam and other | 16,146 | 15,872 | 17,788 |
Operating and maintenance expenses | 762,817 | 762,416 | 761,901 |
Demand side management program expenses | 125,029 | 118,175 | 128,681 |
Depreciation and amortization | 471,515 | 443,555 | 411,667 |
Taxes (other than income taxes) | 195,695 | 196,330 | 195,285 |
Total operating expenses | 3,156,579 | 3,158,175 | 3,263,812 |
Operating income | 885,930 | 889,621 | 899,701 |
Other income, net | 9,852 | 3,817 | 2,964 |
Allowance for funds used during construction — equity | 29,803 | 18,557 | 14,485 |
Interest charges and financing costs | |||
Interest charges — includes other financing costs of $6,281, $6,289 and $6,285, respectively | 190,694 | 181,631 | 177,430 |
Allowance for funds used during construction - debt | (11,407) | (7,045) | (5,522) |
Total interest charges and financing costs | 179,287 | 174,586 | 171,908 |
Income before income taxes | 746,298 | 737,409 | 745,242 |
Income taxes | 252,179 | 273,918 | 278,440 |
Net income | $ 494,119 | $ 463,491 | $ 466,802 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Interest charges and financing costs | |||
Other financing costs | $ 6,281 | $ 6,289 | $ 6,285 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Comprehensive income: | |||
Net income | $ 494,119 | $ 463,491 | $ 466,802 |
Pension and retiree medical benefits: | |||
Net pension and retiree medical losses arising during the period, net of tax of $(3), $(138), and $0 | (5) | (223) | 0 |
Amortization of losses included in net periodic benefit cost, net of tax of $4, $2, and $0, respectively | 5 | 3 | 0 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax | 0 | (220) | 0 |
Derivative instruments: | |||
Net fair value decrease, net of tax of $0, $0, and $(20), respectively | 0 | 0 | (30) |
Reclassification of losses to net income, net of tax of $610, $648, and $39, respectively | 1,005 | 1,056 | 72 |
Total derivative instruments, net of tax | 1,005 | 1,056 | 42 |
Other comprehensive income | 1,005 | 836 | 42 |
Comprehensive income | $ 495,124 | $ 464,327 | $ 466,844 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other comprehensive income (loss) | |||
Amortization of losses included in net periodic benefit cost, tax | $ 4 | $ 2 | $ 0 |
Derivative instruments: | |||
Net fair value (decrease) increase, tax | 0 | 0 | (20) |
Reclassification of losses (gains) to net income, tax | 610 | 648 | 39 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax | $ (3) | $ (138) | $ 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities | |||
Net income | $ 494,119 | $ 463,491 | $ 466,802 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation and amortization | 475,592 | 446,179 | 416,427 |
Demand side management program amortization | 672 | 2,138 | 3,509 |
Deferred income taxes | 207,817 | 222,002 | 277,896 |
Amortization of Investment Tax Credits | (2,803) | (2,805) | (2,807) |
Allowance for equity funds used during construction | (29,803) | (18,557) | (14,485) |
Provision for bad debts | 14,303 | 14,121 | 13,052 |
Net realized and unrealized hedging and derivative transactions | 2,364 | 1,325 | 2,414 |
Other | 6 | (388) | 2,500 |
Changes in operating assets and liabilities: | |||
Accounts receivable | (2,229) | (14,227) | 8,872 |
Accrued unbilled revenues | 1,277 | (20,866) | 17,837 |
Inventories | (9,099) | 172 | 33,417 |
Prepayments and other | 188 | 68,693 | 10,483 |
Accounts payable | 20,410 | 38,439 | (40,982) |
Net regulatory assets and liabilities | (22,548) | 4,143 | 78,055 |
Other current liabilities | 71,776 | 1,892 | 19,654 |
Pension and other employee benefit obligations | (16,515) | (10,627) | (23,449) |
Change in other noncurrent assets | (785) | (6,750) | 4,086 |
Change in other noncurrent liabilities | (2,982) | (22,120) | (35,334) |
Net cash provided by operating activities | 1,201,760 | 1,166,255 | 1,237,947 |
Investing activities | |||
Utility capital/construction expenditures | (1,475,697) | (1,113,800) | (995,597) |
Proceeds from Insurance Recoveries | 0 | 608 | 0 |
Allowance for equity funds used during construction | 29,803 | 18,557 | 14,485 |
Investments in utility money pool arrangement | (954,000) | (444,000) | (196,300) |
Repayments from utility money pool arrangement | 934,000 | 444,000 | 212,300 |
Other | (657) | (1,460) | 0 |
Net cash used in investing activities | (1,466,551) | (1,096,095) | (965,112) |
Financing activities | |||
Proceeds from (repayments of) short-term borrowings, net | (129,000) | 115,000 | (368,000) |
Borrowings under utility money pool arrangement | 40,000 | 524,500 | 165,000 |
Repayments under utility money pool arrangement | (40,000) | (524,500) | (165,000) |
Proceeds from issuance of long-term debt | 393,791 | 244,507 | 246,751 |
Repayments of long-term debt | 0 | (129,500) | 0 |
Capital contributions from parent | 335,576 | 38,755 | 175,210 |
Dividends paid to parent | (333,879) | (336,581) | (330,846) |
Other | (110) | 0 | 0 |
Net cash provided by (used in) financing activities | 266,378 | (67,819) | (276,885) |
Net change in cash and cash equivalents | 1,587 | 2,341 | (4,050) |
Cash and cash equivalents at beginning of period | 5,926 | 3,585 | 7,635 |
Cash and cash equivalents at end of period | 7,513 | 5,926 | 3,585 |
Supplemental disclosure of cash flow information: | |||
Cash paid for interest (net of amounts capitalized) | (174,978) | (171,714) | (165,546) |
Cash (paid) received for income taxes, net | (7,717) | 22,827 | 13,822 |
Supplemental disclosure of non-cash investing transactions: | |||
Property, plant and equipment additions in accounts payable | $ 183,858 | $ 68,870 | $ 106,912 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Current assets | |||
Cash and cash equivalents | $ 7,513 | $ 5,926 | |
Accounts receivable, net | 294,403 | 304,900 | |
Accounts receivable from affiliates | 14,719 | 9,421 | |
Investments Receivable in Utility Money Pool Arrangement | 20,000 | 0 | |
Accrued unbilled revenues | 295,801 | 297,078 | |
Inventories | 214,489 | 202,220 | |
Regulatory assets | 77,337 | 103,783 | |
Derivative instruments | 3,197 | 10,934 | |
Prepayments and other | 35,720 | 34,559 | |
Total current assets | 963,179 | 968,821 | |
Property, plant and equipment, net | 14,025,751 | 12,849,799 | |
Other assets | |||
Regulatory assets | 950,258 | 958,429 | |
Derivative instruments | 1,009 | 3,398 | |
Other | 27,429 | 25,637 | |
Total other assets | 978,696 | 987,464 | |
Total assets | 15,967,626 | 14,806,084 | |
Current liabilities | |||
Current portion of long-term debt | 305,577 | 5,270 | |
Short-term debt | 0 | 129,000 | |
Accounts payable | 492,829 | 376,186 | |
Accounts payable to affiliates | 58,749 | 98,797 | |
Regulatory liabilities | [1] | 66,126 | 101,110 |
Taxes accrued | 222,517 | 171,862 | |
Accrued interest | 48,552 | 48,619 | |
Dividends payable to parent | 76,195 | 74,208 | |
Derivative instruments | 7,348 | 6,788 | |
Other | 92,333 | 73,022 | |
Total current liabilities | 1,370,226 | 1,084,862 | |
Deferred credits and other liabilities | |||
Deferred income taxes | 1,644,476 | 2,889,129 | |
Deferred investment tax credits | 27,858 | 30,661 | |
Regulatory liabilities | 1,933,488 | 512,933 | |
Asset retirement obligations | 347,769 | 289,563 | |
Derivative instruments | 3,468 | 7,828 | |
Customer advances | 162,614 | 162,742 | |
Pension and employee benefit obligations | 287,783 | 285,774 | |
Other | 58,923 | 62,201 | |
Total deferred credits and other liabilities | 4,466,379 | 4,240,831 | |
Capitalization | |||
Long-term debt | 4,302,698 | 4,210,936 | |
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively | 0 | 0 | |
Additional paid in capital | 4,032,826 | 3,633,216 | |
Retained earnings | 1,822,229 | 1,659,239 | |
Accumulated other comprehensive loss | (26,732) | (23,000) | |
Total common stockholder’s equity | 5,828,323 | 5,269,455 | |
Total liabilities and equity | $ 15,967,626 | $ 14,806,084 | |
[1] | (c) Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Capitalization | ||
Common stock, shares authorized (in shares) | 100 | 100 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares outstanding (in shares) | 100 | 100 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands | Total | Common stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | |
Beginning Balance at Dec. 31, 2014 | $ 4,885,839 | $ 0 | $ 3,522,788 | $ 1,386,929 | $ (23,878) | |
Balance (in shares) at Dec. 31, 2014 | 100 | |||||
Increase (Decrease) in Stockholder's Equity | ||||||
Net income | 466,802 | 466,802 | ||||
Other comprehensive income | 42 | 42 | ||||
Common dividends declared to parent | (330,567) | (330,567) | ||||
Contribution of capital by parent | 98,036 | 98,036 | ||||
Ending Balance at Dec. 31, 2015 | 5,120,152 | $ 0 | 3,620,824 | 1,523,164 | (23,836) | |
Balance (in shares) at Dec. 31, 2015 | 100 | |||||
Increase (Decrease) in Stockholder's Equity | ||||||
Net income | 463,491 | 463,491 | ||||
Other comprehensive income | 836 | 836 | ||||
Common dividends declared to parent | (327,416) | (327,416) | ||||
Contribution of capital by parent | 12,392 | 12,392 | ||||
Ending Balance at Dec. 31, 2016 | $ 5,269,455 | $ 0 | 3,633,216 | 1,659,239 | (23,000) | |
Balance (in shares) at Dec. 31, 2016 | 100 | 100 | ||||
Increase (Decrease) in Stockholder's Equity | ||||||
Net income | $ 494,119 | 494,119 | ||||
Other comprehensive income | 1,005 | 1,005 | ||||
Common dividends declared to parent | (335,866) | (335,866) | ||||
Contribution of capital by parent | 399,610 | 399,610 | ||||
Adoption of ASU No. 2018-02 | 0 | 4,737 | (4,737) | [1] | ||
Ending Balance at Dec. 31, 2017 | $ 5,828,323 | $ 0 | $ 4,032,826 | $ 1,822,229 | $ (26,732) | |
Balance (in shares) at Dec. 31, 2017 | 100 | 100 | ||||
[1] | In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Unamortized Debt Issuance Expense | $ (28,911) | $ (26,799) |
Debt Instrument, Unamortized Discount (Premium), Net | (13,472) | (12,922) |
Total long-term debt | 4,608,275 | 4,216,206 |
Less current maturities | 305,577 | 5,270 |
Long-term Debt and Capital Lease Obligations | 4,302,698 | 4,210,936 |
Common Stockholder's Equity | ||
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively. | 0 | 0 |
Additional paid in capital | 4,032,826 | 3,633,216 |
Retained earnings | 1,822,229 | 1,659,239 |
Accumulated other comprehensive loss | (26,732) | (23,000) |
Total common stockholder’s equity | 5,828,323 | 5,269,455 |
First Mortgage Bonds | Series Due Aug. 1, 2018 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 300,000 | 300,000 |
First Mortgage Bonds | Series Due June 1, 2019 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 400,000 | 400,000 |
First Mortgage Bonds | Series Due Nov. 15, 2020 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 400,000 | 400,000 |
First Mortgage Bonds | Series Due Sept. 15, 2022 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 300,000 | 300,000 |
First Mortgage Bonds | Series Due March 15, 2023 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 250,000 | 250,000 |
First Mortgage Bonds | Series Due May 15, 2025 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 250,000 | 250,000 |
First Mortgage Bonds | Series Due Sept. 1, 2037 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 350,000 | 350,000 |
First Mortgage Bonds | Series Due Aug. 1, 2038 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 300,000 | 300,000 |
First Mortgage Bonds | Series Due Aug. 15, 2041 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 250,000 | 250,000 |
First Mortgage Bonds | Series Due Sept. 15, 2042 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 500,000 | 500,000 |
First Mortgage Bonds | Series Due March 15, 2043 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 250,000 | 250,000 |
First Mortgage Bonds | Series Due March 15, 2044 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 300,000 | 300,000 |
First Mortgage Bonds | Series Due June 15, 2046 [Member] | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 250,000 | 250,000 |
First Mortgage Bonds | Series Due June 15, 2047 [Member] | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Long-term debt, gross | 400,000 | 0 |
Capital Lease Obligations | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Capital lease obligations | $ 150,658 | $ 155,927 |
CONSOLIDATED STATEMENTS OF CA11
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Common Stockholders Equity [Abstract] | ||
Common stock, shares authorized (in shares) | 100 | 100 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares outstanding (in shares) | 100 | 100 |
First Mortgage Bonds | Series Due Aug. 1, 2018 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 5.80% | 5.80% |
Debt Instrument, Maturity Date | Aug. 1, 2018 | Aug. 1, 2018 |
First Mortgage Bonds | Series Due June 1, 2019 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 5.125% | 5.125% |
Debt Instrument, Maturity Date | Jun. 1, 2019 | Jun. 1, 2019 |
First Mortgage Bonds | Series Due Nov. 15, 2020 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.20% | 3.20% |
Debt Instrument, Maturity Date | Nov. 15, 2020 | Nov. 15, 2020 |
First Mortgage Bonds | Series Due Sept. 15, 2022 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 2.25% | 2.25% |
Debt Instrument, Maturity Date | Sep. 15, 2022 | Sep. 15, 2022 |
First Mortgage Bonds | Series Due March 15, 2023 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 2.50% | 2.50% |
Debt Instrument, Maturity Date | Mar. 15, 2023 | Mar. 15, 2023 |
First Mortgage Bonds | Series Due May 15, 2025 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 2.90% | 2.90% |
Debt Instrument, Maturity Date | May 15, 2025 | May 15, 2025 |
First Mortgage Bonds | Series Due Sept. 1, 2037 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 6.25% | 6.25% |
Debt Instrument, Maturity Date | Sep. 1, 2037 | Sep. 1, 2037 |
First Mortgage Bonds | Series Due Aug. 1, 2038 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 6.50% | 6.50% |
Debt Instrument, Maturity Date | Aug. 1, 2038 | Aug. 1, 2038 |
First Mortgage Bonds | Series Due Aug. 15, 2041 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 4.75% | 4.75% |
Debt Instrument, Maturity Date | Aug. 15, 2041 | Aug. 15, 2041 |
First Mortgage Bonds | Series Due Sept. 15, 2042 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.60% | 3.60% |
Debt Instrument, Maturity Date | Sep. 15, 2042 | Sep. 15, 2042 |
First Mortgage Bonds | Series Due March 15, 2043 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.95% | 3.95% |
Debt Instrument, Maturity Date | Mar. 15, 2043 | Mar. 15, 2043 |
First Mortgage Bonds | Series Due March 15, 2044 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 4.30% | 4.30% |
Debt Instrument, Maturity Date | Mar. 15, 2044 | Mar. 15, 2044 |
First Mortgage Bonds | Series Due June 15, 2046 [Member] | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.55% | 3.55% |
Debt Instrument, Maturity Date | Jun. 15, 2046 | Jun. 15, 2046 |
First Mortgage Bonds | Series Due June 15, 2047 [Member] | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.80% | |
Debt Instrument, Maturity Date | Jun. 15, 2047 | |
Capital Lease Obligations | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Debt instrument, maturity date range, end | Dec. 31, 2060 | |
Capital Lease Obligations | Minimum | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 11.20% | |
Capital Lease Obligations | Maximum | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 14.30% |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Business and System of Accounts — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. Principles of Consolidation — PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 6 for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages. PSCo evaluates its arrangements and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary. PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary. See Note 12 for further discussion of variable interest entities. Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations . Under this guidance: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows. See Note 13 for further discussion of regulatory assets and liabilities. Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees. PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures. The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers. Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7 , 2.6 and 2.7 percent for the years ended Dec. 31, 2017 , 2016 and 2015 , respectively. Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases. AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs. Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 7 for further discussion of income taxes. Types of and Accounting for Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. See Note 10 for further discussion of PSCo’s risk management and derivative activities. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further discussion. Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Note 8 and 10 for further discussion. Cash and Cash Equivalents — PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. Inventory — All inventory is recorded at average cost. RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. PSCo acquires RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. PSCo follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 12 for further discussion of environmental costs. Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 8 for further discussion of benefit plans and other postretirement benefits. Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee. Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. |
Accounting Pronouncements
Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09) , which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, PSCo’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. PSCo is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall impacts of the Jan. 1, 2018 adoption will not be material. Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. PSCo has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. PSCo expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard. Presentation of Net Periodic Benefit Cost — I n March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07) , which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Recently Adopted Accounting for the TCJA — In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 7 to the consolidated financial statements. Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. PSCo adopted the guidance in the fourth quarter of 2017, and elected to recognize a $4.7 million increase to accumulated other comprehensive loss and retained earnings in the consolidated financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 12 Months Ended |
Dec. 31, 2017 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 314,009 $ 324,512 Less allowance for bad debts (19,606 ) (19,612 ) $ 294,403 $ 304,900 (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 68,940 $ 66,161 Fuel 73,893 66,429 Natural gas 71,656 69,630 $ 214,489 $ 202,220 (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 12,627,592 $ 12,304,436 Natural gas plant 4,102,075 3,710,772 Common and other property 1,022,333 919,955 Plant to be retired (a) 10,949 31,839 Construction work in progress 1,014,338 484,340 Total property, plant and equipment 18,777,287 17,451,342 Less accumulated depreciation (4,751,536 ) (4,601,543 ) $ 14,025,751 $ 12,849,799 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2017. Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 250 $ 250 $ 250 Amount outstanding at period end — — — Average amount outstanding — 21 1 Maximum amount outstanding 20 141 34 Weighted average interest rate, computed on a daily basis 0.92 % 0.73 % 0.41 % Weighted average interest rate at period end N/A N/A N/A Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. PSCo had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017. Commercial paper borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 700 $ 700 $ 700 Amount outstanding at period end — 129 14 Average amount outstanding 54 24 95 Maximum amount outstanding 268 154 449 Weighted average interest rate, computed on a daily basis 1.08 % 0.70 % 0.51 % Weighted average interest rate at period end N/A 0.95 0.60 Letters of Credit — PSCo uses letters of credit, generally with terms of one -year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2017 and 2016, there were $3 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. PSCo has the right to request an extension of the June 2021 termination date for two additional one -year periods. The extension requests are subject to majority bank group approval. Other features of PSCo’s credit facility include: • PSCo may increase its credit facility by up to $100 million . • The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent . PSCo was in compliance as its debt-to-total capitalization ratio was 44 percent and 45 percent at Dec. 31, 2017 and 2016, respectively. If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. • The credit facility has a cross-default provision that provides PSCo will be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15 percent of PSCo’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million . • PSCo was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016. At Dec. 31, 2017 , PSCo had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 700 $ 3 $ 697 (a) This credit facility matures in June 2021 . (b) Includes letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at Dec. 31, 2017 and 2016 . Long-Term Borrowings Generally, all real and personal property of PSCo is subject to the liens of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. In 2017, PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047 . In 2016, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046 . During the next five years, PSCo has long-term debt maturities of $300 million , $400 million , $400 million and $300 million due in 2018, 2019, 2020 and 2022, respectively. Deferred Financing Costs — Deferred financing costs of approximately $29 million and $27 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2017 and 2016 , respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt. Dividend Restrictions — PSCo’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Preferred Stock | Preferred Stock PSCo has authorized the issuance of preferred stock. Preferred Par Value Preferred 10,000,000 $ 0.01 None |
Joint Ownership of Generation,
Joint Ownership of Generation, Transmission and Gas Facilities Joint Ownership of Generation, Transmission and Gas Facilities | 12 Months Ended |
Dec. 31, 2017 | |
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract] | |
Joint Ownership of Generation, Transmission and Gas Facilities | Joint Ownership of Generation, Transmission and Gas Facilities Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017 : (Thousands of Dollars) Plant in Service Accumulated CWIP Ownership % Electric Generation: Hayden Unit 1 $ 150,441 $ 72,042 $ 830 76 % Hayden Unit 2 148,694 65,493 18 37 Hayden Common Facilities 39,321 19,886 97 53 Craig Units 1 and 2 80,650 38,666 — 10 Craig Common Facilities 1, 2 and 3 38,902 20,116 — 7 Comanche Unit 3 889,630 117,759 476 67 Comanche Common Facilities 24,421 2,092 2,809 82 Electric Transmission: Transmission and other facilities, including substations 176,873 67,637 638 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 21,532 7,579 — 60 Gas Transportation Compressor 8,417 616 — 50 Total $ 1,578,881 $ 411,886 $ 4,868 PSCo has approximately 816 MW of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing. |
Income Taxes Income Taxes
Income Taxes Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Federal Tax Reform — In December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, the key provisions impacting Xcel Energy (which includes PSCo), generally beginning in 2018, include: • Corporate federal tax rate reduction from 35 percent to 21 percent ; • Normalization of resulting plant-related excess deferred taxes; • Elimination of the corporate alternative minimum tax; • Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; • Limitations on certain executive compensation deductions; • Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80 percent of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates. Overall for Xcel Energy, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers. The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at PSCo included: • $1.1 billion ( $1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21 percent federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property; • $54 million and $50 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; • $18 million of total estimated income tax benefit related to the federal tax reform implementation, and a $4 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes. Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted. Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following: • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; • PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019; • ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter; • R&E credit was permanently extended; and • Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans. The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment. Federal Audit — PSCO is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020 In 2012, the IRS commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec. 31, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain. State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2017, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009 . There are currently no state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 4.0 $ 2.9 Unrecognized tax benefit — Temporary tax positions 6.1 16.8 Total unrecognized tax benefit $ 10.1 $ 19.7 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 19.7 $ 17.4 $ 11.9 Additions based on tax positions related to the current year 1.9 2.7 4.5 Reductions based on tax positions related to the current year (1.5 ) — (1.5 ) Additions for tax positions of prior years 4.4 0.5 2.5 Reductions for tax positions of prior years (14.4 ) (0.9 ) — Balance at Dec. 31 $ 10.1 $ 19.7 $ 17.4 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (4.0 ) $ (5.8 ) It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and the IRS and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows: (Millions of Dollars) 2017 2016 2015 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (1.1 ) $ (0.4 ) $ (0.2 ) Interest income (expense) related to unrecognized tax benefits 0.8 (0.7 ) (0.2 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (0.3 ) $ (1.1 ) $ (0.4 ) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016 or 2015. Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2017 2016 Federal NOL carryforward $ 68 $ 260 Federal tax credit carryforwards 30 25 State NOL carryforwards 679 684 State tax credit carryforwards, net of federal detriment (a) 17 13 Valuation allowances for state credit carryforwards, net of federal detriment (b) (7 ) (3 ) (a) State tax credit carryforwards are net of federal detriment of $4 million and $7 million as of Dec. 31, 2017 and 2016, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $2 million as of Dec. 31, 2017 and 2016, respectively. The federal carryforward periods expire between 2021 and 2037 . The state carryforward periods expire between 2018 and 2033 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 3.0 % 3.0 % 3.0 % Increases (decreases) in tax from: Tax reform (2.4 ) — — Tax credits recognized, net of federal income tax expense (0.9 ) (0.7 ) (0.7 ) Regulatory differences - effects of rate changes (a) (0.1 ) (0.1 ) (0.1 ) Regulatory differences - other utility plant items (0.9 ) (0.5 ) (0.3 ) Change in unrecognized tax benefits 0.2 — 0.1 Other, net (0.1 ) 0.4 0.4 Effective income tax rate 33.8 % 37.1 % 37.4 % (a) The amortization of excess deferred taxes. (b) The prior periods included in this footnote have been reclassified to conform to current year presentation. The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 40,386 $ 45,287 $ (1,166 ) Current state tax expense (benefit) 14,577 8,754 (727 ) Current change in unrecognized tax (benefit) expense (7,798 ) 680 5,244 Deferred federal tax expense 176,410 195,064 246,096 Deferred state tax expense 22,513 27,216 36,450 Deferred change in unrecognized tax expense (benefit) 8,894 (278 ) (4,650 ) Deferred investment tax credits (2,803 ) (2,805 ) (2,807 ) Total income tax expense $ 252,179 $ 273,918 $ 278,440 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (1,244,653 ) $ 230,931 $ 285,144 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 1,453,080 (8,418 ) (7,229 ) Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (610 ) (511 ) (19 ) Deferred tax expense $ 207,817 $ 222,002 $ 277,896 The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2017 2016 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 1,797,023 $ 2,967,162 Regulatory assets 252,353 102,967 Pension expense 60,032 10,016 Other 3,994 3,920 Total deferred tax liabilities $ 2,113,402 $ 3,084,065 Deferred tax assets: Regulatory liabilities $ 337,973 $ (35,813 ) NOL carryforward 39,347 115,328 Tax credit carryforward 39,323 34,658 Deferred investment tax credits 6,872 11,653 Other employee benefits 6,779 15,274 Deferred fuel costs 6,523 10,070 Rate refund 890 7,221 Other 31,219 36,545 Total deferred tax assets $ 468,926 $ 194,936 Net deferred tax liability $ 1,644,476 $ 2,889,129 (a) The prior period included in this footnote has been reclassified to conform to current year presentation. |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees. Xcel Energy, which includes PSCo, offers various benefit plans to its employees. Approximately 76 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, PSCo had 1,835 bargaining employees covered under a collective-bargaining agreement, which expired in May 2017. While collective bargaining is ongoing, the terms and conditions of the agreement are automatically extended. The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days ’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45 - 90 days ’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Pension Benefits Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and PSCo’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to PSCo funded by PSCo’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million , respectively, of which $3 million and $4 million were attributable to PSCo. In 2017 and 2016 , Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million , respectively, of which $1 million in each year was attributable to PSCo. In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to PSCo will be supplemented by PSCo’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to PSCo is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options. Xcel Energy Inc. and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20 -year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and PSCo continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term. • Investment returns in 2017 were above the assumed level of 6.84 percent ; • Investment returns in 2016 were below the assumed level of 6.84 percent ; • Investment returns in 2015 were below the assumed level of 6.81 percent ; and • In 2018 , PSCo’s expected investment-return assumption is 6.84 percent . The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year. The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 34 % 36 % Long-duration fixed income and interest rate swap securities 32 31 Short-to-intermediate fixed income securities 18 15 Alternative investments 14 16 Cash 2 2 Total 100 % 100 % The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. Pension Plan Assets The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 67,179 $ — $ — $ — $ 67,179 Commingled funds: U.S. equity funds 169,624 — — — 169,624 Non U.S. equity funds 30,277 — — 65,822 96,099 U.S. corporate bond funds 137,086 — — — 137,086 Emerging market equity funds — — — 103,876 103,876 Emerging market debt funds 24,825 — — 54,954 79,779 Private equity investments — — — 27,816 27,816 Real estate — — — 64,500 64,500 Other commingled funds 1,601 — — 38,545 40,146 Debt securities: Government securities — 144,333 — — 144,333 U.S. corporate bonds — 102,659 — — 102,659 Non U.S. corporate bonds — 16,792 — — 16,792 Equity securities: U.S. equities 37,752 — — — 37,752 Other (9,885 ) 1,414 — 180 (8,291 ) Total $ 458,459 $ 265,198 $ — $ 355,693 $ 1,079,350 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 34,957 $ — $ — $ — $ 34,957 Commingled funds: U.S. equity funds 165,621 — — — 165,621 Non U.S. equity funds 64,710 — — 57,487 122,197 U.S. corporate bond funds 96,995 — — — 96,995 Emerging market equity funds — — — 64,784 64,784 Emerging market debt funds 25,866 — — 27,837 53,703 Commodity funds — — — 7,497 7,497 Private equity investments — — — 31,828 31,828 Real estate — — — 61,048 61,048 Other commingled funds — — — 74,696 74,696 Debt securities: Government securities — 168,014 — — 168,014 U.S. corporate bonds — 86,081 — — 86,081 Non U.S. corporate bonds — 13,828 — — 13,828 Mortgage-backed securities — 2,179 — — 2,179 Asset-backed securities — 1,032 — — 1,032 Equity securities: U.S. equities 27,348 — — — 27,348 Other — (7,595 ) — — (7,595 ) Total $ 415,497 $ 263,539 $ — $ 325,177 $ 1,004,213 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017 , 2016 or 2015 . Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 1,285,010 $ 1,213,890 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 1,251,822 $ 1,224,650 Service cost 27,280 25,926 Interest cost 50,558 55,405 Transfer to other plan — (9,149 ) Plan amendments (1,096 ) 206 Actuarial loss 83,531 51,779 Benefit payments (77,915 ) (96,995 ) Obligation at Dec. 31 $ 1,334,180 $ 1,251,822 (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 1,004,213 $ 1,036,681 Actual return on plan assets 135,552 56,762 Employer contributions 17,500 16,829 Transfer to other plan — (9,064 ) Benefit payments (77,915 ) (96,995 ) Fair value of plan assets at Dec. 31 $ 1,079,350 $ 1,004,213 (Thousands of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (a) $ (254,830 ) $ (247,609 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 543,707 $ 554,999 Prior service credit (10,593 ) (12,155 ) Total $ 533,114 $ 542,844 (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 27,662 $ 26,853 Noncurrent regulatory assets 505,171 515,708 Deferred income taxes 69 108 Net-of-tax accumulated OCI 212 175 Total $ 533,114 $ 542,844 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP-2014 RP-2014 Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, PSCo adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). PSCo evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of PSCo’s population. Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $150 million in January 2018, of which $22 million was attributable to PSCo; • $162 million in 2017, of which $18 million was attributable to PSCo; • $125 million in 2016, of which $17 million was attributable to PSCo; and • $90 million in 2015, of which $20 million was attributable to PSCo. For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary. Plan Amendments — Xcel Energy, which includes PSCo, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased. Benefit Costs — The components of PSCo’s net periodic pension cost were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 27,280 $ 25,926 $ 28,260 Interest cost 50,558 55,405 50,857 Expected return on plan assets (68,535 ) (70,769 ) (72,590 ) Amortization of prior service credit (3,211 ) (3,211 ) (3,136 ) Amortization of net loss 28,355 26,771 36,377 Net periodic pension cost 34,447 34,122 39,768 (Costs) credits not recognized due to effects of regulation (2,631 ) 3,364 (1,464 ) Net benefit cost recognized for financial reporting $ 31,816 $ 37,486 $ 38,304 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 6.84 6.84 6.81 In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to PSCo were $18 million , $9 million and $10 million in 2017 , 2016 and 2015 , respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.84 percent . The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees. Defined Contribution Plans Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for PSCo was approximately $10 million in 2017 , 2016 and 2015 . Postretirement Health Care Benefits Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for PSCo nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % Xcel Energy Inc. and PSCo base the investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year. The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 25,724 $ — $ — $ — $ 25,724 Insurance contracts — 43,524 — — 43,524 Commingled funds: U.S. equity funds 64,899 — — — 64,899 U.S fixed income funds 29,946 — — — 29,946 Emerging market debt funds 35,402 — — — 35,402 Debt securities: Government securities — 50,576 — — 50,576 U.S. corporate bonds — 55,323 — — 55,323 Non U.S. corporate bonds — 18,712 — — 18,712 Asset-backed securities — 20,468 — — 20,468 Mortgage-backed securities — 30,231 — — 30,231 Equity securities: Non U.S. equities 30,671 — — — 30,671 Other — 948 — — 948 Total $ 186,642 $ 219,782 $ — $ — $ 406,424 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 18,288 $ — $ — $ — $ 18,288 Insurance contracts — 42,046 — — 42,046 Commingled funds: U.S. equity funds 48,462 — — — 48,462 U.S fixed income funds 24,132 — — — 24,132 Emerging market debt funds 27,089 — — — 27,089 Other commingled funds — — — 48,922 48,922 Debt securities: Government securities — 33,600 — — 33,600 U.S. corporate bonds — 55,473 — — 55,473 Non U.S. corporate bonds — 15,384 — — 15,384 Asset-backed securities — 16,845 — — 16,845 Mortgage-backed securities — 25,563 — — 25,563 Equity securities: Non U.S. equities 36,462 — — — 36,462 Other — 1,289 — — 1,289 Total $ 154,433 $ 190,200 $ — $ 48,922 $ 393,555 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017 , 2016 or 2015 . Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 421,823 $ 403,574 Service cost 767 768 Interest cost 16,765 18,070 Medicare subsidy reimbursements 993 1,901 Plan participants’ contributions 5,971 5,376 Actuarial loss 18,314 27,355 Benefit payments (35,386 ) (35,221 ) Obligation at Dec. 31 $ 429,247 $ 421,823 (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 393,555 $ 399,442 Actual return on plan assets 36,975 18,590 Plan participants’ contributions 5,971 5,376 Employer contributions 5,309 5,368 Benefit payments (35,386 ) (35,221 ) Fair value of plan assets at Dec. 31 $ 406,424 $ 393,555 (Thousands of Dollars) 2017 2016 Funded Status at Dec. 31: Funded status (a) $ (22,823 ) $ (28,268 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively. (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 77,760 $ 78,359 Prior service credit (21,448 ) (27,695 ) Total $ 56,312 $ 50,664 (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Noncurrent regulatory assets $ 56,312 $ 50,664 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial: Pre-65 7.00 % 5.50 % Health care costs trend rate — initial: Post-65 5.50 % 5.50 % Beginning with the Dec. 31 2017 measurement, Xcel Energy Inc. and PSCo separated its initial medical trend assumption for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent , respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percent for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period until the ultimate rate is reached is five years . Xcel Energy Inc. and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan. A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo: One-Percentage Point (Thousands of Dollars) Increase Decrease APBO $ 41,665 $ (35,254 ) Service and interest components 1,837 (1,555 ) Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes PSCo, contributed $20 million , $18 million and $18 million during 2017 , 2016 and 2015 , respectively, of which $5 million , $5 million and $6 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12 million during 2018 , of which amounts attributable to PSCo will be zero . Plan Amendments — In 2017 and 2016 there were no plan amendments made which affected the projected benefit obligation. Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 767 $ 768 $ 928 Interest cost 16,765 18,070 17,498 Expected return on plan assets (21,905 ) (22,299 ) (23,803 ) Amortization of prior service credit (6,247 ) (6,247 ) (6,247 ) Amortization of net loss 3,843 1,931 2,475 Net periodic postretirement benefit credit $ (6,777 ) $ (7,777 ) $ (9,149 ) 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80 In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to PSCo based on Xcel Energy Services Inc. employees’ labor costs. Projected Benefit Payments The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) Projected Pension Gross Projected Expected Medicare Net Projected 2018 $ 83,036 $ 32,186 $ 2,074 $ 30,112 2019 81,698 32,454 2,192 30,262 2020 81,413 32,767 2,296 30,471 2021 82,021 32,737 2,404 30,333 2022 83,261 32,998 2,501 30,497 2023-2027 411,798 152,926 13,789 139,137 |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Derivative Instruments Fair Value Measurements PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At Dec. 31, 2017, accumulated other comprehensive losses related to interest rate derivatives included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel. PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded no amounts to income related to the ineffectiveness of cash flow hedges for the year ended Dec. 31, 2017 and immaterial amounts for the year ended Dec. 31, 2016. Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards and options at Dec. 31: (Amounts in Thousands) (a)(b) 2017 2016 MWh of electricity 22,260 6,283 MMBtu of natural gas 13,410 42,203 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2017, five of PSCo’s 10 most significant counterparties for these activities, comprising $7.0 million or 16 percent of this credit exposure, had investment grade credit ratings from S&P’s, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $16.5 million or 37 percent of this credit exposure at Dec. 31, 2017 were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $7.4 million or 17 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Six of these significant counterparties are municipal or cooperative electric entities, or other utilities. Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Thousands of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (22,780 ) $ (23,836 ) $ (23,878 ) After-tax net unrealized losses related to derivatives accounted for as hedges — — (30 ) After-tax net realized losses on derivative transactions reclassified into earnings 1,005 1,056 72 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (21,775 ) $ (22,780 ) $ (23,836 ) The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2017 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,615 (a) $ — $ — Total $ — $ — $ 1,615 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 386 (c) Natural gas commodity — (10,921 ) — 1,933 (d) (4,170 ) (d) Total $ — $ (10,921 ) $ — $ 1,933 $ (3,784 ) Year Ended Dec. 31, 2016 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,618 (a) $ — $ — Vehicle fuel and other commodity — — 86 (b) — — Total $ — $ — $ 1,704 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (257 ) (c) Natural gas commodity — 2,051 — 10,292 (d) (5,832 ) (d) Total $ — $ 2,051 $ — $ 10,292 $ (6,089 ) Year Ended Dec. 31, 2015 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized Derivatives designated as cash flow hedges Interest rate $ — $ — $ 54 (a) $ — $ — Vehicle fuel and other commodity (50 ) — 57 (b) — — Total $ (50 ) $ — $ 111 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 364 (c) Natural gas commodity — (10,635 ) — 10,158 (d) (7,620 ) (d) Total $ — $ (10,635 ) $ — $ 10,158 $ (7,256 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2017 included $0.4 million of settlement gains and amounts for the years ended Dec. 31, 2016 and 2015 included $0.2 million and $1.1 million , respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At Dec. 31, 2017 and 2016, there were no derivative instruments in a material liability position with such underlying contract provisions. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2017 and 2016. Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2017: Dec. 31, 2017 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Commodity trading $ 528 $ 4,488 $ 12 $ 5,028 $ (3,554 ) $ 1,474 Natural gas commodity — 18 — 18 (10 ) 8 Total current derivative assets $ 528 $ 4,506 $ 12 $ 5,046 $ (3,564 ) 1,482 PPAs (a) 1,715 Current derivative instruments $ 3,197 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 1,541 $ — $ 1,541 $ (563 ) $ 978 Total noncurrent derivative assets $ — $ 1,541 $ — $ 1,541 $ (563 ) 978 PPAs (a) 31 Noncurrent derivative instruments $ 1,009 Current derivative liabilities Other derivative instruments: Commodity trading $ 446 $ 4,285 $ 6 $ 4,737 $ (3,431 ) $ 1,306 Natural gas commodity — 1,016 — 1,016 (10 ) 1,006 Total current derivative liabilities $ 446 $ 5,301 $ 6 $ 5,753 $ (3,441 ) 2,312 PPAs (a) 5,036 Current derivative instruments $ 7,348 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 1,362 $ — $ 1,362 $ (563 ) $ 799 Total noncurrent derivative liabilities $ — $ 1,362 $ — $ 1,362 $ (563 ) 799 PPAs (a) $ 2,669 Noncurrent derivative instruments $ 3,468 (a) During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016: Dec. 31, 2016 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Commodity trading $ 1,124 $ 5,453 $ — $ 6,577 $ (5,137 ) $ 1,440 Natural gas commodity — 7,778 — 7,778 — 7,778 Total current derivative assets $ 1,124 $ 13,231 $ — $ 14,355 $ (5,137 ) 9,218 PPAs (a) 1,716 Current derivative instruments $ 10,934 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 1,652 $ — $ 1,652 $ — $ 1,652 Total noncurrent derivative assets $ — $ 1,652 $ — $ 1,652 $ — 1,652 PPAs (a) 1,746 Noncurrent derivative instruments $ 3,398 Current derivative liabilities Other derivative instruments: Commodity trading $ 1,386 $ 5,357 $ 22 $ 6,765 $ (5,137 ) $ 1,628 Total current derivative liabilities $ 1,386 $ 5,357 $ 22 $ 6,765 $ (5,137 ) 1,628 PPAs (a) 5,160 Current derivative instruments $ 6,788 Noncurrent derivative liabilities PPAs (a) $ 7,828 Noncurrent derivative instruments $ 7,828 (a) During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. There were immaterial gains recognized in earnings for the year ended Dec. 31, 2017 and immaterial losses recognized in earnings for the year ended Dec. 31, 2016 for level 3 commodity trading derivatives. There were no changes in Level 3 recurring fair value measurements for the year ended Dec. 31, 2015. PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2017, 2016 and 2015. Fair Value of Long-Term Debt As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,608,275 $ 5,024,840 $ 4,216,206 $ 4,491,570 The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2017 and 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other Income, Net Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2017 2016 2015 Interest income $ 3,809 $ 1,860 $ 753 Other nonoperating income 6,383 2,241 2,408 Insurance policy expense (340 ) (281 ) (197 ) Other nonoperating expense — (3 ) — Other income, net $ 9,852 $ 3,817 $ 2,964 |
Rate Matters
Rate Matters | 12 Months Ended |
Dec. 31, 2017 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Tax Reform — Regulatory Proceedings The specific impacts of the TCJA on retail customer rates are subject to regulatory approval. PSCo is in the process of quantifying the rate impacts of the TCJA and are being addressed in several regulatory proceedings focused on retail base rate impacts, which include the following: • Colorado Statewide TCJA Proceeding — On Jan. 31, 2018, the CPUC opened a statewide TCJA proceeding and ordered deferred accounting for all investor-owned utilities. On Feb. 21, 2017, PSCo filed a response with the CPUC related to the deferred accounting order and statewide TCJA proceeding, addressing the estimated impacts along with other considerations given PSCo’s pending natural gas and electric rate cases. • Colorado 2017 Multi-Year Natural Gas Rate Case — On Feb. 14, 2018, the ALJ approved PSCo and CPUC Staff’s non-unanimous settlement agreement which addresses the impacts of the TCJA in 2018. This settlement agreement includes a $20 million reduction to provisional rates effective March 1, 2018, with future true-ups to be determined later in 2018 once a full analysis of the comprehensive impacts of tax reform is performed, including any outcomes associated with statewide proceeding. The final true-up would provide customers the full net benefit of the TCJA effective Jan. 1, 2018. • Colorado 2017 Multi-Year Electric Rate Case — On Feb. 16, 2018, the CPUC denied the proposed settlement agreement between PSCo and several intervenors, in favor of the state TCJA proceeding. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. Provisional rates, subject to refund with interest, are expected to be effective June 1, 2018. The appropriate test year and the final approved revenue requirement will be determined in the pending rate case, discussed below. PSCo expects to defer the TCJA net benefits for the first five months of 2018, prior to provisional rates. The CPUC is expected to rule on the regulatory treatment of the TCJA, the natural gas rate case and the electric rate case later in 2018. Pending Regulatory Proceedings — CPUC Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years . The request, summarized below, is based on FTY ending Dec. 31, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 CACJA revenue conversion to base rates (a) 90 — — — 90 TCA revenue conversion to base rates (a) 43 — — — 43 Total (b) $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) (b) $ 6.8 $ 7.1 $ 7.3 $ 7.4 (a) The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. (b) This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. Key dates in the procedural schedule are as follows: • Supplemental direct testimony — April 16, 2018; • Answer testimony — May 31, 2018; • Rebuttal and cross-answer testimony — July 10, 2018; • Hearings — Aug. 21 - 31, 2018; and • Statement of position — Sept. 28, 2018. Interim rates, subject to refund and interest, are to be effective on June 1, 2018. PSCo also proposed a stay-out provision and earnings test through 2021. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. The CPUC is expected to rule on the regulatory treatment of the TCJA and the electric rate case later in 2018. Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years . The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 PSIA revenue conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the OCC, recommended a single 2016 HTY, based on an average 13 -month rate base, and opposed a multi-year request. The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent , respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case. The final positions of the Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million , respectively. In December 2017, hearings before an ALJ were held and the evidentiary record for the case was closed. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. As discussed above, PSCo and the CPUC Staff filed a non-unanimous settlement agreement to address the impacts of the TCJA on rates to be effective in 2018, which was approved by the ALJ. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018. Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. PSCo estimates the 2017 earnings test will not result in a customer refund obligation. PSCo will file its 2017 earnings test with the CPUC in April 2018. The final sharing obligation, if any, will be based on the CPUC approved tariff and could vary from the current estimate. Electric, Purchased Gas and Resource Adjustment Clauses DSM and the DSMCA riders — Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Performance incentives are awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million . In 2017, PSCo earned an electric and natural gas DSM incentive of $11 million and $3 million , respectively, for achieving its 2016 electric and natural gas savings goals. For 2018, the electric energy savings goal is 400 GWh with a spending limit of $84 million . |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Commitments Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to the following major projects: Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures. Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado. Gas Transmission Integrity Management Programs — PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects. Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance. Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2060 . PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements. The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2017 , are as follows: (Millions of Dollars) Coal Natural gas supply Natural gas 2018 $ 160 $ 344 $ 114 2019 97 286 112 2020 69 275 111 2021 37 278 109 2022 38 126 109 Thereafter 184 57 605 Total $ 585 $ 1,366 $ 1,160 Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. PSCo’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers. PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2034 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms. Included in electric fuel and purchased power expenses for PPAs, accounted for as executory contracts, were payments for capacity of $25 million , $44 million and $70 million in 2017 , 2016 and 2015 , respectively. At Dec. 31, 2017 , the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity 2018 $ 22 2019 12 2020 4 2021 4 2022 4 Thereafter 14 Total $ 60 Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand. Leases — PSCo leases a variety of equipment and facilities. Three of these leases are accounted for as capital leases. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract. WYCO is a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company, LLC (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $124 million and $127 million of capital lease obligations as of Dec. 31, 2017 and 2016 , respectively. PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $5 million , $8 million , and $8 million for 2017 , 2016 and 2015 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Gas storage facilities $ 200.5 $ 200.5 Gas pipeline 20.7 20.7 Property held under capital leases 221.2 221.2 Accumulated depreciation (70.6 ) (65.3 ) Total property held under capital leases, net $ 150.6 $ 155.9 The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $109 million , $118 million and $130 million for 2017 , 2016 and 2015 , respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $96 million , $102 million and $114 million in 2017 , 2016 and 2015 , respectively, recorded to electric fuel and purchased power expenses. Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are: (Millions of Dollars) Operating Leases PPA (a) (b) Operating Leases Total Operating Leases Capital Leases 2018 $ 10 $ 96 $ 106 $ 25 2019 10 97 107 25 2020 10 98 108 25 2021 9 99 108 24 2022 8 87 95 21 Thereafter 34 394 428 442 Total minimum obligation 562 Interest component of obligation (411 ) Present value of minimum obligation $ 151 (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2034 . Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary. PPAs — Under certain PPAs, PSCo purchases power from independent power producing entities for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the independent power producing entity. PSCo has determined that certain independent power producing entities are variable interest entities. PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs. PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,571 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032 . Environmental Contingencies PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense. Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent wastes to that site. Other MGP, Landfill or Disposal Sites — PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified three sites where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. PSCo anticipates that these investigation or remediation activities will continue through at least 2018. PSCo had accrued an immaterial amount and $2 million for all of these sites as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers. Environmental Requirements Water and Waste Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule). Industry and environmental non-governmental organizations sought judicial review of the final CCR Rule, but a final decision has not been issued in that litigation. The EPA announced in late 2017 its intent to revise the CCR Rule. It is anticipated that the EPA will publish the revised rule in the first quarter of 2018. Under the CCR Rule, utilities were required to complete groundwater sampling around their CCR landfills and surface impoundments and to analyze the results by early 2018 to determine if there were any statistically significant increases (SSIs) above background levels of certain constituents in the groundwater. PSCo has identified SSIs at several sites. Going forward, PSCo will either conduct additional groundwater sampling to determine whether another source besides plant operations is impacting groundwater and/or to determine if corrective action is needed. Several PSCo sites where SSIs were identified were already undergoing cessation of coal operations and closure of the on-site coal units and therefore no further corrective action is expected at those sites. Until a final decision is reached in the litigation, the EPA publishes its revised rule, and PSCo completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows of PSCo. PSCo believes that any associated costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018. In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.” Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). PSCo does not anticipate the cost of compliance will have a material impact on its results of operations, financial position or cash flows. Air GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP. In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include. Implementation of the NAAQS for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010, and evaluated areas in in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near PSCo’s generating plants as meeting the SO 2 NAAQS with one exception. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” Since the 2016 “unclassifiable” designation, the Colorado Department of Public Health and Environment has prepared and submitted air dispersion modeling to the EPA demonstrating that the area near the Pawnee plant meets the SO 2 NAAQS. The EPA has not yet completed its evaluation of the Pawnee plant. Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. The EPA has not yet taken final action on the designation, but notified the State of Colorado in December 2017 that it intends to designate the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard. Asset Retirement Obligations Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas storage, thermal and common general property. The electric production obligations include asbestos, processed water and ash-containment facilities, radiation sources, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to processed water and ash-containment facilities such as ash ponds, evaporation ponds and solid waste landfills. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract. PSCo recognized AROs for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering equipment, impoundments at gas extraction sites and wells related to gas storage facilities. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, lithium batteries, mercury and street lighting lamps. The common general ARO includes obligations related to storage tanks. A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2017 Liabilities (a) Accretion Cash Flow Revisions (b) Ending Balance Dec. 31, 2017 (c) Electric plant Steam and other production ash containment $ 72,600 $ (12,068 ) $ 3,159 $ 9,573 $ 73,264 Steam, hydro, and other production asbestos 40,450 (12,047 ) 1,917 (458 ) 29,862 Electric distribution 7,669 — 274 — 7,943 Wind production 2,072 — 20 — 2,092 Other 1,520 (204 ) 66 — 1,382 Natural gas plant Gas transmission and distribution 160,719 — 6,649 61,503 228,871 Other 4,080 (354 ) 159 — 3,885 Common and other property Common miscellaneous 453 — 17 — 470 Total liability $ 289,563 $ (24,673 ) $ 12,261 $ 70,618 $ 347,769 (a) The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. (b) In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. (c) There were no ARO liabilities recognized during the year ended Dec. 31, 2017. (Thousands of Dollars) Beginning Balance Jan. 1, 2016 Liabilities Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2016 (b) Electric plant Steam, hydro, and other production asbestos $ 38,676 $ — $ 1,877 $ (103 ) $ 40,450 Steam and other production ash containment 70,767 — 3,078 (1,245 ) 72,600 Wind production 1,992 — 19 61 2,072 Electric distribution 1,130 — 45 6,494 7,669 Other 1,054 214 46 206 1,520 Natural gas plant Gas transmission and distribution 122,168 — 5,009 33,542 160,719 Other 3,925 — 155 — 4,080 Common and other property Common miscellaneous 796 — 28 (371 ) 453 Total liability $ 240,508 $ 214 $ 10,257 $ 38,584 $ 289,563 (a) In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains. (b) There were no ARO liabilities settled during the year ended Dec. 31, 2016. Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities. Removal Costs — PSCo records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2017 and 2016 were $346 million and $367 million , respectively. Legal Contingencies PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves claims by over fifty developers. In May 2016, the Denver District Court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the Denver District Court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. In February 2018, the Colorado Supreme Court denied DRC’s petition effectively terminating this litigation. In January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. Dates for this proceeding have not been scheduled. PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter. Other Contingencies See Note 11 for further discussion. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | 13. Regulatory Assets and Liabilities PSCo’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of PSCo no longer allow for the application of regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI. The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 8 Various $ 28,010 $ 565,241 $ 27,270 $ 568,258 Recoverable deferred taxes on AFUDC recorded in plant (b) 1 Plant lives — 86,966 — 151,022 Net AROs (c) 1, 12 Plant lives — 80,476 — 78,050 Depreciation differences 1 One to fourteen years 19,835 69,428 15,363 90,426 Excess deferred taxes - TCJA 7 Various — 53,937 — — Purchased power contract costs 12 Term of related contract 1,261 28,009 1,035 29,029 Property tax Pending rate cases — 16,047 9,393 1,653 Gas pipeline inspection costs 12 One to two years 1,791 7,743 — 4,405 Conservation programs (d) 1, 11 One to two years 6,942 5,528 9,262 6,986 Losses on reacquired debt 4 Term of related debt 1,203 4,916 1,203 6,120 Contract valuation adjustments (e) 10 Term of related contract 6,022 2,638 3,444 6,082 Other Various 12,273 29,329 36,813 16,398 Total regulatory assets $ 77,337 $ 950,258 $ 103,783 $ 958,429 (a) Includes $3.4 million and $4.2 million of regulatory assets related to the nonqualified pension plan, of which $0.3 million and $0.4 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. (b) Includes a write-down of $75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. (c) Includes amounts recorded for future recovery of AROs. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (e) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 7 Various $ — $ 1,445,079 $ — $ — Plant removal costs 1, 12 Plant lives — 346,174 — 367,440 Renewable resources and environmental initiatives 11, 12 Various — 56,153 3,600 67,728 Investment tax credit deferrals 1, 7 Various — 17,088 — 18,797 Deferred income tax adjustment 1 Various — 16,301 — 16,260 Deferred electric, natural gas and steam production costs 1 Less than one year 29,078 — 35,123 — Conservation programs (b) 1, 11 Less than one year 21,168 — 24,077 — Other Various 15,880 52,693 38,310 42,708 Total regulatory liabilities (c) $ 66,126 $ 1,933,488 $ 101,110 $ 512,933 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $49.6 million revaluation impact of non-plant ADIT at Dec. 31, 2017. (b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (c) Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. At Dec. 31, 2017 and 2016, approximately $44 million and $28 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with property taxes and renewable resources and environmental initiatives. |
Other Comprehensive Income
Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | 14. Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Year Ended Dec. 31, 2017 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (22,780 ) $ (220 ) $ (23,000 ) Other comprehensive loss before reclassifications — (5 ) (5 ) Losses reclassified from net accumulated other comprehensive loss 1,005 5 1,010 Net current period other comprehensive income 1,005 — 1,005 Adoption of ASU No. 2018-02 (a) (4,690 ) (47 ) (4,737 ) Accumulated other comprehensive loss at Dec. 31 $ (26,465 ) $ (267 ) $ (26,732 ) (a) In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Year Ended Dec. 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (23,836 ) $ — $ (23,836 ) Other comprehensive loss before reclassifications — (223 ) (223 ) Losses reclassified from net accumulated other comprehensive loss 1,056 3 1,059 Net current period other comprehensive income (loss) 1,056 (220 ) 836 Accumulated other comprehensive loss at Dec. 31 $ (22,780 ) $ (220 ) $ (23,000 ) Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses (gains) on cash flow hedges: Interest rate derivatives $ 1,615 (a) $ 1,618 (a) Vehicle fuel derivatives — (b) 86 (b) Total, pre-tax 1,615 1,704 Tax benefit (610 ) (648 ) Total, net of tax 1,005 1,056 Defined benefit pension and postretirement losses (gains): Amortization of net losses 9 (c) 5 (c) Total, pre-tax 9 5 Tax benefit (4 ) (2 ) Total, net of tax 5 3 Total amounts reclassified, net of tax $ 1,010 $ 1,059 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans. |
Segments and Related Informatio
Segments and Related Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Segments and Related Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations. • PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities. Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. The accounting policies of the segments are the same as those described in Note 1. (Thousands of Dollars) Regulated Regulated All Other Reconciling Consolidated 2017 Operating revenues (a) $ 3,003,808 $ 995,214 $ 43,487 $ — $ 4,042,509 Intersegment revenues 288 344 — (632 ) — Total revenues $ 3,004,096 $ 995,558 $ 43,487 $ (632 ) $ 4,042,509 Depreciation and amortization $ 353,560 $ 113,253 $ 4,702 $ — $ 471,515 Interest charges and financing costs 138,565 40,214 508 — 179,287 Income tax expense (benefit) 243,604 18,398 (9,823 ) — 252,179 Net income 370,636 107,822 15,661 — 494,119 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues (a) $ 3,049,352 $ 957,721 $ 40,723 $ — $ 4,047,796 Intersegment revenues 275 110 — (385 ) — Total revenues $ 3,049,627 $ 957,831 $ 40,723 $ (385 ) $ 4,047,796 Depreciation and amortization $ 337,583 $ 101,663 $ 4,309 $ — $ 443,555 Interest charges and financing costs 136,274 37,881 431 — 174,586 Income tax expense (benefit) 228,825 45,960 (867 ) — 273,918 Net income 383,973 75,426 4,092 — 463,491 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues (a) $ 3,115,257 $ 1,006,666 $ 41,590 $ — $ 4,163,513 Intersegment revenues 301 67 — (368 ) — Total revenues $ 3,115,558 $ 1,006,733 $ 41,590 $ (368 ) $ 4,163,513 Depreciation and amortization $ 311,122 $ 96,384 $ 4,161 $ — $ 411,667 Interest charges and financing costs 136,397 34,935 576 — 171,908 Income tax expense (benefit) 234,873 44,192 (625 ) — 278,440 Net income 391,257 74,267 1,278 — 466,802 (a) Operating revenues include $6 million , $13 million and $13 million of intercompany revenue for the years ended Dec. 31, 2017 , 2016 and 2015 , respectively. See Note 16 for further discussion of related party transactions by reportable segment. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 4 for further discussion. The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31: (Thousands of Dollars) 2017 2016 2015 Operating revenues: Electric $ 1,436 $ 8,809 $ 8,632 Other 4,492 4,525 4,441 Operating expenses: Purchased power 2 56 — Other operating expenses — paid to Xcel Energy Services Inc. 485,066 446,086 414,620 Interest expense — 149 211 Interest income — — 45 Accounts receivable and payable with affiliates at Dec. 31 were: 2017 2016 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 7,738 $ — $ 7,669 $ — NSP-Wisconsin 61 — 974 — SPS 279 — 745 — Other subsidiaries of Xcel Energy Inc. 6,641 58,748 33 98,797 $ 14,719 $ 58,748 $ 9,421 $ 98,797 |
Summarized Quarterly Financial
Summarized Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Thousands of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 1,080,534 $ 930,916 $ 1,030,293 $ 1,000,766 Operating income 212,422 192,811 326,028 154,669 Net income 111,546 100,587 186,077 95,909 Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 1,057,841 $ 909,852 $ 1,059,177 $ 1,020,926 Operating income 223,190 180,629 315,605 170,197 Net income 115,874 87,344 173,607 86,666 |
Schedule II, Valuation and Qual
Schedule II, Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
Valuation and Qualifying Accounts [Abstract] | |
Schedule II, Valuation and Qualifying Accounts | PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2017 , 2016 AND 2015 (amounts in thousands) Additions Balance at Jan. 1 Charged to Costs and Expenses Charged to Other Accounts (a) Deductions from Reserves (b) Balance at Dec. 31 Allowance for bad debts: 2017 $ 19,612 $ 14,303 $ 3,968 $ 18,277 $ 19,606 2016 20,122 14,121 4,447 19,078 19,612 2015 23,122 13,052 5,175 21,227 20,122 (a) Recovery of amounts previously written off. (b) Deductions relate primarily to bad debt write-offs. |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Business and System of Accounts | Business and System of Accounts — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. PSCo’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. |
Principles of Consolidation | Principles of Consolidation — PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 6 for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages. PSCo evaluates its arrangements and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if PSCo has a variable interest and if PSCo is the primary beneficiary. PSCo follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether PSCo is a variable interest entity’s primary beneficiary. See Note 12 for further discussion of variable interest entities. |
Use of Estimates | Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. |
Regulatory Accounting | Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations . Under this guidance: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s financial condition, results of operations and cash flows. See Note 13 for further discussion of regulatory assets and liabilities. |
Revenue Recognition | Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees. PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. |
Conservation Programs | Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures. The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers. |
Property, Plant and Equipment and Depreciation | Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. PSCo records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.7 , 2.6 and 2.7 percent for the years ended Dec. 31, 2017 , 2016 and 2015 , respectively. |
Leases | Leases — PSCo evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 12 for further discussion of leases. |
AFUDC | AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, including certain generation and transmission projects, the CPUC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, the CPUC has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. |
Asset Retirement Obligations | AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. PSCo also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 12 for further discussion of AROs. |
Income Taxes | Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including PSCo, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 7 for further discussion of income taxes. |
Types of and Accounting for Derivative Instruments | Types of and Accounting for Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customer, see Note 10. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. PSCo evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. See Note 10 for further discussion of PSCo’s risk management and derivative activities. |
Commodity Trading Operations | Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further discussion. |
Fair Value Measurements | Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Note 8 and 10 for further discussion. |
Cash and Cash Equivalents | Cash and Cash Equivalents — PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents. |
Accounts Receivable and Allowance for Bad Debts | Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. |
Inventory | Inventory — All inventory is recorded at average cost. |
Renewable Energy Credits | RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. PSCo acquires RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, PSCo records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. |
Emission Allowances | Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. PSCo follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. |
Environmental Costs | Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 12 for further discussion of environmental costs. |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 8 for further discussion of benefit plans and other postretirement benefits. |
Guarantees | Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee. |
Subsequent Events | Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 314,009 $ 324,512 Less allowance for bad debts (19,606 ) (19,612 ) $ 294,403 $ 304,900 |
Inventories | (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 68,940 $ 66,161 Fuel 73,893 66,429 Natural gas 71,656 69,630 $ 214,489 $ 202,220 |
Property, Plant and Equipment, Net | (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 12,627,592 $ 12,304,436 Natural gas plant 4,102,075 3,710,772 Common and other property 1,022,333 919,955 Plant to be retired (a) 10,949 31,839 Construction work in progress 1,014,338 484,340 Total property, plant and equipment 18,777,287 17,451,342 Less accumulated depreciation (4,751,536 ) (4,601,543 ) $ 14,025,751 $ 12,849,799 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financin32
Borrowings and Other Financing Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Borrowings and Other Financing Instruments [Abstract] | |
Credit Facilities | At Dec. 31, 2017 , PSCo had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 700 $ 3 $ 697 (a) This credit facility matures in June 2021 . (b) Includes letters of credit. |
Money Pool | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | PSCo had no money pool borrowings outstanding during the three months ended Dec. 31, 2017. Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 250 $ 250 $ 250 Amount outstanding at period end — — — Average amount outstanding — 21 1 Maximum amount outstanding 20 141 34 Weighted average interest rate, computed on a daily basis 0.92 % 0.73 % 0.41 % Weighted average interest rate at period end N/A N/A N/A |
Commercial Paper | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Commercial paper borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 700 $ 700 $ 700 Amount outstanding at period end — 129 14 Average amount outstanding 54 24 95 Maximum amount outstanding 268 154 449 Weighted average interest rate, computed on a daily basis 1.08 % 0.70 % 0.51 % Weighted average interest rate at period end N/A 0.95 0.60 |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Preferred Stock | PSCo has authorized the issuance of preferred stock. Preferred Par Value Preferred 10,000,000 $ 0.01 None |
Joint Ownership of Generation34
Joint Ownership of Generation, Transmission and Gas Facilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract] | |
Investments in Jointly Owned Generation, Transmission and Gas Facilities | Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017 : (Thousands of Dollars) Plant in Service Accumulated CWIP Ownership % Electric Generation: Hayden Unit 1 $ 150,441 $ 72,042 $ 830 76 % Hayden Unit 2 148,694 65,493 18 37 Hayden Common Facilities 39,321 19,886 97 53 Craig Units 1 and 2 80,650 38,666 — 10 Craig Common Facilities 1, 2 and 3 38,902 20,116 — 7 Comanche Unit 3 889,630 117,759 476 67 Comanche Common Facilities 24,421 2,092 2,809 82 Electric Transmission: Transmission and other facilities, including substations 176,873 67,637 638 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 21,532 7,579 — 60 Gas Transportation Compressor 8,417 616 — 50 Total $ 1,578,881 $ 411,886 $ 4,868 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Summary of Statute of Limitations Applicable to Open Tax Years | PSCO is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020 |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 4.0 $ 2.9 Unrecognized tax benefit — Temporary tax positions 6.1 16.8 Total unrecognized tax benefit $ 10.1 $ 19.7 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 19.7 $ 17.4 $ 11.9 Additions based on tax positions related to the current year 1.9 2.7 4.5 Reductions based on tax positions related to the current year (1.5 ) — (1.5 ) Additions for tax positions of prior years 4.4 0.5 2.5 Reductions for tax positions of prior years (14.4 ) (0.9 ) — Balance at Dec. 31 $ 10.1 $ 19.7 $ 17.4 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (4.0 ) $ (5.8 ) |
Interest Payable related to Unrecognized Tax Benefits | The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows: (Millions of Dollars) 2017 2016 2015 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (1.1 ) $ (0.4 ) $ (0.2 ) Interest income (expense) related to unrecognized tax benefits 0.8 (0.7 ) (0.2 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (0.3 ) $ (1.1 ) $ (0.4 ) |
NOL and Tax Credit Carryforwards | Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2017 2016 Federal NOL carryforward $ 68 $ 260 Federal tax credit carryforwards 30 25 State NOL carryforwards 679 684 State tax credit carryforwards, net of federal detriment (a) 17 13 Valuation allowances for state credit carryforwards, net of federal detriment (b) (7 ) (3 ) (a) State tax credit carryforwards are net of federal detriment of $4 million and $7 million as of Dec. 31, 2017 and 2016, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $2 million as of Dec. 31, 2017 and 2016, respectively. |
Schedule of Effective Income Tax Rate Reconciliation | Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 3.0 % 3.0 % 3.0 % Increases (decreases) in tax from: Tax reform (2.4 ) — — Tax credits recognized, net of federal income tax expense (0.9 ) (0.7 ) (0.7 ) Regulatory differences - effects of rate changes (a) (0.1 ) (0.1 ) (0.1 ) Regulatory differences - other utility plant items (0.9 ) (0.5 ) (0.3 ) Change in unrecognized tax benefits 0.2 — 0.1 Other, net (0.1 ) 0.4 0.4 Effective income tax rate 33.8 % 37.1 % 37.4 % |
Schedule of Components of Income Tax Expense (Benefit) | The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 40,386 $ 45,287 $ (1,166 ) Current state tax expense (benefit) 14,577 8,754 (727 ) Current change in unrecognized tax (benefit) expense (7,798 ) 680 5,244 Deferred federal tax expense 176,410 195,064 246,096 Deferred state tax expense 22,513 27,216 36,450 Deferred change in unrecognized tax expense (benefit) 8,894 (278 ) (4,650 ) Deferred investment tax credits (2,803 ) (2,805 ) (2,807 ) Total income tax expense $ 252,179 $ 273,918 $ 278,440 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (1,244,653 ) $ 230,931 $ 285,144 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 1,453,080 (8,418 ) (7,229 ) Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (610 ) (511 ) (19 ) Deferred tax expense $ 207,817 $ 222,002 $ 277,896 |
Schedule of Deferred Tax Assets and Liabilities | The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2017 2016 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 1,797,023 $ 2,967,162 Regulatory assets 252,353 102,967 Pension expense 60,032 10,016 Other 3,994 3,920 Total deferred tax liabilities $ 2,113,402 $ 3,084,065 Deferred tax assets: Regulatory liabilities $ 337,973 $ (35,813 ) NOL carryforward 39,347 115,328 Tax credit carryforward 39,323 34,658 Deferred investment tax credits 6,872 11,653 Other employee benefits 6,779 15,274 Deferred fuel costs 6,523 10,070 Rate refund 890 7,221 Other 31,219 36,545 Total deferred tax assets $ 468,926 $ 194,936 Net deferred tax liability $ 1,644,476 $ 2,889,129 (a) The prior period included in this footnote has been reclassified to conform to current year presentation. |
Benefit Plans and Other Postr36
Benefit Plans and Other Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Projected Benefit Payments for the Pension and Postretirement Benefit Plans | The following table lists PSCo’s projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) Projected Pension Gross Projected Expected Medicare Net Projected 2018 $ 83,036 $ 32,186 $ 2,074 $ 30,112 2019 81,698 32,454 2,192 30,262 2020 81,413 32,767 2,296 30,471 2021 82,021 32,737 2,404 30,333 2022 83,261 32,998 2,501 30,497 2023-2027 411,798 152,926 13,789 139,137 |
Pension Plan [Member] | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Target Asset Allocations and Plan Assets Measured at Fair Value | The following tables present, for each of the fair value hierarchy levels, PSCo’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 67,179 $ — $ — $ — $ 67,179 Commingled funds: U.S. equity funds 169,624 — — — 169,624 Non U.S. equity funds 30,277 — — 65,822 96,099 U.S. corporate bond funds 137,086 — — — 137,086 Emerging market equity funds — — — 103,876 103,876 Emerging market debt funds 24,825 — — 54,954 79,779 Private equity investments — — — 27,816 27,816 Real estate — — — 64,500 64,500 Other commingled funds 1,601 — — 38,545 40,146 Debt securities: Government securities — 144,333 — — 144,333 U.S. corporate bonds — 102,659 — — 102,659 Non U.S. corporate bonds — 16,792 — — 16,792 Equity securities: U.S. equities 37,752 — — — 37,752 Other (9,885 ) 1,414 — 180 (8,291 ) Total $ 458,459 $ 265,198 $ — $ 355,693 $ 1,079,350 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 34,957 $ — $ — $ — $ 34,957 Commingled funds: U.S. equity funds 165,621 — — — 165,621 Non U.S. equity funds 64,710 — — 57,487 122,197 U.S. corporate bond funds 96,995 — — — 96,995 Emerging market equity funds — — — 64,784 64,784 Emerging market debt funds 25,866 — — 27,837 53,703 Commodity funds — — — 7,497 7,497 Private equity investments — — — 31,828 31,828 Real estate — — — 61,048 61,048 Other commingled funds — — — 74,696 74,696 Debt securities: Government securities — 168,014 — — 168,014 U.S. corporate bonds — 86,081 — — 86,081 Non U.S. corporate bonds — 13,828 — — 13,828 Mortgage-backed securities — 2,179 — — 2,179 Asset-backed securities — 1,032 — — 1,032 Equity securities: U.S. equities 27,348 — — — 27,348 Other — (7,595 ) — — (7,595 ) Total $ 415,497 $ 263,539 $ — $ 325,177 $ 1,004,213 The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 34 % 36 % Long-duration fixed income and interest rate swap securities 32 31 Short-to-intermediate fixed income securities 18 15 Alternative investments 14 16 Cash 2 2 Total 100 % 100 % |
Change in Projected Benefit Obligation | Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 1,285,010 $ 1,213,890 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 1,251,822 $ 1,224,650 Service cost 27,280 25,926 Interest cost 50,558 55,405 Transfer to other plan — (9,149 ) Plan amendments (1,096 ) 206 Actuarial loss 83,531 51,779 Benefit payments (77,915 ) (96,995 ) Obligation at Dec. 31 $ 1,334,180 $ 1,251,822 |
Change in Fair Value of Plan Assets | (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 1,004,213 $ 1,036,681 Actual return on plan assets 135,552 56,762 Employer contributions 17,500 16,829 Transfer to other plan — (9,064 ) Benefit payments (77,915 ) (96,995 ) Fair value of plan assets at Dec. 31 $ 1,079,350 $ 1,004,213 |
Funded Status of Plans | (Thousands of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (a) $ (254,830 ) $ (247,609 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost | (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 543,707 $ 554,999 Prior service credit (10,593 ) (12,155 ) Total $ 533,114 $ 542,844 |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates | (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 27,662 $ 26,853 Noncurrent regulatory assets 505,171 515,708 Deferred income taxes 69 108 Net-of-tax accumulated OCI 212 175 Total $ 533,114 $ 542,844 |
Schedule of Assumptions Used | 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 6.84 6.84 6.81 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP-2014 RP-2014 |
Components of Net Periodic Benefit Costs | Benefit Costs — The components of PSCo’s net periodic pension cost were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 27,280 $ 25,926 $ 28,260 Interest cost 50,558 55,405 50,857 Expected return on plan assets (68,535 ) (70,769 ) (72,590 ) Amortization of prior service credit (3,211 ) (3,211 ) (3,136 ) Amortization of net loss 28,355 26,771 36,377 Net periodic pension cost 34,447 34,122 39,768 (Costs) credits not recognized due to effects of regulation (2,631 ) 3,364 (1,464 ) Net benefit cost recognized for financial reporting $ 31,816 $ 37,486 $ 38,304 |
Other Postretirement Benefits Plan [Member] | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Target Asset Allocations and Plan Assets Measured at Fair Value | The following tables present, for each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 25,724 $ — $ — $ — $ 25,724 Insurance contracts — 43,524 — — 43,524 Commingled funds: U.S. equity funds 64,899 — — — 64,899 U.S fixed income funds 29,946 — — — 29,946 Emerging market debt funds 35,402 — — — 35,402 Debt securities: Government securities — 50,576 — — 50,576 U.S. corporate bonds — 55,323 — — 55,323 Non U.S. corporate bonds — 18,712 — — 18,712 Asset-backed securities — 20,468 — — 20,468 Mortgage-backed securities — 30,231 — — 30,231 Equity securities: Non U.S. equities 30,671 — — — 30,671 Other — 948 — — 948 Total $ 186,642 $ 219,782 $ — $ — $ 406,424 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 18,288 $ — $ — $ — $ 18,288 Insurance contracts — 42,046 — — 42,046 Commingled funds: U.S. equity funds 48,462 — — — 48,462 U.S fixed income funds 24,132 — — — 24,132 Emerging market debt funds 27,089 — — — 27,089 Other commingled funds — — — 48,922 48,922 Debt securities: Government securities — 33,600 — — 33,600 U.S. corporate bonds — 55,473 — — 55,473 Non U.S. corporate bonds — 15,384 — — 15,384 Asset-backed securities — 16,845 — — 16,845 Mortgage-backed securities — 25,563 — — 25,563 Equity securities: Non U.S. equities 36,462 — — — 36,462 Other — 1,289 — — 1,289 Total $ 154,433 $ 190,200 $ — $ 48,922 $ 393,555 The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % |
Change in Projected Benefit Obligation | A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 421,823 $ 403,574 Service cost 767 768 Interest cost 16,765 18,070 Medicare subsidy reimbursements 993 1,901 Plan participants’ contributions 5,971 5,376 Actuarial loss 18,314 27,355 Benefit payments (35,386 ) (35,221 ) Obligation at Dec. 31 $ 429,247 $ 421,823 |
Change in Fair Value of Plan Assets | (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 393,555 $ 399,442 Actual return on plan assets 36,975 18,590 Plan participants’ contributions 5,971 5,376 Employer contributions 5,309 5,368 Benefit payments (35,386 ) (35,221 ) Fair value of plan assets at Dec. 31 $ 406,424 $ 393,555 |
Funded Status of Plans | (Thousands of Dollars) 2017 2016 Funded Status at Dec. 31: Funded status (a) $ (22,823 ) $ (28,268 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively. |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost | (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 77,760 $ 78,359 Prior service credit (21,448 ) (27,695 ) Total $ 56,312 $ 50,664 |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates | (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Noncurrent regulatory assets $ 56,312 $ 50,664 |
Schedule of Assumptions Used | Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial: Pre-65 7.00 % 5.50 % Health care costs trend rate — initial: Post-65 5.50 % 5.50 % 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80 |
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate | A one-percent change in the assumed health care cost trend rate would have the following effects on PSCo: One-Percentage Point (Thousands of Dollars) Increase Decrease APBO $ 41,665 $ (35,254 ) Service and interest components 1,837 (1,555 ) |
Components of Net Periodic Benefit Costs | The components of PSCo’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 767 $ 768 $ 928 Interest cost 16,765 18,070 17,498 Expected return on plan assets (21,905 ) (22,299 ) (23,803 ) Amortization of prior service credit (6,247 ) (6,247 ) (6,247 ) Amortization of net loss 3,843 1,931 2,475 Net periodic postretirement benefit credit $ (6,777 ) $ (7,777 ) $ (9,149 ) |
Fair Value of Financial Asset37
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Gross Notional Amounts of Commodity Forwards and Options | The following table details the gross notional amounts of commodity forwards and options at Dec. 31: (Amounts in Thousands) (a)(b) 2017 2016 MWh of electricity 22,260 6,283 MMBtu of natural gas 13,410 42,203 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss | Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Thousands of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (22,780 ) $ (23,836 ) $ (23,878 ) After-tax net unrealized losses related to derivatives accounted for as hedges — — (30 ) After-tax net realized losses on derivative transactions reclassified into earnings 1,005 1,056 72 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (21,775 ) $ (22,780 ) $ (23,836 ) |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2017 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,615 (a) $ — $ — Total $ — $ — $ 1,615 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 386 (c) Natural gas commodity — (10,921 ) — 1,933 (d) (4,170 ) (d) Total $ — $ (10,921 ) $ — $ 1,933 $ (3,784 ) Year Ended Dec. 31, 2016 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Derivatives designated as cash flow hedges Interest rate $ — $ — $ 1,618 (a) $ — $ — Vehicle fuel and other commodity — — 86 (b) — — Total $ — $ — $ 1,704 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (257 ) (c) Natural gas commodity — 2,051 — 10,292 (d) (5,832 ) (d) Total $ — $ 2,051 $ — $ 10,292 $ (6,089 ) Year Ended Dec. 31, 2015 Pre-Tax Fair Value Pre-Tax Losses (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized Derivatives designated as cash flow hedges Interest rate $ — $ — $ 54 (a) $ — $ — Vehicle fuel and other commodity (50 ) — 57 (b) — — Total $ (50 ) $ — $ 111 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 364 (c) Natural gas commodity — (10,635 ) — 10,158 (d) (7,620 ) (d) Total $ — $ (10,635 ) $ — $ 10,158 $ (7,256 ) (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2017 included $0.4 million of settlement gains and amounts for the years ended Dec. 31, 2016 and 2015 included $0.2 million and $1.1 million , respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2017: Dec. 31, 2017 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Commodity trading $ 528 $ 4,488 $ 12 $ 5,028 $ (3,554 ) $ 1,474 Natural gas commodity — 18 — 18 (10 ) 8 Total current derivative assets $ 528 $ 4,506 $ 12 $ 5,046 $ (3,564 ) 1,482 PPAs (a) 1,715 Current derivative instruments $ 3,197 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 1,541 $ — $ 1,541 $ (563 ) $ 978 Total noncurrent derivative assets $ — $ 1,541 $ — $ 1,541 $ (563 ) 978 PPAs (a) 31 Noncurrent derivative instruments $ 1,009 Current derivative liabilities Other derivative instruments: Commodity trading $ 446 $ 4,285 $ 6 $ 4,737 $ (3,431 ) $ 1,306 Natural gas commodity — 1,016 — 1,016 (10 ) 1,006 Total current derivative liabilities $ 446 $ 5,301 $ 6 $ 5,753 $ (3,441 ) 2,312 PPAs (a) 5,036 Current derivative instruments $ 7,348 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 1,362 $ — $ 1,362 $ (563 ) $ 799 Total noncurrent derivative liabilities $ — $ 1,362 $ — $ 1,362 $ (563 ) 799 PPAs (a) $ 2,669 Noncurrent derivative instruments $ 3,468 (a) During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents, for each of the fair value hierarchy levels, PSCo’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016: Dec. 31, 2016 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Commodity trading $ 1,124 $ 5,453 $ — $ 6,577 $ (5,137 ) $ 1,440 Natural gas commodity — 7,778 — 7,778 — 7,778 Total current derivative assets $ 1,124 $ 13,231 $ — $ 14,355 $ (5,137 ) 9,218 PPAs (a) 1,716 Current derivative instruments $ 10,934 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 1,652 $ — $ 1,652 $ — $ 1,652 Total noncurrent derivative assets $ — $ 1,652 $ — $ 1,652 $ — 1,652 PPAs (a) 1,746 Noncurrent derivative instruments $ 3,398 Current derivative liabilities Other derivative instruments: Commodity trading $ 1,386 $ 5,357 $ 22 $ 6,765 $ (5,137 ) $ 1,628 Total current derivative liabilities $ 1,386 $ 5,357 $ 22 $ 6,765 $ (5,137 ) 1,628 PPAs (a) 5,160 Current derivative instruments $ 6,788 Noncurrent derivative liabilities PPAs (a) $ 7,828 Noncurrent derivative instruments $ 7,828 (a) During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Carrying Amount and Fair Value of Long-term Debt | As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,608,275 $ 5,024,840 $ 4,216,206 $ 4,491,570 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2017 2016 2015 Interest income $ 3,809 $ 1,860 $ 753 Other nonoperating income 6,383 2,241 2,408 Insurance policy expense (340 ) (281 ) (197 ) Other nonoperating expense — (3 ) — Other income, net $ 9,852 $ 3,817 $ 2,964 |
Rate Matters (Tables)
Rate Matters (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Public Utilities, General Disclosures [Abstract] | |
Colorado 2017 Multi-Year Electric Rate Case [Table Text Block] | Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 CACJA revenue conversion to base rates (a) 90 — — — 90 TCA revenue conversion to base rates (a) 43 — — — 43 Total (b) $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) (b) $ 6.8 $ 7.1 $ 7.3 $ 7.4 (a) The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. (b) This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. |
Colorado 2017 Multi-Year Gas Rate Case [Table Text Block] | Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 PSIA revenue conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Estimated Minimum Purchases Under Fuel Contracts | The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2017 , are as follows: (Millions of Dollars) Coal Natural gas supply Natural gas 2018 $ 160 $ 344 $ 114 2019 97 286 112 2020 69 275 111 2021 37 278 109 2022 38 126 109 Thereafter 184 57 605 Total $ 585 $ 1,366 $ 1,160 |
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements | At Dec. 31, 2017 , the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity 2018 $ 22 2019 12 2020 4 2021 4 2022 4 Thereafter 14 Total $ 60 |
Summary of Property Held Under Capital Leases | Total amortization expenses under capital lease assets were approximately $5 million , $8 million , and $8 million for 2017 , 2016 and 2015 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Gas storage facilities $ 200.5 $ 200.5 Gas pipeline 20.7 20.7 Property held under capital leases 221.2 221.2 Accumulated depreciation (70.6 ) (65.3 ) Total property held under capital leases, net $ 150.6 $ 155.9 |
Future Commitments Under Operating and Capital Leases | Future commitments under operating and capital leases are: (Millions of Dollars) Operating Leases PPA (a) (b) Operating Leases Total Operating Leases Capital Leases 2018 $ 10 $ 96 $ 106 $ 25 2019 10 97 107 25 2020 10 98 108 25 2021 9 99 108 24 2022 8 87 95 21 Thereafter 34 394 428 442 Total minimum obligation 562 Interest component of obligation (411 ) Present value of minimum obligation $ 151 (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2034 . |
Asset Retirement Obligations | A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2017 Liabilities (a) Accretion Cash Flow Revisions (b) Ending Balance Dec. 31, 2017 (c) Electric plant Steam and other production ash containment $ 72,600 $ (12,068 ) $ 3,159 $ 9,573 $ 73,264 Steam, hydro, and other production asbestos 40,450 (12,047 ) 1,917 (458 ) 29,862 Electric distribution 7,669 — 274 — 7,943 Wind production 2,072 — 20 — 2,092 Other 1,520 (204 ) 66 — 1,382 Natural gas plant Gas transmission and distribution 160,719 — 6,649 61,503 228,871 Other 4,080 (354 ) 159 — 3,885 Common and other property Common miscellaneous 453 — 17 — 470 Total liability $ 289,563 $ (24,673 ) $ 12,261 $ 70,618 $ 347,769 (a) The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. (b) In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. (c) There were no ARO liabilities recognized during the year ended Dec. 31, 2017. (Thousands of Dollars) Beginning Balance Jan. 1, 2016 Liabilities Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2016 (b) Electric plant Steam, hydro, and other production asbestos $ 38,676 $ — $ 1,877 $ (103 ) $ 40,450 Steam and other production ash containment 70,767 — 3,078 (1,245 ) 72,600 Wind production 1,992 — 19 61 2,072 Electric distribution 1,130 — 45 6,494 7,669 Other 1,054 214 46 206 1,520 Natural gas plant Gas transmission and distribution 122,168 — 5,009 33,542 160,719 Other 3,925 — 155 — 4,080 Common and other property Common miscellaneous 796 — 28 (371 ) 453 Total liability $ 240,508 $ 214 $ 10,257 $ 38,584 $ 289,563 (a) In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains. (b) There were no ARO liabilities settled during the year ended Dec. 31, 2016. |
Regulatory Assets and Liabili41
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets | The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 8 Various $ 28,010 $ 565,241 $ 27,270 $ 568,258 Recoverable deferred taxes on AFUDC recorded in plant (b) 1 Plant lives — 86,966 — 151,022 Net AROs (c) 1, 12 Plant lives — 80,476 — 78,050 Depreciation differences 1 One to fourteen years 19,835 69,428 15,363 90,426 Excess deferred taxes - TCJA 7 Various — 53,937 — — Purchased power contract costs 12 Term of related contract 1,261 28,009 1,035 29,029 Property tax Pending rate cases — 16,047 9,393 1,653 Gas pipeline inspection costs 12 One to two years 1,791 7,743 — 4,405 Conservation programs (d) 1, 11 One to two years 6,942 5,528 9,262 6,986 Losses on reacquired debt 4 Term of related debt 1,203 4,916 1,203 6,120 Contract valuation adjustments (e) 10 Term of related contract 6,022 2,638 3,444 6,082 Other Various 12,273 29,329 36,813 16,398 Total regulatory assets $ 77,337 $ 950,258 $ 103,783 $ 958,429 (a) Includes $3.4 million and $4.2 million of regulatory assets related to the nonqualified pension plan, of which $0.3 million and $0.4 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. (b) Includes a write-down of $75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. (c) Includes amounts recorded for future recovery of AROs. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (e) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
Regulatory Liabilities | The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 7 Various $ — $ 1,445,079 $ — $ — Plant removal costs 1, 12 Plant lives — 346,174 — 367,440 Renewable resources and environmental initiatives 11, 12 Various — 56,153 3,600 67,728 Investment tax credit deferrals 1, 7 Various — 17,088 — 18,797 Deferred income tax adjustment 1 Various — 16,301 — 16,260 Deferred electric, natural gas and steam production costs 1 Less than one year 29,078 — 35,123 — Conservation programs (b) 1, 11 Less than one year 21,168 — 24,077 — Other Various 15,880 52,693 38,310 42,708 Total regulatory liabilities (c) $ 66,126 $ 1,933,488 $ 101,110 $ 512,933 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $49.6 million revaluation impact of non-plant ADIT at Dec. 31, 2017. (b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (c) Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Year Ended Dec. 31, 2017 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (22,780 ) $ (220 ) $ (23,000 ) Other comprehensive loss before reclassifications — (5 ) (5 ) Losses reclassified from net accumulated other comprehensive loss 1,005 5 1,010 Net current period other comprehensive income 1,005 — 1,005 Adoption of ASU No. 2018-02 (a) (4,690 ) (47 ) (4,737 ) Accumulated other comprehensive loss at Dec. 31 $ (26,465 ) $ (267 ) $ (26,732 ) (a) In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Year Ended Dec. 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (23,836 ) $ — $ (23,836 ) Other comprehensive loss before reclassifications — (223 ) (223 ) Losses reclassified from net accumulated other comprehensive loss 1,056 3 1,059 Net current period other comprehensive income (loss) 1,056 (220 ) 836 Accumulated other comprehensive loss at Dec. 31 $ (22,780 ) $ (220 ) $ (23,000 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses (gains) on cash flow hedges: Interest rate derivatives $ 1,615 (a) $ 1,618 (a) Vehicle fuel derivatives — (b) 86 (b) Total, pre-tax 1,615 1,704 Tax benefit (610 ) (648 ) Total, net of tax 1,005 1,056 Defined benefit pension and postretirement losses (gains): Amortization of net losses 9 (c) 5 (c) Total, pre-tax 9 5 Tax benefit (4 ) (2 ) Total, net of tax 5 3 Total amounts reclassified, net of tax $ 1,010 $ 1,059 (a) Included in interest charges. (b) Included in O&M expenses. (c) Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans. |
Segments and Related Informat43
Segments and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Thousands of Dollars) Regulated Regulated All Other Reconciling Consolidated 2017 Operating revenues (a) $ 3,003,808 $ 995,214 $ 43,487 $ — $ 4,042,509 Intersegment revenues 288 344 — (632 ) — Total revenues $ 3,004,096 $ 995,558 $ 43,487 $ (632 ) $ 4,042,509 Depreciation and amortization $ 353,560 $ 113,253 $ 4,702 $ — $ 471,515 Interest charges and financing costs 138,565 40,214 508 — 179,287 Income tax expense (benefit) 243,604 18,398 (9,823 ) — 252,179 Net income 370,636 107,822 15,661 — 494,119 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues (a) $ 3,049,352 $ 957,721 $ 40,723 $ — $ 4,047,796 Intersegment revenues 275 110 — (385 ) — Total revenues $ 3,049,627 $ 957,831 $ 40,723 $ (385 ) $ 4,047,796 Depreciation and amortization $ 337,583 $ 101,663 $ 4,309 $ — $ 443,555 Interest charges and financing costs 136,274 37,881 431 — 174,586 Income tax expense (benefit) 228,825 45,960 (867 ) — 273,918 Net income 383,973 75,426 4,092 — 463,491 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues (a) $ 3,115,257 $ 1,006,666 $ 41,590 $ — $ 4,163,513 Intersegment revenues 301 67 — (368 ) — Total revenues $ 3,115,558 $ 1,006,733 $ 41,590 $ (368 ) $ 4,163,513 Depreciation and amortization $ 311,122 $ 96,384 $ 4,161 $ — $ 411,667 Interest charges and financing costs 136,397 34,935 576 — 171,908 Income tax expense (benefit) 234,873 44,192 (625 ) — 278,440 Net income 391,257 74,267 1,278 — 466,802 (a) Operating revenues include $6 million , $13 million and $13 million of intercompany revenue for the years ended Dec. 31, 2017 , 2016 and 2015 , respectively. See Note 16 for further discussion of related party transactions by reportable segment. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31: (Thousands of Dollars) 2017 2016 2015 Operating revenues: Electric $ 1,436 $ 8,809 $ 8,632 Other 4,492 4,525 4,441 Operating expenses: Purchased power 2 56 — Other operating expenses — paid to Xcel Energy Services Inc. 485,066 446,086 414,620 Interest expense — 149 211 Interest income — — 45 Accounts receivable and payable with affiliates at Dec. 31 were: 2017 2016 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 7,738 $ — $ 7,669 $ — NSP-Wisconsin 61 — 974 — SPS 279 — 745 — Other subsidiaries of Xcel Energy Inc. 6,641 58,748 33 98,797 $ 14,719 $ 58,748 $ 9,421 $ 98,797 |
Summarized Quarterly Financia45
Summarized Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Quarter Ended (Thousands of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 1,080,534 $ 930,916 $ 1,030,293 $ 1,000,766 Operating income 212,422 192,811 326,028 154,669 Net income 111,546 100,587 186,077 95,909 Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 1,057,841 $ 909,852 $ 1,059,177 $ 1,020,926 Operating income 223,190 180,629 315,605 170,197 Net income 115,874 87,344 173,607 86,666 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Number of DSM Products, Commercial and Industrial Customers | 20 | ||
Number of DSM Products, Residential and Low-income Customers | 23 | ||
DSM Measurements | 1,000 | ||
Conservation Programs [Abstract] | |||
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs | 24 months | ||
Property, Plant and Equipment [Abstract] | |||
Depreciation expense expressed as a percentage of average depreciable property | 2.70% | 2.60% | 2.70% |
Cash and Cash Equivalents [Abstract] | |||
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents | 3 months |
Accounting Pronouncements Adopt
Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - Accounting Standards Update 2018-02 $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Accumulated Other Comprehensive Loss | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Reclassification of tax effects from AOCI to retained earnings | $ (4.7) |
Retained Earnings | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Reclassification of tax effects from AOCI to retained earnings | $ 4.7 |
Selected Balance Sheet Data (De
Selected Balance Sheet Data (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts receivable, net | ||
Accounts receivable | $ 314,009 | $ 324,512 |
Less allowance for bad debts | (19,606) | (19,612) |
Accounts receivable, net | $ 294,403 | $ 304,900 |
Selected Balance Sheet Data Bal
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 214,489 | $ 202,220 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 68,940 | 66,161 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 73,893 | 66,429 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 71,656 | $ 69,630 |
Selected Balance Sheet Data B50
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 18,777,287 | $ 17,451,342 | |
Less accumulated depreciation | (4,751,536) | (4,601,543) | |
Property, plant and equipment, net | 14,025,751 | 12,849,799 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 12,627,592 | 12,304,436 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 4,102,075 | 3,710,772 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,022,333 | 919,955 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 10,949 | 31,839 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 1,014,338 | $ 484,340 | |
[1] | In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financin51
Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Short-term Debt [Line Items] | |||
Short-term debt | $ 0 | $ 129,000 | |
Money Pool | |||
Short-term Debt [Line Items] | |||
Borrowing limit | 250,000 | 250,000 | $ 250,000 |
Short-term debt | 0 | 0 | 0 |
Average amount outstanding | 0 | 21,000 | 1,000 |
Maximum amount outstanding | $ 20,000 | $ 141,000 | $ 34,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.92% | 0.73% | 0.41% |
Commercial Paper | |||
Short-term Debt [Line Items] | |||
Borrowing limit | $ 700,000 | $ 700,000 | $ 700,000 |
Short-term debt | 0 | 129,000 | 14,000 |
Average amount outstanding | 54,000 | 24,000 | 95,000 |
Maximum amount outstanding | $ 268,000 | $ 154,000 | $ 449,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 1.08% | 0.70% | 0.51% |
Weighted average interest rate at period end (percentage) | 0.95% | 0.60% |
Borrowings and Other Financin52
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Line of Credit Facility [Line Items] | ||
Short-term debt | $ 0 | $ 129,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Short-term debt | $ 3,000 | $ 3,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin53
Borrowings and Other Financing Instruments, Credit Facility (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | ||
Line of Credit Facility [Line Items] | |||
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased | $ 100,000,000 | ||
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed | 65.00% | ||
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) | 44.00% | 45.00% | |
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions | 15.00% | ||
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions | $ 75,000,000 | ||
Short-term debt | $ 0 | $ 129,000,000 | |
Credit Facility | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Maturity Date | Jun. 30, 2021 | ||
Credit facility | [1] | $ 700,000,000 | |
Drawn | [2] | 3,000,000 | |
Available | $ 697,000,000 | ||
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | ||
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 year | ||
Long-term Line of Credit | $ 0 | 0 | |
Letter of Credit | |||
Line of Credit Facility [Line Items] | |||
Short-term debt | $ 3,000,000 | $ 3,000,000 | |
[1] | This credit facility matures in June 2021. | ||
[2] | Includes letters of credit. |
Borrowings and Other Financin54
Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | $ 300 | |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 400 | |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 400 | |
Long-term Debt, Maturities, Repayments of Principal after Year Five | 300 | |
Deferred Finance Costs, Noncurrent, Net | $ 29 | $ 27 |
First Mortgage Bonds | Series Due June 15, 2047 [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.80% | |
Debt Instrument, Maturity Date | Jun. 15, 2047 | |
First Mortgage Bonds | Series Due June 15, 2046 [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 3.55% | 3.55% |
Debt Instrument, Maturity Date | Jun. 15, 2046 | Jun. 15, 2046 |
PSCo | First Mortgage Bonds | Series Due June 15, 2047 [Member] | ||
Debt Instrument [Line Items] | ||
Face amount | $ 400 | |
Interest rate, stated percentage (in hundredths) | 3.80% | |
Debt Instrument, Maturity Date | Jun. 15, 2047 | |
PSCo | First Mortgage Bonds | Series Due June 15, 2046 [Member] | ||
Debt Instrument [Line Items] | ||
Face amount | $ 250 | |
Interest rate, stated percentage (in hundredths) | 3.55% | |
Debt Instrument, Maturity Date | Jun. 15, 2046 |
Preferred Stock (Details)
Preferred Stock (Details) | Dec. 31, 2017$ / sharesshares |
Equity [Abstract] | |
Preferred stock, shares authorized (in shares) | 10,000,000 |
Preferred stock, par value (in dollars per share) | $ / shares | $ 0.01 |
Preferred stock, shares outstanding (in shares) | 0 |
Joint Ownership of Generation56
Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($)MW | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 1,578,881 |
Accumulated depreciation | 411,886 |
Construction work in progress | $ 4,868 |
Generating capacity (in MW) | MW | 816 |
Electric Generation | Hayden Unit 1 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 150,441 |
Accumulated depreciation | 72,042 |
Construction work in progress | $ 830 |
Ownership percentage (in hundredths) | 76.00% |
Electric Generation | Hayden Unit 2 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 148,694 |
Accumulated depreciation | 65,493 |
Construction work in progress | $ 18 |
Ownership percentage (in hundredths) | 37.00% |
Electric Generation | Hayden Common Facilities | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 39,321 |
Accumulated depreciation | 19,886 |
Construction work in progress | $ 97 |
Ownership percentage (in hundredths) | 53.00% |
Electric Generation | Craig Units 1 and 2 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 80,650 |
Accumulated depreciation | 38,666 |
Construction work in progress | $ 0 |
Ownership percentage (in hundredths) | 10.00% |
Electric Generation | Craig Common Facilities 1, 2 and 3 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 38,902 |
Accumulated depreciation | 20,116 |
Construction work in progress | $ 0 |
Ownership percentage (in hundredths) | 7.00% |
Electric Generation | Comanche Unit 3 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 889,630 |
Accumulated depreciation | 117,759 |
Construction work in progress | $ 476 |
Ownership percentage (in hundredths) | 67.00% |
Electric Generation | Comanche Common Facilities | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 24,421 |
Accumulated depreciation | 2,092 |
Construction work in progress | $ 2,809 |
Ownership percentage (in hundredths) | 82.00% |
Electric Transmission | Transmission and other facilities, including substations | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 176,873 |
Accumulated depreciation | 67,637 |
Construction work in progress | $ 638 |
Ownership percentage of group of jointly owned facilities | Various |
Gas Transportation | Rifle to Avon | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 21,532 |
Accumulated depreciation | 7,579 |
Construction work in progress | $ 0 |
Ownership percentage (in hundredths) | 60.00% |
Gas Transportation | Gas Transportation Compressor [Member] | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 8,417 |
Accumulated depreciation | 616 |
Construction work in progress | $ 0 |
Ownership percentage (in hundredths) | 50.00% |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Sep. 30, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2012 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||||
Income Tax Examination [Line Items] | |||||||||||||||
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate | 21.00% | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income | 80.00% | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross | $ 1,500,000,000 | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | 18,000,000 | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction | $ 4,000,000 | ||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Excise Tax Delay | 2 years | ||||||||||||||
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ (300,000) | $ (1,100,000) | $ (400,000) | $ (200,000) | |||||||||||
Interest Income (Expense) related to unrecognized tax benefits | $ 800,000 | $ (700,000) | $ (200,000) | ||||||||||||
Unrecognized Tax Benefits, Income Tax Penalties Accrued | 0 | 0 | 0 | ||||||||||||
Unrecognized Tax Benefits [Abstract] | |||||||||||||||
Unrecognized tax benefit — Permanent tax positions | 4,000,000 | 2,900,000 | |||||||||||||
Unrecognized tax benefit — Temporary tax positions | 6,100,000 | 16,800,000 | |||||||||||||
Total unrecognized tax benefit | $ 10,100,000 | 19,700,000 | 17,400,000 | 11,900,000 | 10,100,000 | 19,700,000 | $ 17,400,000 | $ 11,900,000 | |||||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||||||||||||||
Balance at Jan. 1 | 19,700,000 | 17,400,000 | 11,900,000 | ||||||||||||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 1,900,000 | 2,700,000 | 4,500,000 | ||||||||||||
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions | (1,500,000) | 0 | (1,500,000) | ||||||||||||
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions | 4,400,000 | 500,000 | 2,500,000 | ||||||||||||
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions | (14,400,000) | (900,000) | 0 | ||||||||||||
Balance at Dec. 31 | $ 10,100,000 | $ 10,100,000 | $ 19,700,000 | $ 17,400,000 | |||||||||||
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract] | |||||||||||||||
NOL and tax credit carryforwards | (4,000,000) | (5,800,000) | |||||||||||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 2,000,000 | ||||||||||||||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||||||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% | [1] | 35.00% | [1] | ||||||||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.00% | 3.00% | [1] | 3.00% | [1] | ||||||||||
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent | (2.40%) | 0.00% | [1] | 0.00% | [1] | ||||||||||
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent | (0.90%) | (0.70%) | [1] | (0.70%) | [1] | ||||||||||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | [2] | (0.10%) | (0.10%) | [1] | (0.10%) | [1] | |||||||||
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent | (0.90%) | (0.50%) | [1] | (0.30%) | [1] | ||||||||||
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent | 0.20% | 0.00% | [1] | 0.10% | [1] | ||||||||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | (0.10%) | 0.40% | [1] | 0.40% | [1] | ||||||||||
Effective Income Tax Rate Reconciliation, Percent | 33.80% | 37.10% | [1] | 37.40% | [1] | ||||||||||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||||||||||
Current Federal Tax Expense (Benefit) | $ 40,386,000 | $ 45,287,000 | $ (1,166,000) | ||||||||||||
Current State and Local Tax Expense (Benefit) | 14,577,000 | 8,754,000 | (727,000) | ||||||||||||
Current Change In Unrecognized Tax Expense (Benefit) | (7,798,000) | 680,000 | 5,244,000 | ||||||||||||
Deferred Federal Income Tax Expense (Benefit) | 176,410,000 | 195,064,000 | 246,096,000 | ||||||||||||
Deferred State and Local Income Tax Expense (Benefit) | 22,513,000 | 27,216,000 | 36,450,000 | ||||||||||||
Deferred Change In Unrecognized Tax Expense (Benefit) | 8,894,000 | (278,000) | (4,650,000) | ||||||||||||
Deferred investment tax credits | (2,803,000) | (2,805,000) | (2,807,000) | ||||||||||||
Income Tax Expense (Benefit) | 252,179,000 | 273,918,000 | 278,440,000 | ||||||||||||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||||||||||
Deferred tax expense (benefit) excluding selected items | (1,244,653,000) | 230,931,000 | 285,144,000 | ||||||||||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | 1,453,080,000 | (8,418,000) | (7,229,000) | ||||||||||||
Other Comprehensive Income (Loss), Tax | (610,000) | (511,000) | (19,000) | ||||||||||||
Deferred Income Tax Expense (Benefit) | $ 207,817,000 | $ 222,002,000 | $ 277,896,000 | ||||||||||||
Deferred Tax Liabilities, Gross [Abstract] | |||||||||||||||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,797,023,000 | 2,967,162,000 | [3] | ||||||||||||
Deferred Tax Liabilities, Regulatory Assets | 252,353,000 | 102,967,000 | [3] | ||||||||||||
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits | 60,032,000 | 10,016,000 | [3] | ||||||||||||
Deferred Tax Liabilities, Other | 3,994,000 | 3,920,000 | [3] | ||||||||||||
Deferred Tax Liabilities, Gross | 2,113,402,000 | 3,084,065,000 | [3] | ||||||||||||
Deferred Tax Assets, Gross [Abstract] | |||||||||||||||
Deferred Tax Assets Regulatory Liabilities | 337,973,000 | (35,813,000) | [3] | ||||||||||||
Deferred Tax Assets, Operating Loss Carryforwards | 39,347,000 | 115,328,000 | [3] | ||||||||||||
Deferred Tax Assets Tax credit carryforward | 39,323,000 | 34,658,000 | [3] | ||||||||||||
Deferred Tax Assets Deferred Investment Tax Credits | 6,872,000 | 11,653,000 | [3] | ||||||||||||
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits | 6,779,000 | 15,274,000 | [3] | ||||||||||||
Deferred Tax Assets Unbilled Revenue Fuel Costs | 6,523,000 | 10,070,000 | [3] | ||||||||||||
Deferred Tax Assets Rate Refund | 890,000 | 7,221,000 | [3] | ||||||||||||
Deferred Tax Assets, Other | 31,219,000 | 36,545,000 | [3] | ||||||||||||
Deferred Tax Assets, Net of Valuation Allowance | 468,926,000 | 194,936,000 | [3] | ||||||||||||
Deferred Tax Liabilities, Net | 1,644,476,000 | 2,889,129,000 | [3] | ||||||||||||
Internal Revenue Service (IRS) | |||||||||||||||
Tax Audits [Abstract] | |||||||||||||||
Earliest year subject to examination | 2,009 | ||||||||||||||
Year(s) under examination | 2012 and 2013 | 2010 and 2011 | |||||||||||||
Tax years under examination, Concluded | 2012 and 2013 | ||||||||||||||
Year of carryback claim under examination | 2,009 | ||||||||||||||
Potential Tax Adjustments | $ 14,000,000 | ||||||||||||||
Operating Loss Carryforwards | 68,000,000 | 260,000,000 | |||||||||||||
Tax Credit Carryforward, Amount | 30,000,000 | 25,000,000 | |||||||||||||
Carryforward expiration date range, low | 2,021 | ||||||||||||||
Carryforward expiration date range, high | 2,037 | ||||||||||||||
State and Local Jurisdiction | |||||||||||||||
Tax Audits [Abstract] | |||||||||||||||
Earliest year subject to examination | 2,009 | ||||||||||||||
Operating Loss Carryforwards | 679,000,000 | 684,000,000 | |||||||||||||
Tax Credit Carryforward Net Of Federal Detriment | [4] | 17,000,000 | 13,000,000 | ||||||||||||
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit | [5] | (7,000,000) | (3,000,000) | ||||||||||||
Federal detriment | 4,000,000 | 7,000,000 | |||||||||||||
Federal Benefit | $ 2,000,000 | $ 2,000,000 | |||||||||||||
Carryforward expiration date range, low | 2,018 | ||||||||||||||
Carryforward expiration date range, high | 2,033 | ||||||||||||||
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Bonus depreciation rate, Percent | 50.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2016 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Production Tax Credit Rate, Percent | 100.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2017 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Production Tax Credit Rate, Percent | 80.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2018 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Production Tax Credit Rate, Percent | 60.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2019 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Production Tax Credit Rate, Percent | 40.00% | ||||||||||||||
Investment Tax Credit Rate, Percent | 30.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2020 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Investment Tax Credit Rate, Percent | 26.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; 2021 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Investment Tax Credit Rate, Percent | 22.00% | ||||||||||||||
Consolidated Appropriations Act of 2016; After 2021 Impact [Member] | |||||||||||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||||||||||
Investment Tax Credit Rate, Percent | 10.00% | ||||||||||||||
Plant Related Regulatory Liability [Member] | |||||||||||||||
Income Tax Examination [Line Items] | |||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit | $ 1,100,000,000 | ||||||||||||||
Non-Plant Related Regulated Liability [Member] | |||||||||||||||
Income Tax Examination [Line Items] | |||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit | 50,000,000 | ||||||||||||||
Non-Plant Related Regulatory Asset [Member] | |||||||||||||||
Income Tax Examination [Line Items] | |||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit) | $ 54,000,000 | ||||||||||||||
[1] | The prior periods included in this footnote have been reclassified to conform to current year presentation. | ||||||||||||||
[2] | The amortization of excess deferred taxes. | ||||||||||||||
[3] | The prior period included in this footnote has been reclassified to conform to current year presentation. | ||||||||||||||
[4] | (a) State tax credit carryforwards are net of federal detriment of $4 million and $7 million as of Dec. 31, 2017 and 2016, respectively. | ||||||||||||||
[5] | (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million and $2 million as of Dec. 31, 2017 and 2016, respectively. |
Benefit Plans and Other Postr58
Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details) | Dec. 31, 2017Employee |
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract] | |
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent) | 76.00% |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 1,835 |
Benefit Plans and Other Postr59
Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Commingled funds | Maximum | |
Defined Benefit Plan Disclosure [Line Items] | |
Notice period for investment redemption | 90 days |
Real estate funds | Minimum | |
Defined Benefit Plan Disclosure [Line Items] | |
Notice period for investment redemption | 45 days |
Real estate funds | Maximum | |
Defined Benefit Plan Disclosure [Line Items] | |
Notice period for investment redemption | 90 days |
Benefit Plans and Other Postr60
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plan [Member] | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | $ 1,334,180 | $ 1,251,822 | $ 1,224,650 |
Net benefit cost recognized for financial reporting | $ 31,816 | $ 37,486 | $ 38,304 |
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years) | 20 years | ||
Expected average long-term rate of return on assets (as a percent) | 6.84% | 6.84% | 6.81% |
Expected average long-term rate of return on assets for next fiscal year (as a percent) | 6.84% | ||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 100.00% | 100.00% | |
Pension Plan [Member] | Domestic and international equity securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 34.00% | 36.00% | |
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 32.00% | 31.00% | |
Pension Plan [Member] | Short-to-intermediate fixed income securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 18.00% | 15.00% | |
Pension Plan [Member] | Alternative investments | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 14.00% | 16.00% | |
Pension Plan [Member] | Cash | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 2.00% | 2.00% | |
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | $ 3,000 | $ 4,000 | |
Net benefit cost recognized for financial reporting | 1,000 | 1,000 | |
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | 37,000 | 44,000 | |
Net benefit cost recognized for financial reporting | $ 5,000 | $ 8,000 |
Benefit Plans and Other Postr61
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 1,079,350 | $ 1,004,213 | $ 1,036,681 |
Plan assets at net asset value | 355,693 | 325,177 | |
Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 458,459 | 415,497 | |
Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 265,198 | 263,539 | |
Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 67,179 | 34,957 | |
Plan assets at net asset value | 0 | 0 | |
Cash | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 67,179 | 34,957 | |
Cash | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. equity funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 169,624 | 165,621 | |
Plan assets at net asset value | 0 | 0 | |
U.S. equity funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 169,624 | 165,621 | |
U.S. equity funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. equity funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. equity funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 96,099 | 122,197 | |
Plan assets at net asset value | 65,822 | 57,487 | |
Non U.S. equity funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 30,277 | 64,710 | |
Non U.S. equity funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. equity funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bond funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 137,086 | 96,995 | |
Plan assets at net asset value | 0 | 0 | |
U.S. corporate bond funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 137,086 | 96,995 | |
U.S. corporate bond funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bond funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market equity funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 103,876 | 64,784 | |
Plan assets at net asset value | 103,876 | 64,784 | |
Emerging market equity funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market equity funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market equity funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market debt funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 79,779 | 53,703 | |
Plan assets at net asset value | 54,954 | 27,837 | |
Emerging market debt funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 24,825 | 25,866 | |
Emerging market debt funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market debt funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Commodity funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 7,497 | ||
Plan assets at net asset value | 7,497 | ||
Commodity funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Commodity funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Commodity funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Private equity investments | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 27,816 | 31,828 | |
Plan assets at net asset value | 27,816 | 31,828 | |
Private equity investments | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Private equity investments | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Private equity investments | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Real estate | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 64,500 | 61,048 | |
Plan assets at net asset value | 64,500 | 61,048 | |
Real estate | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Real estate | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Real estate | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other commingled funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 40,146 | 74,696 | |
Plan assets at net asset value | 38,545 | 74,696 | |
Other commingled funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1,601 | 0 | |
Other commingled funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other commingled funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Government securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 144,333 | 168,014 | |
Plan assets at net asset value | 0 | 0 | |
Government securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Government securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 144,333 | 168,014 | |
Government securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bonds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 102,659 | 86,081 | |
Plan assets at net asset value | 0 | 0 | |
U.S. corporate bonds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bonds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 102,659 | 86,081 | |
U.S. corporate bonds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. corporate bonds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 16,792 | 13,828 | |
Plan assets at net asset value | 0 | 0 | |
Non U.S. corporate bonds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. corporate bonds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 16,792 | 13,828 | |
Non U.S. corporate bonds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Mortgage-backed securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 2,179 | ||
Plan assets at net asset value | 0 | ||
Mortgage-backed securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Mortgage-backed securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 2,179 | ||
Mortgage-backed securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Asset-backed securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1,032 | ||
Plan assets at net asset value | 0 | ||
Asset-backed securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Asset-backed securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1,032 | ||
Asset-backed securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
U.S. equities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 37,752 | 27,348 | |
Plan assets at net asset value | 0 | 0 | |
U.S. equities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 37,752 | 27,348 | |
U.S. equities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. equities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | (8,291) | (7,595) | |
Plan assets at net asset value | 180 | 0 | |
Other | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | (9,885) | 0 | |
Other | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1,414 | (7,595) | |
Other | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 0 | $ 0 |
Benefit Plans and Other Postr62
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2018USD ($)Plan | Dec. 31, 2017USD ($)Plan | Dec. 31, 2016USD ($)Plan | Dec. 31, 2015USD ($)Plan | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Defined Contribution Plan, Cost | $ 10,000 | $ 10,000 | $ 10,000 | ||
Pension Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Accumulated Benefit Obligation at Dec. 31 | 1,285,010 | 1,213,890 | |||
Change in Projected Benefit Obligation [Roll Forward] | |||||
Obligation at Jan. 1 | $ 1,334,180 | 1,251,822 | 1,224,650 | ||
Service cost | 27,280 | 25,926 | 28,260 | ||
Interest cost | 50,558 | 55,405 | 50,857 | ||
Transfer (to) from other plan | 0 | (9,149) | |||
Plan amendments | (1,096) | 206 | |||
Actuarial (gain) loss | 83,531 | 51,779 | |||
Benefit payments | (77,915) | (96,995) | |||
Obligation at Dec. 31 | 1,334,180 | 1,251,822 | 1,224,650 | ||
Change in Fair Value of Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 1,079,350 | 1,004,213 | 1,036,681 | ||
Actual return (loss) on plan assets | 135,552 | 56,762 | |||
Employer contributions | 17,500 | 16,829 | |||
Transfer (to) from other plan | 0 | (9,064) | |||
Benefit payments | (77,915) | (96,995) | |||
Fair value of plan assets at Dec. 31 | 1,079,350 | 1,004,213 | 1,036,681 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Funded status | [1] | (254,830) | (247,609) | ||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | |||||
Net loss | 543,707 | 554,999 | |||
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax | (10,593) | (12,155) | |||
Total | 533,114 | 542,844 | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | |||||
Current regulatory assets | 27,662 | 26,853 | |||
Noncurrent regulatory assets | 505,171 | 515,708 | |||
Deferred income taxes | 69 | 108 | |||
Net-of-tax accumulated OCI | 212 | 175 | |||
Total | $ 533,114 | $ 542,844 | |||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | |||||
Discount rate for year-end valuation (as a percent) | 3.63% | 4.13% | |||
Expected average long-term increase in compensation level (as a percent) | 3.75% | 3.75% | |||
Mortality table | RP2014 | RP2014 | |||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 18,000 | $ 17,000 | 20,000 | ||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 27,280 | 25,926 | 28,260 | ||
Interest cost | 50,558 | 55,405 | 50,857 | ||
Expected return on plan assets | (68,535) | (70,769) | (72,590) | ||
Amortization of prior service (credit) cost | (3,211) | (3,211) | (3,136) | ||
Amortization of net loss | 28,355 | 26,771 | 36,377 | ||
Net periodic pension cost | 34,447 | 34,122 | 39,768 | ||
Costs not recognized due to regulation | (2,631) | 3,364 | (1,464) | ||
Net benefit cost recognized for financial reporting | $ 31,816 | $ 37,486 | $ 38,304 | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Discount rate (as a percent) | 4.13% | 4.66% | 4.11% | ||
Expected average long-term increase in compensation level (as a percent) | 3.75% | 4.00% | 3.75% | ||
Expected average long-term rate of return on assets (as a percent) | 6.84% | 6.84% | 6.81% | ||
Allocated costs for pension plans sponsored by Xcel Energy Inc. | $ 18,000 | $ 9,000 | $ 10,000 | ||
Expected average long-term rate of return on assets for next fiscal year (as a percent) | 6.84% | ||||
Number of years fair market value of plan assets is adjusted using calculated value method (in years) | 5 years | ||||
Annual adjustment rate used in calculated value method (as a percent) | 20.00% | ||||
Pension Plan [Member] | Xcel Energy Inc. | |||||
Cash Flows [Abstract] | |||||
Number of pension plans to which contributions were made | Plan | 4 | 4 | 4 | ||
Total contributions to Xcel Energy's pension plans during the period | $ 162,000 | $ 125,000 | $ 90,000 | ||
Pension Plan [Member] | Subsequent Event | |||||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 22,000 | ||||
Pension Plan [Member] | Subsequent Event | Xcel Energy Inc. | |||||
Cash Flows [Abstract] | |||||
Number of pension plans to which contributions were made | Plan | 4 | ||||
Total contributions to Xcel Energy's pension plans during the period | $ 150,000 | ||||
[1] | Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. |
Benefit Plans and Other Postr63
Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Contribution Plans [Abstract] | |||
Contributions to 401(k) and other defined contribution plans | $ 10 | $ 10 | $ 10 |
Benefit Plans and Other Postr64
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member] | Dec. 31, 2017 | Dec. 31, 2016 |
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 100.00% | 100.00% |
Domestic and international equity securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 24.00% | 25.00% |
Short-to-intermediate fixed income securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 60.00% | 57.00% |
Alternative investments | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 9.00% | 13.00% |
Cash | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 7.00% | 5.00% |
Benefit Plans and Other Postr65
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 406,424 | $ 393,555 | $ 399,442 |
Plan assets at net asset value | 0 | 48,922 | |
Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 186,642 | 154,433 | |
Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 219,782 | 190,200 | |
Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 25,724 | 18,288 | |
Plan assets at net asset value | 0 | 0 | |
Cash | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 25,724 | 18,288 | |
Cash | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Insurance contracts | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 43,524 | 42,046 | |
Plan assets at net asset value | 0 | 0 | |
Insurance contracts | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Insurance contracts | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 43,524 | 42,046 | |
Insurance contracts | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. equity funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 64,899 | 48,462 | |
Plan assets at net asset value | 0 | 0 | |
U.S. equity funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 64,899 | 48,462 | |
U.S. equity funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. equity funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S fixed income funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 29,946 | 24,132 | |
Plan assets at net asset value | 0 | 0 | |
U.S fixed income funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 29,946 | 24,132 | |
U.S fixed income funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S fixed income funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market debt funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 35,402 | 27,089 | |
Plan assets at net asset value | 0 | 0 | |
Emerging market debt funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 35,402 | 27,089 | |
Emerging market debt funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Emerging market debt funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other commingled funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 48,922 | ||
Plan assets at net asset value | 48,922 | ||
Other commingled funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Other commingled funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Other commingled funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | ||
Government securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 50,576 | 33,600 | |
Plan assets at net asset value | 0 | 0 | |
Government securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Government securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 50,576 | 33,600 | |
Government securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bonds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 55,323 | 55,473 | |
Plan assets at net asset value | 0 | 0 | |
U.S. corporate bonds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
U.S. corporate bonds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 55,323 | 55,473 | |
U.S. corporate bonds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. corporate bonds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 18,712 | 15,384 | |
Plan assets at net asset value | 0 | 0 | |
Non U.S. corporate bonds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. corporate bonds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 18,712 | 15,384 | |
Non U.S. corporate bonds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Asset-backed securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 20,468 | 16,845 | |
Plan assets at net asset value | 0 | 0 | |
Asset-backed securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Asset-backed securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 20,468 | 16,845 | |
Asset-backed securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Mortgage-backed securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 30,231 | 25,563 | |
Plan assets at net asset value | 0 | 0 | |
Mortgage-backed securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Mortgage-backed securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 30,231 | 25,563 | |
Mortgage-backed securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. equities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 30,671 | 36,462 | |
Plan assets at net asset value | 0 | 0 | |
Non U.S. equities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 30,671 | 36,462 | |
Non U.S. equities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Non U.S. equities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 948 | 1,289 | |
Plan assets at net asset value | 0 | 0 | |
Other | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Other | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 948 | 1,289 | |
Other | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 0 | $ 0 |
Benefit Plans and Other Postr66
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Other Postretirement Benefits Plan [Member] - USD ($) | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Change in Projected Benefit Obligation [Roll Forward] | ||||
Obligation at Jan. 1 | $ 421,823,000 | $ 403,574,000 | ||
Service cost | 767,000 | 768,000 | $ 928,000 | |
Interest cost | 16,765,000 | 18,070,000 | 17,498,000 | |
Medicare subsidy reimbursements | 993,000 | 1,901,000 | ||
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant | 5,971,000 | 5,376,000 | ||
Actuarial (gain) loss | 18,314,000 | 27,355,000 | ||
Benefit payments | (35,386,000) | (35,221,000) | ||
Obligation at Dec. 31 | 429,247,000 | 421,823,000 | 403,574,000 | |
Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 393,555,000 | 399,442,000 | ||
Actual return (loss) on plan assets | 36,975,000 | 18,590,000 | ||
Plan participants' contributions | 5,971,000 | 5,376,000 | ||
Employer contributions | 5,309,000 | 5,368,000 | ||
Benefit payments | (35,386,000) | (35,221,000) | ||
Fair value of plan assets at Dec. 31 | 406,424,000 | 393,555,000 | 399,442,000 | |
Funded Status of Plans at Dec. 31 [Abstract] | ||||
Funded status | [1] | (22,823,000) | (28,268,000) | |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | ||||
Net loss | 77,760,000 | 78,359,000 | ||
Prior service (credit) cost | 21,448,000 | 27,695,000 | ||
Total | 56,312,000 | 50,664,000 | ||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | ||||
Noncurrent regulatory assets | $ 56,312,000 | $ 50,664,000 | ||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | ||||
Discount rate for year-end valuation (as a percent) | 3.62% | 4.13% | ||
Mortality table | RP 2,014 | RP 2,014 | ||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 | 7.00% | 5.50% | ||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65 | 5.50% | 5.50% | ||
Ultimate health care trend assumption rate (as a percent) | 4.50% | |||
Period until ultimate trend rate is reached (in years) | 5 years | |||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | ||||
One-percent increase in APBO | $ 41,665,000 | |||
One-percent decrease in APBO | (35,254,000) | |||
One-percent increase in service and interest components | 1,837,000 | |||
One-percent decrease in service and interest components | (1,555,000) | |||
Cash Flows [Abstract] | ||||
Total contributions to Xcel Energy's postretirement health care plans during the year | 5,000,000 | $ 5,000,000 | 6,000,000 | |
Expected contribution to postretirement health care plans during 2018 | 0 | |||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | ||||
Service cost | 767,000 | 768,000 | 928,000 | |
Interest cost | 16,765,000 | 18,070,000 | 17,498,000 | |
Expected return on plan assets | (21,905,000) | (22,299,000) | (23,803,000) | |
Amortization of prior service (credit) cost | (6,247,000) | (6,247,000) | (6,247,000) | |
Amortization of net loss | 3,843,000 | 1,931,000 | 2,475,000 | |
Net periodic pension cost | $ (6,777,000) | $ (7,777,000) | $ (9,149,000) | |
Significant Assumptions Used to Measure Costs [Abstract] | ||||
Discount rate (as a percent) | 4.13% | 4.65% | 4.08% | |
Expected average long-term rate of return on assets (as a percent) | 5.80% | 5.80% | 5.80% | |
Xcel Energy Inc. | ||||
Cash Flows [Abstract] | ||||
Total contributions to Xcel Energy's postretirement health care plans during the year | $ 20,000,000 | $ 18,000,000 | $ 18,000,000 | |
Expected contribution to postretirement health care plans during 2018 | $ 12,000,000 | |||
[1] | Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets as of Dec. 31, 2017 and 2016, respectively. |
Benefit Plans and Other Postr67
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Other Postretirement Benefits Plan [Member] | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2,018 | $ 32,186 |
2,019 | 32,454 |
2,020 | 32,767 |
2,021 | 32,737 |
2,022 | 32,998 |
2023-2027 | 152,926 |
Expected Medicare Part D Subsidies [Abstract] | |
2,018 | 2,074 |
2,019 | 2,192 |
2,020 | 2,296 |
2,021 | 2,404 |
2,022 | 2,501 |
2023-2027 | 13,789 |
Defined Benefit Plan, Net Projected Benefit Payments [Abstract] | |
2,018 | 30,112 |
2,019 | 30,262 |
2,020 | 30,471 |
2,021 | 30,333 |
2,022 | 30,497 |
2023-2027 | 139,137 |
Pension Plan [Member] | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2,018 | 83,036 |
2,019 | 81,698 |
2,020 | 81,413 |
2,021 | 82,021 |
2,022 | 83,261 |
2023-2027 | $ 411,798 |
Fair Value of Financial Asset68
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, MMBTU in Thousands, $ in Millions | Dec. 31, 2017USD ($)MMBTUMWhCounterparty | Dec. 31, 2016MMBTUMWh | |
Credit Concentration Risk | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 10 | ||
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 6 | ||
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 4 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 16.5 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 37.00% | ||
Credit Concentration Risk | External Credit Rating, Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 5 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 7 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 16.00% | ||
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | 1 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ | $ 7.4 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 17.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ | $ (1.2) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 22,260 | 6,283 |
Natural Gas Commodity (in million British thermal units) | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 13,410 | 42,203 |
[1] | Amounts are not reflective of net positions in the underlying commodities. | ||
[2] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |||
Interest income | $ 3,809 | $ 1,860 | $ 753 |
Other nonoperating income | 6,383 | 2,241 | 2,408 |
Insurance Policy Expense (Income), Net | (340) | (281) | (197) |
Other Nonoperating Expense | 0 | (3) | 0 |
Other income, net | $ 9,852 | $ 3,817 | $ 2,964 |
Fair Value of Financial Asset70
Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ (22,780) | $ (23,836) | $ (23,878) |
After-tax net unrealized losses related to derivatives accounted for as hedges | 0 | 0 | (30) |
After-tax net realized losses on derivative transactions reclassified into earnings | 1,005 | 1,056 | 72 |
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ (21,775) | $ (22,780) | $ (23,836) |
Fair Value of Financial Asset71
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | ||||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | $ 0 | |
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | |
Designated as Hedging Instrument | Cash Flow Hedges | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | (50,000) | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1,615,000 | 1,704,000 | 111,000 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [1] | 1,615,000 | 1,618,000 | 54,000 |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | |
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | (50,000) | ||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | ||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [2] | 86,000 | 57,000 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | ||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | ||
Other Derivative Instruments | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (10,921,000) | 2,051,000 | (10,635,000) | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 1,933,000 | 10,292,000 | 10,158,000 | |
Pre-tax gains (losses) recognized during the period in income | (3,784,000) | (6,089,000) | (7,256,000) | |
Other Derivative Instruments | Commodity Trading | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | |
Pre-tax gains (losses) recognized during the period in income | [3] | 386,000 | (257,000) | 364,000 |
Other Derivative Instruments | Natural Gas Commodity | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (10,921,000) | 2,051,000 | (10,635,000) | |
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | [4] | 1,933,000 | 10,292,000 | 10,158,000 |
Pre-tax gains (losses) recognized during the period in income | [4] | (4,170,000) | (5,832,000) | (7,620,000) |
Other Derivative Instruments | Natural Gas Commodity for Electric Generation | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | $ 400,000 | $ (200,000) | $ (1,100,000) | |
[1] | Amounts are recorded to interest charges. | |||
[2] | Amounts are recorded to O&M expenses. | |||
[3] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | |||
[4] | Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset as appropriate. Amounts for the year ended Dec. 31, 2017 included $0.4 million of settlement gains and amounts for the years ended Dec. 31, 2016 and 2015 included $0.2 million and $1.1 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. |
Fair Value of Financial Asset72
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 0 | $ 0 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Fair Value of Financial Asset73
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 0 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,197 | 10,934 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,009 | 3,398 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 7,348 | 6,788 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,468 | 7,828 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,482 | 9,218 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (3,564) | [1] | (5,137) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,474 | 1,440 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (3,554) | [1] | (5,137) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 8 | 7,778 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (10) | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 978 | 1,652 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (563) | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 978 | 1,652 | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (563) | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,312 | 1,628 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (3,441) | [1] | (5,137) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,306 | 1,628 | |||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (3,431) | [1] | (5,137) | [2] | |
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,006 | ||||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | [1] | (10) | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 799 | ||||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | [1] | (563) | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 799 | ||||
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | [1] | (563) | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 528 | 1,124 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 528 | 1,124 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 446 | 1,386 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 446 | 1,386 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 4,506 | 13,231 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 4,488 | 5,453 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 18 | 7,778 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,541 | 1,652 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,541 | 1,652 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,301 | 5,357 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 4,285 | 5,357 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,016 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,362 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,362 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 12 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 12 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6 | 22 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6 | 22 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,715 | [3] | 1,716 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 31 | [3] | 1,746 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,036 | [3] | 5,160 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,669 | [3] | 7,828 | [4] | |
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 5,046 | 14,355 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 5,028 | 6,577 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 18 | 7,778 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,541 | 1,652 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,541 | 1,652 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,753 | 6,765 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 4,737 | $ 6,765 | |||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,016 | ||||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,362 | ||||
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ 1,362 | ||||
[1] | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return or reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[2] | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral of or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[3] | During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Financial Asset74
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Transfers into Level 3 | $ 0 | $ 0 | $ 0 |
Transfers out of Level 3 | $ 0 | $ 0 | $ 0 |
Fair Value of Financial Asset75
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 4,608,275 | $ 4,216,206 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 5,024,840 | $ 4,491,570 |
Rate Matters (Details)
Rate Matters (Details) $ in Millions | Feb. 16, 2018 | Feb. 14, 2018USD ($) | Oct. 31, 2017USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2017USD ($)GWh | |
Colorado 2017 Multi-Year Electric Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Number of Years Which Rates are Requested to Increase | 4 years | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | |||||
Public Utilities, Requested Equity Capital Structure, Percentage | 55.25% | |||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 245 | |||||
Public Utilities, Impact to Base Rates | 378 | |||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 74 | |||||
Public Utilities, Impact to Base Rates | 207 | |||||
Public Utilities, Expected Year-End Rate Base | [1] | 6,800 | ||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 75 | |||||
Public Utilities, Impact to Base Rates | 75 | |||||
Public Utilities, Expected Year-End Rate Base | [1] | 7,100 | ||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 60 | |||||
Public Utilities, Impact to Base Rates | 60 | |||||
Public Utilities, Expected Year-End Rate Base | [1] | 7,300 | ||||
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 36 | |||||
Public Utilities, Impact to Base Rates | 36 | |||||
Public Utilities, Expected Year-End Rate Base | [1] | $ 7,400 | ||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Number of Years Which Rates are Requested to Increase | 3 years | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.00% | |||||
Public Utilities, Requested Equity Capital Structure, Percentage | 55.25% | |||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 139 | |||||
Public Utilities, Impact to Base Rates | 233 | |||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 63 | |||||
Public Utilities, Impact to Base Rates | 63 | |||||
Public Utilities, Expected Year-End Rate Base | [2] | 1,500 | ||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 33 | |||||
Public Utilities, Impact to Base Rates | 127 | |||||
Public Utilities, Expected Year-End Rate Base | [2] | 2,300 | ||||
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 43 | |||||
Public Utilities, Impact to Base Rates | 43 | |||||
Public Utilities, Expected Year-End Rate Base | [2] | 2,400 | ||||
CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Return on Equity Threshold for Earnings Sharing | 9.83% | |||||
CPUC Proceeding - Demand Side Management Cost Adjustment | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Incentive Award Upon Achieving Savings Goal | $ 5 | |||||
Public Utilities, Percentage of Net Economic Benefits on Which Incentive is Earned | 5.00% | |||||
Public Utilities, Maximum Annual Incentive | $ 30 | |||||
Public Utilities, Electric Incentive Award Earned for Achieving 2016 Savings Goal | 11 | |||||
Public Utilities, Gas Incentive Award Earned for Achieving 2016 Savings Goal | $ 3 | |||||
Demand Side Management Cost Adjustment, 2018 through 2020 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (in GWh) | GWh | 400 | |||||
Public Utilities, Annual Spending Limit | $ 84 | |||||
CPUC Staff [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Recommended Length of Average Rate Base | 13 months | |||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 48.73% | |||||
Public Utilities, Total Recommended Rate Increase (Decrease) | 30 | |||||
Office of Consumer Council (OCC) [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Recommended Length of Average Rate Base | 13 months | |||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 51.20% | |||||
Public Utilities, Total Recommended Rate Increase (Decrease) | $ 39 | |||||
Subsequent Event | Colorado 2017 Multi-Year Electric Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Length of TCJA Net Benefits Deferral | 5 months | |||||
Subsequent Event | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Reduction of Provisional Rates | $ 20 | |||||
CACJA Recovery Rider | Colorado 2017 Multi-Year Electric Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | $ 90 | ||||
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 90 | ||||
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 0 | ||||
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 0 | ||||
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 0 | ||||
Transmission Cost Adjustment (TCA) Rider | Colorado 2017 Multi-Year Electric Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 43 | ||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 43 | ||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 0 | ||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | 0 | ||||
Transmission Cost Adjustment (TCA) Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [3] | $ 0 | ||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [4] | 94 | ||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [4] | 0 | ||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [4] | 94 | ||||
Pipeline System Integrity Adjustment (PSIA) Rider | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Rider Conversion to Base Rates | [4] | $ 0 | ||||
[1] | This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. | |||||
[2] | The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. | |||||
[3] | The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. | |||||
[4] | The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. |
Commitments and Contingencies,
Commitments and Contingencies, Capital Commitments (Details) | 12 Months Ended |
Dec. 31, 2017MW | |
Capital Commitments | Rush Creek Wind Farm [Member] | |
Capital Commitments [Abstract] | |
Public Utilities, Facility Generating Capacity | 600 |
Commitments and Contingencies78
Commitments and Contingencies, Fuel Contracts (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Coal | |
Fuel Contracts [Abstract] | |
2,018 | $ 160 |
2,019 | 97 |
2,020 | 69 |
2,021 | 37 |
2,022 | 38 |
Thereafter | 184 |
Total | 585 |
Natural Gas Supply | |
Fuel Contracts [Abstract] | |
2,018 | 344 |
2,019 | 286 |
2,020 | 275 |
2,021 | 278 |
2,022 | 126 |
Thereafter | 57 |
Total | 1,366 |
Natural Gas Storage and Transportation | |
Fuel Contracts [Abstract] | |
2,018 | 114 |
2,019 | 112 |
2,020 | 111 |
2,021 | 109 |
2,022 | 109 |
Thereafter | 605 |
Total | $ 1,160 |
Minimum | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Fuel Contract Expiration Date | 2,018 |
Maximum | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Fuel Contract Expiration Date | 2,060 |
Commitments and Contingencies79
Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Purchase Power Agreement Expiration Date | 2,034 | ||
Capacity | |||
Purchased Power Agreements (PPAs) [Abstract] | |||
Payments for capacity | $ 25 | $ 44 | $ 70 |
Estimated Future Payments Under PPAs [Abstract] | |||
2,018 | 22 | ||
2,019 | 12 | ||
2,020 | 4 | ||
2,021 | 4 | ||
2,022 | 4 | ||
Thereafter | 14 | ||
Total | $ 60 |
Commitments and Contingencies80
Commitments and Contingencies, Leases (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017USD ($)Lease | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Capital Leases [Abstract] | ||||
Number of leases qualifying as capital leases | Lease | 3 | |||
Amortization expense under capital lease assets | $ 5 | $ 8 | $ 8 | |
Property Held Under Capital Leases, Net [Abstract] | ||||
Property held under capital lease | 221.2 | 221.2 | ||
Accumulated depreciation | (70.6) | (65.3) | ||
Total property held under capital leases, net | 150.6 | 155.9 | ||
Capital Leases, Future Minimum Payments Due [Abstract] | ||||
2,018 | 25 | |||
2,019 | 25 | |||
2,020 | 25 | |||
2,021 | 24 | |||
2,022 | 21 | |||
Thereafter | 442 | |||
Total minimum obligation | 562 | |||
Interest component of obligation | (411) | |||
Present value of minimum obligation | $ 151 | |||
Operating Leased Assets [Line Items] | ||||
Operating Lease Purchase Power Agreement Expiration Date | 2,034 | |||
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,018 | $ 106 | |||
2,019 | 107 | |||
2,020 | 108 | |||
2,021 | 108 | |||
2,022 | 95 | |||
Thereafter | $ 428 | |||
WYCO Totem Gas Storage Facilities | ||||
Capital Leases [Abstract] | ||||
Ownership interest in joint venture (in hundredths) | 50.00% | |||
Capital lease obligations | $ 124 | 127 | ||
Gas Storage Facilities | ||||
Property Held Under Capital Leases, Net [Abstract] | ||||
Property held under capital lease | 200.5 | 200.5 | ||
Gas Pipeline | ||||
Property Held Under Capital Leases, Net [Abstract] | ||||
Property held under capital lease | 20.7 | 20.7 | ||
Office Space and Other Equipment | ||||
Operating Leases [Abstract] | ||||
Total expenses under operating lease obligations | 109 | 118 | 130 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,018 | 10 | |||
2,019 | 10 | |||
2,020 | 10 | |||
2,021 | 9 | |||
2,022 | 8 | |||
Thereafter | 34 | |||
Purchased Power Agreements | ||||
Operating Leases [Abstract] | ||||
Payments for capacity for PPAs under operating lease obligations | 96 | $ 102 | $ 114 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,018 | [1],[2] | 96 | ||
2,019 | [1],[2] | 97 | ||
2,020 | [1],[2] | 98 | ||
2,021 | [1],[2] | 99 | ||
2,022 | [1],[2] | 87 | ||
Thereafter | [1],[2] | $ 394 | ||
[1] | Amounts do not include PPAs accounted for as executory contracts. | |||
[2] | PPA operating leases contractually expire through 2034. |
Commitments and Contingencies81
Commitments and Contingencies, Variable Interest Entities (Details) - MW | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Purchased Power Agreements (PPAs) [Abstract] | ||
VIE Purchase Power Agreement Expiration Date | 2,032 | |
Independent Power Producing Entities | ||
Purchased Power Agreements (PPAs) [Abstract] | ||
Generating capacity (in MW) | 1,571 | 1,571 |
Commitments and Contingencies82
Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017Site | Dec. 31, 2016USD ($) | Dec. 31, 2015Period | |
Other MGP, Landfill, or Disposal Sites [Domain] | |||
Manufactured Gas Plant (MGP) Sites [Abstract] | |||
Number of Identified MGP Sites Under Current Investigation and/or Remediation | Site | 3 | ||
Accrual for Environmental Loss Contingencies, Gross | $ | $ 2 | ||
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide | |||
Environmental Requirements [Abstract] | |||
Number of Phases Under a Consent Decree Which the EPA is Requiring States to Evaluate Areas for Attainment | 3 | ||
National Ambient Air Quality Standards for Ozone | |||
Environmental Requirements [Abstract] | |||
Number of Hours Measured for Standard | Period | 8 | ||
Former Level of Air Quality Concentrations (in parts per billion) | 75 | ||
Revised Level of Air Quality Concentrations (in parts per billion) | 70 |
Commitments and Contingencies83
Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | $ 289,563,000 | [1] | $ 240,508,000 | |
Liabilities recognized | 0 | 214,000 | ||
Liabilities settled | (24,673,000) | [2] | 0 | |
Accretion | 12,261,000 | 10,257,000 | ||
Cash Flow Revisions | 70,618,000 | [3] | 38,584,000 | [4] |
Ending balance | 347,769,000 | [5] | 289,563,000 | [1] |
Electric Plant Steam and Other Production Ash Containment | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 72,600,000 | [1] | 70,767,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | (12,068,000) | [2] | 0 | |
Accretion | 3,159,000 | 3,078,000 | ||
Cash Flow Revisions | 9,573,000 | [3] | (1,245,000) | [4] |
Ending balance | 73,264,000 | [5] | 72,600,000 | [1] |
Steam, hydro, and other production asbestos | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 40,450,000 | [1] | 38,676,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | (12,047,000) | [2] | 0 | |
Accretion | 1,917,000 | 1,877,000 | ||
Cash Flow Revisions | (458,000) | [3] | (103,000) | [4] |
Ending balance | 29,862,000 | [5] | 40,450,000 | [1] |
Electric Plant Electric Distribution | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 7,669,000 | [1] | 1,130,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | [2] | 0 | |
Accretion | 274,000 | 45,000 | ||
Cash Flow Revisions | 0 | [3] | 6,494,000 | [4] |
Ending balance | 7,943,000 | [5] | 7,669,000 | [1] |
Electric Plant Wind Production | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 2,072,000 | [1] | 1,992,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | [2] | 0 | |
Accretion | 20,000 | 19,000 | ||
Cash Flow Revisions | 0 | [3] | 61,000 | [4] |
Ending balance | 2,092,000 | [5] | 2,072,000 | [1] |
Electric Plant Other | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 1,520,000 | [1] | 1,054,000 | |
Liabilities recognized | 0 | 214,000 | ||
Liabilities settled | (204,000) | [2] | 0 | |
Accretion | 66,000 | 46,000 | ||
Cash Flow Revisions | 0 | [3] | 206,000 | [4] |
Ending balance | 1,382,000 | [5] | 1,520,000 | [1] |
Natural Gas Plant Gas Transmission and Distribution | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 160,719,000 | [1] | 122,168,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | [2] | 0 | |
Accretion | 6,649,000 | 5,009,000 | ||
Cash Flow Revisions | 61,503,000 | [3] | 33,542,000 | [4] |
Ending balance | 228,871,000 | [5] | 160,719,000 | [1] |
Natural Gas Plant Other | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 4,080,000 | [1] | 3,925,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | (354,000) | [2] | 0 | |
Accretion | 159,000 | 155,000 | ||
Cash Flow Revisions | 0 | [3] | 0 | [4] |
Ending balance | 3,885,000 | [5] | 4,080,000 | [1] |
Common and Other Property Common Miscellaneous | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 453,000 | [1] | 796,000 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | [2] | 0 | |
Accretion | 17,000 | 28,000 | ||
Cash Flow Revisions | 0 | [3] | (371,000) | [4] |
Ending balance | $ 470,000 | [5] | $ 453,000 | [1] |
[1] | There were no ARO liabilities settled during the year ended Dec. 31, 2016 | |||
[2] | The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. | |||
[3] | In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. | |||
[4] | In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains. | |||
[5] | There were no ARO liabilities recognized during the year ended Dec. 31, 2017. |
Commitments and Contingencies84
Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Plant Removal Costs | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | $ 346 | $ 367 |
Commitments and Contingencies85
Commitments and Contingencies, Legal Contingencies (Details) | 1 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2017USD ($) | |
Pacific Northwest FERC Refund Proceeding [Member] | ||
Legal Contingencies [Abstract] | ||
Accrual For Legal Contingency | $ 0 | |
PSCo | Line Extension Disputes | ||
Legal Contingencies [Abstract] | ||
Accrual For Legal Contingency | $ 0 | |
Minimum | PSCo | Line Extension Disputes | ||
Legal Contingencies [Abstract] | ||
Loss Contingency, Number of Plaintiffs | 50 |
Regulatory Assets and Liabili86
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | |||
Regulatory Assets [Line Items] | ||||
Regulatory Asset, Current | $ 77,337 | $ 103,783 | ||
Regulatory Asset, Noncurrent | 950,258 | 958,429 | ||
Past expenditures not currently earning a return | $ 44,000 | 28,000 | ||
Pension and Retiree Medical Obligations | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Various | |||
Regulatory Asset, Current | [1] | $ 28,010 | 27,270 | |
Regulatory Asset, Noncurrent | [1] | 565,241 | 568,258 | |
Non Qualified Pension Plan | ||||
Regulatory Assets [Line Items] | ||||
Regulatory Asset, Current | 300 | 400 | ||
Regulatory Asset | $ 3,400 | 4,200 | ||
Recoverable Deferred Taxes on AFUDC Recorded in Plant | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Plant lives | |||
Regulatory Asset, Current | $ 0 | [2] | 0 | |
Regulatory Asset, Noncurrent | 86,966 | [2] | 151,022 | |
Revaluation of Regulatory Assets for New Federal Tax Rate [Member] | ||||
Regulatory Assets [Line Items] | ||||
Contra Regulatory Asset | $ 76,000 | |||
Net AROs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Plant lives | |||
Regulatory Asset, Current | [3] | $ 0 | 0 | |
Regulatory Asset, Noncurrent | [3] | $ 80,476 | 78,050 | |
Depreciation Differences | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | One to fourteen years | |||
Regulatory Asset, Current | $ 19,835 | 15,363 | ||
Regulatory Asset, Noncurrent | $ 69,428 | 90,426 | ||
Excess deferred taxes - TCJA | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Various | |||
Regulatory Asset, Current | $ 0 | 0 | ||
Regulatory Asset, Noncurrent | $ 53,937 | 0 | ||
Purchased Power Agreements | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Term of related contract | |||
Regulatory Asset, Current | $ 1,261 | 1,035 | ||
Regulatory Asset, Noncurrent | $ 28,009 | 29,029 | ||
Property Tax | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Pending rate cases | |||
Regulatory Asset, Current | $ 0 | 9,393 | ||
Regulatory Asset, Noncurrent | $ 16,047 | 1,653 | ||
Gas Pipeline Inspection Costs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | One to two years | |||
Regulatory Asset, Current | $ 1,791 | 0 | ||
Regulatory Asset, Noncurrent | $ 7,743 | 4,405 | ||
Conservation Programs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | One to two years | |||
Regulatory Asset, Current | [4] | $ 6,942 | 9,262 | |
Regulatory Asset, Noncurrent | [4] | $ 5,528 | 6,986 | |
Losses on Reacquired Debt | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Term of related debt | |||
Regulatory Asset, Current | $ 1,203 | 1,203 | ||
Regulatory Asset, Noncurrent | $ 4,916 | 6,120 | ||
Contract Valuation Adjustments | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Term of related contract | |||
Regulatory Asset, Current | [5] | $ 6,022 | 3,444 | |
Regulatory Asset, Noncurrent | [5] | $ 2,638 | 6,082 | |
Other Regulatory Assets | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, remaining amortization period | Various | |||
Regulatory Asset, Current | $ 12,273 | 36,813 | ||
Regulatory Asset, Noncurrent | $ 29,329 | $ 16,398 | ||
[1] | (a) Includes $3.4 million and $4.2 million of regulatory assets related to the nonqualified pension plan, of which $0.3 million and $0.4 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. | |||
[2] | (b) Includes a write-down of $75.9 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. | |||
[3] | (c) Includes amounts recorded for future recovery of AROs. | |||
[4] | (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | |||
[5] | (e) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
Regulatory Assets and Liabili87
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | |||
Regulatory Liabilities [Line Items] | ||||
Regulatory Liability, Current | [1] | $ 66,126 | $ 101,110 | |
Regulatory Liability, Noncurrent | $ 1,933,488 | 512,933 | ||
Excess deferred taxes - TCJA | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Various | |||
Revaluation of Non-plant ADIT | $ 49,600 | |||
Regulatory Liability, Current | 0 | [2] | 0 | |
Regulatory Liability, Noncurrent | $ 1,445,079 | [2] | 0 | |
Plant Removal Costs | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Plant lives | |||
Regulatory Liability, Current | $ 0 | 0 | ||
Regulatory Liability, Noncurrent | $ 346,174 | 367,440 | ||
Renewable Resources and Environmental Initiatives | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Various | |||
Regulatory Liability, Current | $ 0 | 3,600 | ||
Regulatory Liability, Noncurrent | $ 56,153 | 67,728 | ||
Investment Tax Credit Deferrals | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Various | |||
Regulatory Liability, Current | $ 0 | 0 | ||
Regulatory Liability, Noncurrent | $ 17,088 | 18,797 | ||
Deferred Income Tax Adjustment | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Various | |||
Regulatory Liability, Current | $ 0 | 0 | ||
Regulatory Liability, Noncurrent | $ 16,301 | 16,260 | ||
Deferred Electric, Gas, and Steam Production Costs | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Less than one year | |||
Regulatory Liability, Current | $ 29,078 | 35,123 | ||
Regulatory Liability, Noncurrent | $ 0 | 0 | ||
Conservation Programs | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Less than one year | |||
Regulatory Liability, Current | [3] | $ 21,168 | 24,077 | |
Regulatory Liability, Noncurrent | [3] | $ 0 | 0 | |
Other Regulatory Liabilities | ||||
Regulatory Liabilities [Line Items] | ||||
Regulatory Noncurrent Liability, Amortization Period | Various | |||
Regulatory Liability, Current | $ 15,880 | 38,310 | ||
Regulatory Liability, Noncurrent | 52,693 | 42,708 | ||
Other Current Liabilities | ||||
Regulatory Liabilities [Line Items] | ||||
Entity's Recorded Provision for Revenue Subject To Refund | $ 0 | $ 2,400 | ||
[1] | (c) Revenue subject to refund of $0 million and $2.4 million for 2017 and 2016, respectively, is included in other current liabilities. | |||
[2] | (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $49.6 million revaluation impact of non-plant ADIT at Dec. 31, 2017. | |||
[3] | (b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | $ 5,269,455 | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,010 | $ 1,059 | |
Adoption of ASU No. 2018-02 | 0 | ||
Accumulated other comprehensive loss at end of period | 5,828,323 | 5,269,455 | |
Gains and Losses on Cash Flow Hedges | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | (22,780) | (23,836) | |
Other comprehensive income (loss) before reclassifications | 0 | 0 | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,005 | 1,056 | |
Net current period other comprehensive income (loss) | 1,005 | 1,056 | |
Adoption of ASU No. 2018-02 | [1] | (4,690) | |
Accumulated other comprehensive loss at end of period | (26,465) | (22,780) | |
Defined Benefit Pension and Postretirement Items | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | (220) | 0 | |
Other comprehensive income (loss) before reclassifications | (5) | (223) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 5 | 3 | |
Net current period other comprehensive income (loss) | 0 | (220) | |
Adoption of ASU No. 2018-02 | [1] | (47) | |
Accumulated other comprehensive loss at end of period | (267) | (220) | |
Accumulated Other Comprehensive Income (Loss) | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | (23,000) | (23,836) | |
Other comprehensive income (loss) before reclassifications | (5) | (223) | |
(Gains) losses reclassified from net accumulated other comprehensive loss | 1,010 | 1,059 | |
Net current period other comprehensive income (loss) | 1,005 | 836 | |
Adoption of ASU No. 2018-02 | [1] | (4,737) | |
Accumulated other comprehensive loss at end of period | $ (26,732) | $ (23,000) | |
[1] | In 2017, PSCo implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. |
Other Comprehensive Income - Re
Other Comprehensive Income - Reclassification from AOCI (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Operating and maintenance expenses | $ 762,817 | $ 762,416 | $ 761,901 | |
Total, pre-tax | (746,298) | (737,409) | (745,242) | |
Income tax expense (benefit) | 252,179 | 273,918 | $ 278,440 | |
Total amounts reclassified, net of tax | (1,010) | (1,059) | ||
Gains and Losses on Cash Flow Hedges | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total amounts reclassified, net of tax | (1,005) | (1,056) | ||
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total, pre-tax | 1,615 | 1,704 | ||
Income tax expense (benefit) | (610) | (648) | ||
Total, net of tax | 1,005 | 1,056 | ||
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Interest charges | [1] | 1,615 | 1,618 | |
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Operating and maintenance expenses | [2] | 0 | 86 | |
Amortization of net losses | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total, pre-tax | [3] | 9 | 5 | |
Defined Benefit Pension and Postretirement Items | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total amounts reclassified, net of tax | (5) | (3) | ||
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total, pre-tax | (9) | (5) | ||
Tax Benefit | (4) | (2) | ||
Total amounts reclassified, net of tax | $ 5 | $ 3 | ||
[1] | Included in interest charges. | |||
[2] | Included in O&M expenses | |||
[3] | Included in the computation of net periodic pension and postretirement benefit costs. See Note 8 for details regarding these benefit plans. |
Segments and Related Informat90
Segments and Related Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Segment Reporting Information [Line Items] | ||||||||||||
Intercompany Revenue | $ 6,000 | $ 13,000 | $ 13,000 | |||||||||
Operating revenues | $ 1,000,766 | $ 1,030,293 | $ 930,916 | $ 1,080,534 | $ 1,020,926 | $ 1,059,177 | $ 909,852 | $ 1,057,841 | 4,042,509 | 4,047,796 | 4,163,513 | |
Depreciation and amortization | 471,515 | 443,555 | 411,667 | |||||||||
Total interest charges and financing costs | 179,287 | 174,586 | 171,908 | |||||||||
Income tax expense (benefit) | 252,179 | 273,918 | 278,440 | |||||||||
Net income (loss) | $ 95,909 | $ 186,077 | $ 100,587 | $ 111,546 | $ 86,666 | $ 173,607 | $ 87,344 | $ 115,874 | 494,119 | 463,491 | 466,802 | |
Regulated Electric | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 3,004,096 | 3,049,627 | 3,115,558 | |||||||||
Depreciation and amortization | 353,560 | 337,583 | 311,122 | |||||||||
Total interest charges and financing costs | 138,565 | 136,274 | 136,397 | |||||||||
Income tax expense (benefit) | 243,604 | 228,825 | 234,873 | |||||||||
Net income (loss) | 370,636 | 383,973 | 391,257 | |||||||||
Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 995,558 | 957,831 | 1,006,733 | |||||||||
Depreciation and amortization | 113,253 | 101,663 | 96,384 | |||||||||
Total interest charges and financing costs | 40,214 | 37,881 | 34,935 | |||||||||
Income tax expense (benefit) | 18,398 | 45,960 | 44,192 | |||||||||
Net income (loss) | 107,822 | 75,426 | 74,267 | |||||||||
All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 43,487 | 40,723 | 41,590 | |||||||||
Depreciation and amortization | 4,702 | 4,309 | 4,161 | |||||||||
Total interest charges and financing costs | 508 | 431 | 576 | |||||||||
Income tax expense (benefit) | (9,823) | (867) | (625) | |||||||||
Net income (loss) | 15,661 | 4,092 | 1,278 | |||||||||
Operating Segments | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 4,042,509 | 4,047,796 | 4,163,513 | ||||||||
Operating Segments | Regulated Electric | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 3,003,808 | 3,049,352 | 3,115,257 | ||||||||
Operating Segments | Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 995,214 | 957,721 | 1,006,666 | ||||||||
Operating Segments | All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 43,487 | 40,723 | 41,590 | ||||||||
Intersegment Eliminations | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | (632) | (385) | (368) | |||||||||
Depreciation and amortization | 0 | 0 | 0 | |||||||||
Total interest charges and financing costs | 0 | 0 | 0 | |||||||||
Income tax expense (benefit) | 0 | 0 | 0 | |||||||||
Net income (loss) | 0 | 0 | 0 | |||||||||
Intersegment Eliminations | Regulated Electric | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 288 | 275 | 301 | |||||||||
Intersegment Eliminations | Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 344 | 110 | 67 | |||||||||
Intersegment Eliminations | All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | $ 0 | $ 0 | $ 0 | |||||||||
[1] | Operating revenues include $6 million, $13 million and $13 million of intercompany revenue for the years ended Dec. 31, 2017, 2016 and 2015, respectively. See Note 16 for further discussion of related party transactions by reportable segment. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating revenues | |||
Electric | $ 1,436 | $ 8,809 | $ 8,632 |
Other | 4,492 | 4,525 | 4,441 |
Operating expenses | |||
Purchased power | 2 | 56 | 0 |
Other operating expenses - paid to Xcel Energy Services Inc. | 485,066 | 446,086 | 414,620 |
Interest expense | 0 | 149 | 211 |
Interest income | 0 | 0 | $ 45 |
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 14,719 | 9,421 | |
Accounts payable | 58,748 | 98,797 | |
NSP-Minnesota | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 7,738 | 7,669 | |
Accounts payable | 0 | 0 | |
NSP-Wisconsin | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 61 | 974 | |
Accounts payable | 0 | 0 | |
SPS | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 279 | 745 | |
Accounts payable | 0 | 0 | |
Other subsidiaries of Xcel Energy Inc. | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 6,641 | 33 | |
Accounts payable | $ 58,748 | $ 98,797 |
Summarized Quarterly Financia92
Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 1,000,766 | $ 1,030,293 | $ 930,916 | $ 1,080,534 | $ 1,020,926 | $ 1,059,177 | $ 909,852 | $ 1,057,841 | $ 4,042,509 | $ 4,047,796 | $ 4,163,513 |
Operating income | 154,669 | 326,028 | 192,811 | 212,422 | 170,197 | 315,605 | 180,629 | 223,190 | 885,930 | 889,621 | 899,701 |
Net income | $ 95,909 | $ 186,077 | $ 100,587 | $ 111,546 | $ 86,666 | $ 173,607 | $ 87,344 | $ 115,874 | $ 494,119 | $ 463,491 | $ 466,802 |
Schedule II, Valuation and Qu93
Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Jan. 1 | $ 19,612 | $ 20,122 | $ 23,122 | |
Charged to costs and expenses | 14,303 | 14,121 | 13,052 | |
Charged to other accounts | [1] | 3,968 | 4,447 | 5,175 |
Deductions from reserves | [2] | 18,277 | 19,078 | 21,227 |
Balance at Dec. 31 | $ 19,606 | $ 19,612 | $ 20,122 | |
[1] | Recovery of amounts previously written off. | |||
[2] | Deductions relate primarily to bad debt write-offs. |