Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 22, 2016 | Jun. 30, 2015 | |
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 | ||
Document Type | 10-K | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Entity Common Stock, Shares Outstanding | 100 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues | |||
Electric | $ 3,115,257 | $ 3,125,937 | $ 3,081,171 |
Natural gas | 1,006,666 | 1,215,324 | 1,080,703 |
Steam and other | 41,590 | 41,888 | 40,754 |
Total operating revenues | 4,163,513 | 4,383,149 | 4,202,628 |
Operating expenses | |||
Electric fuel and purchased power | 1,246,666 | 1,405,498 | 1,335,818 |
Cost of natural gas sold and transported | 501,824 | 725,754 | 621,120 |
Cost of sales — steam and other | 17,788 | 16,831 | 17,039 |
Operating and maintenance expenses | 761,901 | 751,786 | 762,322 |
Demand side management program expenses | 128,681 | 139,780 | 139,337 |
Depreciation and amortization | 411,667 | 379,202 | 360,417 |
Taxes (other than income taxes) | 195,285 | 161,928 | 137,816 |
Total operating expenses | 3,263,812 | 3,580,779 | 3,373,869 |
Operating income | 899,701 | 802,370 | 828,759 |
Other income, net | 2,964 | 4,265 | 3,136 |
Allowance for funds used during construction — equity | 14,485 | 46,784 | 33,173 |
Interest charges and financing costs | |||
Interest charges — includes other financing costs of $6,285, $6,340, and $6,866, respectively | 177,430 | 171,881 | 173,602 |
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt | (5,522) | (17,241) | (12,657) |
Total interest charges and financing costs | 171,908 | 154,640 | 160,945 |
Income before income taxes | 745,242 | 698,779 | 704,123 |
Income taxes | 278,440 | 243,591 | 250,740 |
Net income | $ 466,802 | $ 455,188 | $ 453,383 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Interest charges and financing costs | |||
Other financing costs | $ 6,285 | $ 6,340 | $ 6,866 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Comprehensive income: | |||
Net income | $ 466,802 | $ 455,188 | $ 453,383 |
Derivative instruments: | |||
Net fair value (decrease) increase, net of tax of $(20), $(43) and $5, respectively | (30) | (72) | 9 |
Reclassification of losses (gains) to net income, net of tax of $39, $(287) and $(294), respectively | 72 | (468) | (476) |
Other comprehensive income (loss) | 42 | (540) | (467) |
Comprehensive income | $ 466,844 | $ 454,648 | $ 452,916 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative instruments: | |||
Net fair value (decrease) increase, tax | $ (20) | $ 5 | $ (5,708) |
Reclassification of losses (gains) to net income, tax | $ 39 | $ (294) | $ (725) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating activities | |||
Net income | $ 466,802 | $ 455,188 | $ 453,383 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation and amortization | 416,427 | 383,992 | 365,713 |
Demand side management program amortization | 3,509 | 4,331 | 4,802 |
Deferred income taxes | 277,896 | 227,823 | 316,253 |
Amortization of Investment Tax Credits | (2,807) | (2,941) | (2,935) |
Allowance for equity funds used during construction | (14,485) | (46,784) | (33,173) |
Provision for bad debts | 13,052 | 17,005 | 16,784 |
Net realized and unrealized hedging and derivative transactions | 2,414 | (2,578) | (3,571) |
Other Operating Activities, Cash Flow Statement | 2,500 | 0 | 0 |
Changes in operating assets and liabilities: | |||
Accounts receivable | 8,872 | (42,921) | 5,089 |
Accrued unbilled revenues | 17,837 | (23,132) | 14,707 |
Inventories | 33,417 | (972) | (14,857) |
Prepayments and other | 10,483 | (81,715) | (7,210) |
Accounts payable | (40,982) | (22,789) | 59,361 |
Net regulatory assets and liabilities | 78,055 | 130,499 | 108,400 |
Other current liabilities | 19,654 | 5,284 | 16,561 |
Pension and other employee benefit obligations | (23,449) | (38,905) | (48,886) |
Change in other noncurrent assets | 4,086 | 5,537 | 3,862 |
Change in other noncurrent liabilities | (35,334) | (19,130) | 17,191 |
Net cash provided by (used in) operating activities | 1,237,947 | 947,792 | 1,271,474 |
Investing activities | |||
Utility capital/construction expenditures | (995,597) | (1,114,338) | (1,066,700) |
Allowance for equity funds used during construction | 14,485 | 46,784 | 33,173 |
Investments in utility money pool arrangement | (196,300) | (603,000) | (1,495,000) |
Repayments from utility money pool arrangement | 212,300 | 659,000 | 1,423,000 |
Net cash provided by (used in) investing activities | (965,112) | (1,011,554) | (1,105,527) |
Financing activities | |||
Proceeds from (repayments of) short-term borrowings, net | (368,000) | 382,000 | (154,000) |
Borrowings under utility money pool arrangement | 165,000 | 333,000 | 14,000 |
Repayments under utility money pool arrangement | (165,000) | (333,000) | (14,000) |
Proceeds from issuance of long-term debt | 246,751 | 295,598 | 492,313 |
Repayments of long-term debt | 0 | (275,000) | (250,000) |
Capital contributions from parent | 175,210 | 81,498 | 25,621 |
Dividends paid to parent | (330,846) | (433,788) | (263,942) |
Net cash provided by (used in) financing activities | (276,885) | 50,308 | (150,008) |
Net change in cash and cash equivalents | (4,050) | (13,454) | 15,939 |
Cash and cash equivalents at beginning of period | 7,635 | 21,089 | 5,150 |
Cash and cash equivalents at end of period | 3,585 | 7,635 | 21,089 |
Supplemental disclosure of cash flow information: | |||
Cash paid for interest (net of amounts capitalized) | (165,546) | (150,011) | (155,457) |
Cash received (paid) for income taxes, net | 13,822 | (91,810) | 34,946 |
Supplemental disclosure of non-cash investing transactions: | |||
Property, plant and equipment additions in accounts payable | $ 106,912 | $ 139,616 | $ 142,103 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Current assets | |||
Cash and cash equivalents | $ 3,585 | $ 7,635 | |
Accounts receivable, net | 300,882 | 322,885 | |
Accounts receivable from affiliates | 4,909 | 50,842 | |
Investments in utility money pool arrangement | 0 | 16,000 | |
Accrued unbilled revenues | 276,212 | 294,049 | |
Inventories | 205,562 | 238,979 | |
Regulatory assets | 92,072 | 120,120 | |
Deferred income taxes | 62,662 | 64,587 | |
Derivative instruments | 1,945 | 1,731 | |
Prepaid Taxes | 81,162 | 90,365 | |
Prepayments and other | 22,698 | 23,979 | |
Total current assets | 1,051,689 | 1,231,172 | |
Property, plant and equipment, net | 12,172,211 | 11,626,956 | |
Other assets | |||
Regulatory assets | 906,275 | 903,973 | |
Derivative instruments | 3,478 | 5,176 | |
Other | 44,819 | 48,506 | |
Total other assets | 954,572 | 957,655 | |
Total assets | 14,178,472 | 13,815,783 | |
Current liabilities | |||
Current portion of long-term debt | 8,103 | 8,178 | |
Short-term debt | 14,000 | 382,000 | |
Accounts payable | 352,701 | 425,133 | |
Accounts payable to affiliates | 76,643 | 46,736 | |
Regulatory liabilities | [1] | 152,823 | 134,459 |
Taxes accrued | 166,660 | 159,470 | |
Accrued interest | 49,698 | 48,409 | |
Dividends payable to parent | 83,374 | 83,652 | |
Derivative instruments | 8,881 | 5,774 | |
Other | 78,910 | 72,002 | |
Total current liabilities | 991,793 | 1,365,813 | |
Deferred credits and other liabilities | |||
Deferred income taxes | 2,720,860 | 2,437,641 | |
Deferred investment tax credits | 33,466 | 36,273 | |
Regulatory liabilities | 471,421 | 464,421 | |
Asset retirement obligations | 240,508 | 225,296 | |
Derivative instruments | 13,020 | 18,257 | |
Customer advances | 198,526 | 229,990 | |
Pension and employee benefit obligations | 200,774 | 202,031 | |
Other | 63,864 | 68,171 | |
Total deferred credits and other liabilities | $ 3,942,439 | $ 3,682,080 | |
Commitments and contingencies | |||
Capitalization | |||
Long-term debt | $ 4,124,088 | $ 3,882,051 | |
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively | 0 | 0 | |
Additional paid in capital | 3,620,824 | 3,522,788 | |
Retained earnings | 1,523,164 | 1,386,929 | |
Accumulated other comprehensive loss | (23,836) | (23,878) | |
Total common stockholder’s equity | 5,120,152 | 4,885,839 | |
Total liabilities and equity | $ 14,178,472 | $ 13,815,783 | |
[1] | Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities. |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
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, 2012 | $ 4,585,735 | $ 0 | $ 3,415,669 | $ 1,192,937 | $ (22,871) |
Balance (in shares) at Dec. 31, 2012 | 100 | ||||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | 453,383 | 453,383 | |||
Other comprehensive income (loss) | (467) | (467) | |||
Common dividends declared to parent | (262,273) | (262,273) | |||
Contribution of capital by parent | 25,621 | 25,621 | |||
Ending Balance at Dec. 31, 2013 | 4,801,999 | $ 0 | 3,441,290 | 1,384,047 | (23,338) |
Balance (in shares) at Dec. 31, 2013 | 100 | ||||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | 455,188 | 455,188 | |||
Other comprehensive income (loss) | (540) | (540) | |||
Common dividends declared to parent | (452,306) | (452,306) | |||
Contribution of capital by parent | 81,498 | 81,498 | |||
Ending 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 | 100 | |||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | $ 466,802 | 466,802 | |||
Other comprehensive income (loss) | 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 | 100 |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Capitalization, Long-term Debt [Line Items] | |||
Debt Instrument, Unamortized Discount (Premium), Net | $ (11,340) | $ (11,480) | |
Total long-term debt | 4,132,191 | 3,890,229 | |
Less current maturities | 8,103 | 8,178 | |
Long-term Debt and Capital Lease Obligations | 4,124,088 | 3,882,051 | |
Common Stockholder's Equity | |||
Common Stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2015 and 2014, respectively. | 0 | 0 | |
Additional paid in capital | 3,620,824 | 3,522,788 | |
Retained earnings | 1,523,164 | 1,386,929 | |
Accumulated other comprehensive loss | (23,836) | (23,878) | |
Total common stockholder’s equity | 5,120,152 | 4,885,839 | |
First Mortgage Bonds | Series Due Sept. 1, 2017 | |||
Schedule of Capitalization, Long-term Debt [Line Items] | |||
Long-term debt, gross | [1] | 129,500 | 129,500 |
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 [Member] | |||
Schedule of Capitalization, Long-term Debt [Line Items] | |||
Long-term debt, gross | 250,000 | 0 | |
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 | |
Capital Lease Obligations | |||
Schedule of Capitalization, Long-term Debt [Line Items] | |||
Capital lease obligations | $ 164,031 | $ 172,209 | |
[1] | Pollution control financing. |
CONSOLIDATED STATEMENTS OF CA11
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Common Stockholder's Equity | ||
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 Sept. 1, 2017 | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 4.375% | 4.375% |
Debt instrument, maturity date | Sep. 1, 2017 | Sep. 1, 2017 |
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 [Member] | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Interest rate, stated percentage (in hundredths) | 2.90% | |
Debt instrument, maturity date | 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 |
Capital Lease Obligations | ||
Schedule of Capitalization, Long-term Debt [Line Items] | ||
Debt instrument, interest rate, stated percentage rate range, minimum (in hundredths) | 11.20% | |
Debt instrument, interest rate, stated percentage rate range, maximum (in hundredths) | 14.30% | |
Debt instrument, maturity date range, end | Dec. 31, 2060 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
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 but not limited to, 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 for alternative revenue recognition under generally accepted accounting principles. 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 commercial and industrial 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 that is required to be decommissioned early by a regulator is reclassified as plant to be retired. 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 , 2.7 and 2.8 percent for the years ended Dec. 31, 2015 , 2014 and 2013 , 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 income in the period that includes the enactment date. 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. 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 only applies to federal ITCs. 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. 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 or 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 net asset values. 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. See Note 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, 2015 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, 2015 | |
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 framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s July 2015 deferral of the standard’s required implementation date, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. PSCo does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, PSCo does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. This guidance will be effective on a retrospective basis, effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, PSCo does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements. Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which removes the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, PSCo does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements. 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 among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, 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 will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 12 Months Ended |
Dec. 31, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 321,004 $ 346,007 Less allowance for bad debts (20,122 ) (23,122 ) $ 300,882 $ 322,885 (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 58,128 $ 55,491 Fuel 78,586 80,963 Natural gas 68,848 102,525 $ 205,562 $ 238,979 (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 11,856,126 $ 10,927,867 Natural gas plant 3,420,249 3,210,242 Common and other property 862,840 827,708 Plant to be retired (a) 38,249 71,534 Construction work in progress 408,963 828,620 Total property, plant and equipment 16,586,427 15,865,971 Less accumulated depreciation (4,414,216 ) (4,239,015 ) $ 12,172,211 $ 11,626,956 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 12 Months Ended |
Dec. 31, 2015 | |
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. Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2015 Borrowing limit $ 250 Amount outstanding at period end — Average amount outstanding 4 Maximum amount outstanding 34 Weighted average interest rate, computed on a daily basis 0.36 % Weighted average interest rate at period end N/A (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Twelve Months Ended Dec. 31, 2013 Borrowing limit $ 250 $ 250 $ 250 Amount outstanding at period end — — — Average amount outstanding 1 4 — Maximum amount outstanding 34 97 12 Weighted average interest rate, computed on a daily basis 0.41 % 0.25 % 0.36 % 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. Commercial paper borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2014 Borrowing limit $ 700 Amount outstanding at period end 14 Average amount outstanding 14 Maximum amount outstanding 68 Weighted average interest rate, computed on a daily basis 0.50 % Weighted average interest rate at period end 0.60 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Twelve Months Ended Dec. 31, 2013 Borrowing limit $ 700 $ 700 $ 700 Amount outstanding at period end 14 382 — Average amount outstanding 95 167 38 Maximum amount outstanding 449 393 332 Weighted average interest rate, computed on a daily basis 0.51 % 0.31 % 0.34 % Weighted average interest rate at period end 0.60 0.65 N/A Letters of Credit — PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2015 and 2014, there were $4 million and $6 million of letters of credit outstanding, respectively, 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. Credit Agreement — PSCo has a five -year credit agreement with a syndicate of banks. The total size of the credit facility is $700 million and the credit facility matures in October 2019. PSCo has the right to request an extension of the termination date for two additional one -year periods. All 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 45 percent and 47 percent at Dec. 31, 2015 and 2014, 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, 2015 and 2014. • The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings. • The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year. At Dec. 31, 2015 , PSCo had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 700 $ 18 $ 682 (a) This credit facility matures in October 2019. (b) Includes outstanding commercial paper and 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, 2015 and 2014 . 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 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025 . In 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044 . During the next five years, PSCo has long-term debt maturities of $130 million , $300 million , $400 million and $400 million due in 2017, 2018, 2019 and 2020, respectively. Deferred Financing Costs — Other assets included deferred financing costs of approximately $26.6 million and $26.5 million , net of amortization, at Dec. 31, 2015 and 2014 , 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, 2015 | |
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, 2015 | |
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, 2015 : (Thousands of Dollars) Plant in Service Accumulated CWIP Ownership % Electric Generation: Hayden Unit 1 $ 155,159 $ 69,679 $ 147 76 % Hayden Unit 2 121,486 61,780 20,840 37 Hayden Common Facilities 37,756 17,910 321 53 Craig Units 1 and 2 60,158 36,570 8,518 10 Craig Common Facilities 1, 2 and 3 37,418 18,520 505 7 Comanche Unit 3 892,340 95,029 452 67 Comanche Common Facilities 23,826 1,430 894 82 Electric Transmission: Transmission and other facilities, including substations 152,460 62,324 5,378 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 19,928 7,165 — 60 Gas Transportation Compressor $ 8,353 $ 124 $ 127 50 Total $ 1,508,884 $ 370,531 $ 37,182 PSCo has approximately 820 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, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Consolidated Appropriations Act, 2016 - In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following: • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation; • PTCs at 100 percent of the credit rate ( $0.023 per KWh) 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. Tax Increase Prevention Act of 2014 — In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following: • The R&E credit was extended for 2014; • PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and • 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation. The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment. American Taxpayer Relief Act of 2012 — In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following: • The top tax rate for dividends increased from 15 percent to 20 percent . The 20 percent dividend rate is now consistent with the tax rates for capital gains; • The R&E credit was extended for 2012 and 2013; • PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and • 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation. The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for 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. In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of Dec. 31, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. PSCo is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Dec. 31, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2015, 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, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 2.4 $ 1.9 Unrecognized tax benefit — Temporary tax positions 15.0 10.0 Total unrecognized tax benefit $ 17.4 $ 11.9 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2015 2014 2013 Balance at Jan. 1 $ 11.9 $ 8.4 $ 9.6 Additions based on tax positions related to the current year 4.5 3.7 3.9 Reductions based on tax positions related to the current year (1.5 ) (0.7 ) — Additions for tax positions of prior years 2.5 2.8 3.3 Reductions for tax positions of prior years — (1.2 ) (0.9 ) Settlements with taxing authorities — (1.1 ) (7.5 ) Balance at Dec. 31 $ 17.4 $ 11.9 $ 8.4 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, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (4.3 ) $ (3.9 ) It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress and state audits resume. As the IRS Appeals and audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $11 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2015, 2014 and 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2015, 2014 or 2013. 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) 2015 2014 Federal NOL carryforward $ 328 $ 320 Federal tax credit carryforwards 24 22 State NOL carryforwards 684 690 State tax credit carryforwards, net of federal detriment (a) 13 12 Valuation allowances for state credit carryforwards, net of federal detriment (b) (1 ) — (a) State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2015 and 2014, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million as of Dec. 31, 2015. The federal carryforward periods expire between 2021 and 2035 . The state carryforward periods expire between 2017 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: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 3.2 2.8 3.0 Change in unrecognized tax benefits 0.1 (0.1 ) 0.1 Regulatory differences — utility plant items (0.3 ) (2.1 ) (1.4 ) Tax credits recognized, net of federal income tax expense (0.7 ) (0.8 ) (0.8 ) Other, net 0.1 0.1 (0.3 ) Effective income tax rate 37.4 % 34.9 % 35.6 % The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2015 2014 2013 Current federal tax (benefit) expense $ (1,166 ) $ 9,550 $ (52,408 ) Current state tax (benefit) expense (727 ) 2,611 (7,252 ) Current change in unrecognized tax expense (benefit) 5,244 6,548 (2,918 ) Deferred federal tax expense 246,096 208,781 273,916 Deferred state tax expense 36,450 26,196 38,243 Deferred change in unrecognized tax (benefit) expense (4,650 ) (7,154 ) 4,094 Deferred investment tax credits (2,807 ) (2,941 ) (2,935 ) Total income tax expense $ 278,440 $ 243,591 $ 250,740 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2015 2014 2013 Deferred tax expense excluding items below $ 285,144 $ 254,142 $ 335,580 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (7,229 ) (26,649 ) (19,616 ) Tax benefit allocated to other comprehensive income and other (19 ) 330 289 Deferred tax expense $ 277,896 $ 227,823 $ 316,253 The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows: (Thousands of Dollars) 2015 2014 Deferred tax liabilities: Differences between book and tax bases of property $ 2,772,043 $ 2,467,260 Employee benefits 105,049 110,556 Other 101,219 140,080 Total deferred tax liabilities $ 2,978,311 $ 2,717,896 Deferred tax assets: NOL carryforward $ 147,763 $ 143,158 Unbilled revenue - fuel costs 48,181 57,654 Rate refund 23,352 43,735 Tax credit carryforward 35,240 34,493 Regulatory liabilities 17,201 14,549 Deferred investment tax credits 12,718 13,781 Other 35,658 37,472 Total deferred tax assets $ 320,113 $ 344,842 Net deferred tax liability $ 2,658,198 $ 2,373,054 |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [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 77 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2015, PSCo had 2,024 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017. 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 net asset values. 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 equity securities and other funds — Equity securities are valued using quoted prices in active markets. Preferred stock is valued using recent trades and quoted prices of similar securities. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, 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 net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two 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. Unscheduled distributions from real estate investments 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. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3. 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. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2015 and 2014 were $41.8 million and $46.5 million , respectively, of which $3.6 million and $3.8 million were attributable to PSCo. In 2015 and 2014 , Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $9.5 million and $4.7 million , respectively, of which $0.6 million in each year was attributable to PSCo. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows. 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 the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term. • Investment returns in 2015 were below the assumed level of 6.81 percent ; • Investment returns in 2014 were above the assumed level of 6.81 percent ; • Investment returns in 2013 were below the assumed level of 6.47 percent ; and • In 2016 , 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 a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, 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: 2015 2014 Domestic and international equity securities 36 % 32 % Long-duration fixed income and interest rate swap securities 32 35 Short-to-intermediate fixed income securities 12 12 Alternative investments 18 18 Cash 2 3 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, 2015 and 2014 : Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 81,954 $ — $ — $ 81,954 Derivatives — 1,204 — 1,204 Government securities — 214,341 — 214,341 Corporate bonds — 86,914 — 86,914 Asset-backed securities — 881 — 881 Common stock 28,797 — — 28,797 Private equity investments — — 34,353 34,353 Commingled funds — 573,009 — 573,009 Real estate — — 18,681 18,681 Other — (3,453 ) — (3,453 ) Total $ 110,751 $ 872,896 $ 53,034 $ 1,036,681 Dec. 31, 2014 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 82,486 $ — $ — $ 82,486 Derivatives — 508 — 508 Government securities — 180,912 — 180,912 Corporate bonds — 115,593 — 115,593 Asset-backed securities — 1,360 — 1,360 Mortgage-backed securities — 3,997 — 3,997 Common stock 37,067 — — 37,067 Private equity investments — — 50,210 50,210 Commingled funds — 629,439 — 629,439 Real estate — — 18,410 18,410 Securities lending collateral obligation and other — (16,117 ) — (16,117 ) Total $ 119,553 $ 915,692 $ 68,620 $ 1,103,865 The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2015 , 2014 and 2013 : (Thousands of Dollars) Jan. 1, 2015 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 Dec. 31, 2015 Private equity investments $ 50,210 $ 7,636 $ (20,036 ) $ (3,457 ) $ — $ 34,353 Real estate 18,410 1,925 (2,371 ) 717 — 18,681 Total $ 68,620 $ 9,561 $ (22,407 ) $ (2,740 ) $ — $ 53,034 (Thousands of Dollars) Jan. 1, 2014 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 Dec. 31, 2014 Private equity investments $ 49,022 $ 8,495 $ (4,299 ) $ (3,008 ) $ — $ 50,210 Real estate 15,556 1,180 (302 ) 1,976 — 18,410 Total $ 64,578 $ 9,675 $ (4,601 ) $ (1,032 ) $ — $ 68,620 (Thousands of Dollars) Jan. 1, 2013 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 (a) Dec. 31, 2013 Asset-backed securities $ 4,604 $ — $ — $ — $ (4,604 ) $ — Mortgage-backed securities 12,058 — — — (12,058 ) — Private equity investments 47,056 7,074 (4,027 ) (1,081 ) — 49,022 Real estate 19,273 (870 ) 3,769 3,048 (9,664 ) 15,556 Total $ 82,991 $ 6,204 $ (258 ) $ 1,967 $ (26,326 ) $ 64,578 (a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. 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) 2015 2014 Accumulated Benefit Obligation at Dec. 31 $ 1,192,798 $ 1,249,739 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 1,277,957 $ 1,152,836 Service cost 28,260 23,939 Interest cost 50,857 53,277 Transfer to other plan (2,938 ) (13,404 ) Actuarial (gain) loss (54,737 ) 133,215 Benefit payments (74,749 ) (71,906 ) Obligation at Dec. 31 $ 1,224,650 $ 1,277,957 (Thousands of Dollars) 2015 2014 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 1,103,865 $ 1,067,057 Actual (loss) return on plan assets (9,122 ) 84,871 Employer contributions 20,056 35,156 Transfer to other plan (3,369 ) (11,313 ) Benefit payments (74,749 ) (71,906 ) Fair value of plan assets at Dec. 31 $ 1,036,681 $ 1,103,865 (Thousands of Dollars) 2015 2014 Funded Status of Plans at Dec. 31: Funded status (a) $ (187,969 ) $ (174,092 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. (Thousands of Dollars) 2015 2014 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 521,703 $ 530,674 Prior service credit (15,572 ) (18,708 ) Total $ 506,131 $ 511,966 (Thousands of Dollars) 2015 2014 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 $ 28,852 $ 31,774 Noncurrent regulatory assets 477,279 480,192 Total $ 506,131 $ 511,966 Measurement date Dec. 31, 2015 Dec. 31, 2014 2015 2014 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.66 % 4.11 % Expected average long-term increase in compensation level 4.00 3.75 Mortality table RP 2014 RP 2014 Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. PSCo has reviewed its own population through a credibility analysis and adopted the RP 2014 table, with modifications, based on its population and specific experience. During 2015, a new projection table was released (MP 2015). PSCo evaluated the updated projection table and concluded that the methodology adopted at Dec. 31, 2014 is consistent with the recently updated table and continues to be representative of its 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 2013 through 2016 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $125.0 million in January 2016, of which $16.8 million was attributable to PSCo; • $90.1 million in 2015, of which $20.1 million was attributable to PSCo; • $130.6 million in 2014, of which $35.2 million was attributable to PSCo; and • $192.4 million in 2013, of which $44.6 million was attributable to PSCo. For future years, Xcel Energy and PSCo anticipate contributions will be made as necessary. Plan Amendments — In 2015 and 2014, there were no plan amendments made which affected the benefit obligation. Benefit Costs — The components of PSCo’s net periodic pension cost were: (Thousands of Dollars) 2015 2014 2013 Service cost $ 28,260 $ 23,939 $ 25,206 Interest cost 50,857 53,277 46,160 Expected return on plan assets (72,590 ) (70,709 ) (63,821 ) Amortization of prior service credit (3,136 ) (3,092 ) (1,064 ) Amortization of net loss 36,377 33,892 43,418 Net periodic pension cost 39,768 37,307 49,899 Costs not recognized due to effects of regulation (1,464 ) — — Net benefit cost recognized for financial reporting $ 38,304 $ 37,307 $ 49,899 2015 2014 2013 Significant Assumptions Used to Measure Costs: Discount rate 4.11 % 4.75 % 4.00 % Expected average long-term increase in compensation level 3.75 3.75 3.75 Expected average long-term rate of return on assets 6.81 6.81 6.47 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 $9.9 million , $9.4 million and $11.6 million in 2015 , 2014 and 2013 , 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 2016 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 $9.5 million in 2015 , $9.1 million in 2014 and $8.7 million in 2013 . 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: 2015 2014 Domestic and international equity securities 25 % 25 % Short-to-intermediate fixed income securities 57 57 Alternative investments 13 13 Cash 5 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 the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, 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, 2015 and 2014 : Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 17,524 $ — $ — $ 17,524 Government securities — 35,016 — 35,016 Insurance contracts — 42,123 — 42,123 Corporate bonds — 65,031 — 65,031 Asset-backed securities — 25,602 — 25,602 Mortgage-backed securities — 31,778 — 31,778 Commingled funds — 182,736 — 182,736 Other — (368 ) — (368 ) Total $ 17,524 $ 381,918 $ — $ 399,442 Dec. 31, 2014 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents (a) $ 23,566 $ — $ — $ 23,566 Derivatives — 166 — 166 Government securities — 43,494 — 43,494 Insurance contracts — 45,075 — 45,075 Corporate bonds — 48,527 — 48,527 Asset-backed securities — 3,240 — 3,240 Mortgage-backed securities — 10,071 — 10,071 Commingled funds — 252,790 — 252,790 Other — (1,647 ) — (1,647 ) Total $ 23,566 $ 401,716 $ — $ 425,282 (a) Includes restricted cash of $0.9 million at Dec. 31, 2014. For the years ended Dec. 31, 2015 and 2014, there were no assets transferred in or out of Level 3. The following table presents the changes in PSCo’s Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2013 : (Thousands of Dollars) Jan. 1, 2013 Net Realized Net Unrealized Purchases, Transfers Out of Level 3 (a) Dec. 31, 2013 Asset-backed securities $ 670 $ — $ — $ — $ (670 ) $ — Mortgage-backed securities 35,394 — — — (35,394 ) — Total $ 36,064 $ — $ — $ — $ (36,064 ) $ — (a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2015 2014 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 443,753 $ 508,971 Service cost 928 1,915 Interest cost 17,498 23,704 Medicare subsidy reimbursements 1,712 1,753 Plan participants’ contributions 4,961 4,625 Actuarial gain (32,001 ) (63,130 ) Benefit payments (33,277 ) (34,085 ) Obligation at Dec. 31 $ 403,574 $ 443,753 (Thousands of Dollars) 2015 2014 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 425,282 $ 438,193 Actual (loss) return on plan assets (3,076 ) 11,060 Plan participants’ contributions 4,961 4,625 Employer contributions 5,552 5,489 Benefit payments (33,277 ) (34,085 ) Fair value of plan assets at Dec. 31 $ 399,442 $ 425,282 (Thousands of Dollars) 2015 2014 Funded Status at Dec. 31: Funded status (a) $ (4,132 ) $ (18,471 ) (a) Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. (Thousands of Dollars) 2015 2014 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 49,226 $ 56,823 Prior service credit (33,942 ) (40,189 ) Total $ 15,284 $ 16,634 (Thousands of Dollars) 2015 2014 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 $ 15,284 $ 16,634 Measurement date Dec. 31, 2015 Dec. 31, 2014 2015 2014 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.65 % 4.08 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial 6.00 % 6.50 % Effective Jan. 1, 2016, the initial medical trend rate was decreased from 6.5 percent to 6.0 percent . The ultimate trend assumption remained at 4.5 percent . The period until the ultimate rate is reached is three 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 $ 38,946 $ (33,136 ) Service and interest components 2,093 (1,743 ) 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 $18.3 million , $17.1 million and $17.6 million during 2015 , 2014 and 2013 , respectively, of which $5.6 million , $5.5 million and $7.0 million were attributable to PSCo. Xcel Energy expects to contribute approximately $12.3 million during 2016 , of which amounts attributable to PSCo will be zero . Plan Amendments — In 2015 and 2014 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) 2015 2014 2013 Service cost $ 928 $ 1,915 $ 2,564 Interest cost 17,498 23,704 22,210 Expected return on plan assets (23,803 ) (30,214 ) (29,227 ) Amortization of transition obligation — — 785 Amortization of prior service credit (6,247 ) (6,247 ) (7,666 ) Amortization of net loss 2,475 6,434 13,699 Net periodic postretirement benefit (credit) cost $ (9,149 ) $ (4,408 ) $ 2,365 2015 2014 2013 Significant Assumptions Used to Measure Costs: Discount rate 4.08 % 4.82 % 4.10 % Expected average long-term rate of return on assets 5.80 7.18 7.11 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 2016 $ 77,898 $ 32,197 $ 2,234 $ 29,963 2017 77,952 32,356 2,373 29,983 2018 80,583 32,381 2,517 29,864 2019 82,760 32,402 2,647 29,755 2020 83,372 33,093 2,753 30,340 2021-2025 430,762 158,040 15,450 142,590 |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
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 net asset values. 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. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term 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, 2015, accumulated other comprehensive losses related to interest rate derivatives included $1.0 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 and energy-related instruments. 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. At Dec. 31, 2015, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not 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 immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2015 and 2014. At Dec. 31, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. 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) 2015 2014 MWh of electricity 684 — MMBtu of natural gas 12,515 735 Gallons of vehicle fuel 63 127 (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 considering 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, 2015, three of PSCo’s 10 most significant counterparties for these activities, comprising $1.2 million or 2 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Six of the 10 most significant counterparties, comprising $33.2 million or 48 percent of this credit exposure at Dec. 31, 2015, 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 $4.9 million or 7 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine 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) 2015 2014 2013 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (23,878 ) $ (23,338 ) $ (22,871 ) After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (30 ) (72 ) 9 After-tax net realized losses (gains) on derivative transactions reclassified into earnings 72 (468 ) (476 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (23,836 ) $ (23,878 ) $ (23,338 ) The following tables detail the impact of derivative activity during the years ended Dec. 31, 2015, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2015 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized in Income 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 (e) (7,620 ) (e) Total $ — $ (10,635 ) $ — $ 10,158 $ (7,256 ) Year Ended Dec. 31, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Gains Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (730 ) (a) $ — $ — Vehicle fuel and other commodity (115 ) — (25 ) (b) — — Total $ (115 ) $ — $ (755 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ 451 $ — $ (4,631 ) (e) $ (9,850 ) (e) Total $ — $ 451 $ — $ (4,631 ) $ (9,850 ) Year Ended Dec. 31, 2013 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Losses in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (730 ) (a) $ — $ — Vehicle fuel and other commodity 14 — (40 ) (b) — — Total $ 14 $ — $ (770 ) $ — $ — Other derivative instruments Natural gas commodity — (4,001 ) — 4,340 (e) (5,850 ) (d) Total $ — $ (4,001 ) $ — $ 4,340 $ (5,850 ) (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) Amounts are recorded to electric fuel and purchased power. (e) Amounts for the year ended Dec. 31, 2015 included $1.1 million 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. Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2015, 2014 and 2013 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, 2015, 2014 and 2013. 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 recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit ratings. At Dec. 31, 2015 and 2014, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade. 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, 2015 and 2014. 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, 2015: Dec. 31, 2015 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 $ 137 $ 351 $ — $ 488 $ (324 ) $ 164 Natural gas commodity — 352 — 352 (286 ) 66 Total current derivative assets $ 137 $ 703 $ — $ 840 $ (610 ) 230 PPAs (a) 1,715 Current derivative instruments $ 1,945 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 16 $ — $ 16 $ — $ 16 Total noncurrent derivative assets $ — $ 16 $ — $ 16 $ — 16 PPAs (a) 3,462 Noncurrent derivative instruments $ 3,478 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 92 $ — $ 92 $ — $ 92 Other derivative instruments: Commodity trading 34 325 — 359 (324 ) 35 Natural gas commodity — 3,850 — 3,850 (286 ) 3,564 Total current derivative liabilities $ 34 $ 4,267 $ — $ 4,301 $ (610 ) 3,691 PPAs (a) 5,190 Current derivative instruments $ 8,881 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 33 $ — $ 33 $ — $ 33 Total noncurrent derivative liabilities $ — $ 33 $ — $ 33 $ — 33 PPAs (a) 12,987 Noncurrent derivative instruments $ 13,020 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral 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. 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, 2014: Dec. 31, 2014 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 33 $ — $ 33 $ (18 ) $ 15 Total current derivative assets $ — $ 33 $ — $ 33 $ (18 ) 15 PPAs (a) 1,716 Current derivative instruments $ 1,731 Noncurrent derivative assets PPAs (a) 5,176 Noncurrent derivative instruments $ 5,176 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 53 $ — $ 53 $ — $ 53 Other derivative instruments: Natural gas commodity — 548 — 548 (18 ) 530 Total current derivative liabilities $ — $ 601 $ — $ 601 $ (18 ) 583 PPAs (a) 5,191 Current derivative instruments $ 5,774 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 46 $ — $ 46 $ — $ 46 Other derivative instruments: Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 81 $ — $ 81 $ — 81 PPAs (a) 18,176 Noncurrent derivative instruments $ 18,257 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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, 2014. At Dec. 31, 2014, 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 no changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2015, 2014 and 2013. 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, 2015, 2014 and 2013. Fair Value of Long-Term Debt As of Dec. 31, 2015 and 2014, other financial instruments for which the carrying amount did not equal fair value were as follows: 2015 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,132,191 $ 4,376,875 $ 3,890,229 $ 4,328,968 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, 2015 and 2014, 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, 2015 | |
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) 2015 2014 2013 Interest income $ 753 $ 1,470 $ 1,761 Other nonoperating income 2,408 3,601 2,603 Insurance policy expense (197 ) (806 ) (1,228 ) Other income, net $ 2,964 $ 4,265 $ 3,136 |
Rate Matters
Rate Matters | 12 Months Ended |
Dec. 31, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Pending and Recently Concluded Regulatory Proceedings — CPUC Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $66.2 million over three years . The request was based on a HTY ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the periods in the MYP and an equity ratio of 56 percent . In addition, PSCo requested an extension of its PSIA rider through 2020 to recover costs associated with its pipeline integrity efforts. The rider would recover incremental revenue of $42.8 million over three years . In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate increase $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 Requested ROE 10.1 % 10.1 % 10.3 % Rate base $ 1,260 $ 1,310 $ 1,360 In November 2015, the ALJ issued his recommended decision, which reflected a 2014 HTY with a 13 -month average rate base, the Cherokee pipeline investment adjusted to year-end rate base, a ROE of 9.5 percent and an equity ratio of 56.51 percent . In addition, the ALJ’s recommendation included a three -year extension (2016 through 2018) of the PSIA rider with all O&M expenses transferred to base rates as well as certain other projects shifting between the PSIA rider and base rates, beginning January 2016. The ALJ also recommended that certain expenses, including property taxes and damage prevention costs that exceed the 2014 HTY level, be deferred. He further recommended a pension cost tracker and certain other deferral related items. In February 2016, the CPUC issued their written order. Key matters are as follows: • 2014 HTY, with a 13 -month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level; • Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates; • A ROE of 9.5 percent ; and • An equity ratio of 56.51 percent . The following table reflects the ALJ’s position and the CPUC’s written order (estimated): (Millions of Dollars) ALJ CPUC ’ s Written Order PSCo’s filed 2015 base rate request (a) $ 40.5 $ 40.5 ROE (7.8 ) (7.8 ) Capital structure and cost of debt (0.5 ) (0.5 ) Cherokee pipeline adjustment 4.1 4.1 Move to 2014 HTY (14.1 ) (14.1 ) O&M expenses (3.0 ) (2.4 ) Other, net (1.1 ) (1.1 ) Overall recommended rate increase $ 18.1 $ 18.7 (a) The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016. The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated): ALJ CPUC ’ s Written Order (Millions of Dollars) 2016 2017 2016 2017 PSCo’s filed incremental PSIA request $ 21.7 $ 21.2 $ 21.7 $ 21.2 Transfer PSIA costs to base rates (20.5 ) — (20.5 ) — PSIA cost recovery remaining in base (4.3 ) — (4.3 ) — Projects not recovered through the PSIA (3.6 ) (2.0 ) (3.3 ) (0.8 ) ROE and capital structure (0.3 ) (1.6 ) (0.3 ) (1.6 ) Total $ (7.0 ) $ 17.6 $ (6.7 ) $ 18.8 The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order: (Millions of Dollars) 2015 2016 2017 Base rate increase $ 18.7 $ 19.7 $ — Incremental PSIA rider revenues (0.2 ) (6.7 ) 18.8 Expense deferrals, net amortization (a) (3.6 ) 1.5 5.2 Estimated pre-tax impact $ 14.9 $ 14.5 $ 24.0 (a) Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case. Interim rates, subject to refund, went into effect Oct. 1, 2015. PSCo has recognized management’s best estimate of the potential customer refund obligation. Colorado 2015 Steam Rate Case — In November 2015, PSCo filed a request to increase Colorado retail steam rates by $3.5 million in 2016. In December 2015, the CPUC approved the filed request which recovers costs related to upgrades for the state steam plant as well as the Zuni Station and permits use of the Zuni Station exclusively for steam business. Final rates are implemented in two steps with $2.8 million , which began on Jan. 1, 2016, and the remaining $0.7 million which will be effective Nov. 1, 2016. Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test in which PSCo shares with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Dec. 31, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test of $15 million . PSCo will file its 2015 earnings test with the CPUC in April 2016. The final sharing obligation 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 — 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. Savings goals were 384 GWh in 2014 and 400 GWh in 2015 with incentives 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 . For the years 2016 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million . In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan: • A 2015 DSM electric budget of $81.6 million and a natural gas budget of $13.1 million ; and • A 2016 DSM electric budget of $78.7 million and a natural gas budget of $13.6 million . REC Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. PSCo credited to the RESA regulatory liability balance approximately $5.5 million and $0.6 million in 2015 and 2014, respectively. The cumulative credit to the RESA regulatory liability balance was $110.6 million and $105.1 million at Dec. 31, 2015 and Dec. 31, 2014, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. The current sharing mechanism, without modification, extends through 2017. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
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: 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 2016 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, 2015 , are as follows: (Millions of Dollars) Coal Natural gas supply Natural gas 2016 $ 302.3 $ 231.1 $ 137.5 2017 230.3 129.5 137.2 2018 118.5 181.0 85.5 2019 42.0 187.6 51.0 2020 43.6 203.4 50.4 Thereafter 332.3 409.6 773.2 Total $ 1,069.0 $ 1,342.2 $ 1,234.8 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 2032 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 certain contract obligations, including plant availability requirements. Certain 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 $69.5 million , $69.5 million and $72.7 million in 2015 , 2014 and 2013 , respectively. At Dec. 31, 2015 , the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity Energy (a) 2016 $ 44.5 $ 25.3 2017 24.3 4.4 2018 19.2 — 2019 10.3 — 2020 1.5 — Thereafter 9.5 — Total $ 109.3 $ 29.7 (a) Excludes contingent energy payments for renewable energy PPAs. 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 used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. 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 was formed as 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 $132.9 million and $138.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2015 and 2014 , 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 $8.2 million , $7.2 million , and $6.3 million for 2015 , 2014 and 2013 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2015 Dec. 31, 2014 Gas storage facilities $ 200.5 $ 200.5 Gas pipeline 20.7 20.7 Property held under capital leases 221.2 221.2 Accumulated depreciation (57.2 ) (49.0 ) Total property held under capital leases, net $ 164.0 $ 172.2 The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases. Total expenses under operating lease obligations were approximately $130.5 million , $126.2 million and $96.6 million for 2015 , 2014 and 2013 , respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $113.5 million , $110.1 million and $79.6 million in 2015 , 2014 and 2013 , 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 2016 $ 12.0 $ 102.2 $ 114.2 $ 29.3 2017 7.8 95.8 103.6 25.7 2018 7.4 96.0 103.4 25.3 2019 7.4 96.9 104.3 25.1 2020 7.4 97.7 105.1 24.9 Thereafter 39.5 579.7 619.2 486.5 Total minimum obligation 616.8 Interest component of obligation (452.8 ) Present value of minimum obligation $ 164.0 (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2032 . 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 associated 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 in the future, 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 1,802 MW of capacity under long-term PPAs as of Dec. 31, 2015 , and 2014 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. MGP Sites — PSCo is currently involved in investigating and/or remediating several MGP sites where regulated materials may have been deposited. PSCo has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2016. PSCo had accrued $1.7 million and $1.8 million for both of these sites at Dec. 31, 2015 and 2014, 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. Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 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. PSCo estimates that the cost to comply with the new ELG rule will range from $9 million to $21 million , and could change as PSCo continues to assess alternate compliance technologies. PSCo believes that compliance costs would be recoverable through regulatory mechanisms. Federal CWA Section 316(b) — Section 316(b) of 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 August 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). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. PSCo does not anticipate the cost of compliance will have a material impact on the results of operations, financial position or cash flows. Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings. Air GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In October 2015, a final rule was published by the EPA for GHG emission standards for existing power plants. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018, or the EPA will prepare a federal plan for the state. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP is currently being challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule as well as ordered expedited review of the CPP, with briefings to be completed and oral arguments held by June 2016. Following the D.C. Circuit Court’s denial of motions for stay, multiple parties filed requests for stay with the U.S. Supreme Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until, first, the D.C. Circuit Court and then the U.S. Supreme Court have ruled on the challenges to the CPP. PSCo has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in Colorado. If state plans do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. Until PSCo has more information about SIPs or knows the requirements of the EPA’s upcoming final rule on federal plans for the states that do not develop related plans, PSCo cannot predict the costs of compliance with the final rule once it takes effect. PSCo believes compliance costs will be recoverable through regulatory mechanisms. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows. Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Colorado identified the PSCo facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities. In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for facilities included within the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at Hayden Unit 1 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million , completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms. Implementation of the National Ambient Air Quality Standard (NAAQS) for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where PSCo operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors. Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO 2 scrubber to reduce SO 2 emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA ’ s final decision is expected by summer 2016. It is anticipated that the areas near PSCo ’ s other power plants would be evaluated in the next designation phase, ending December 2017. If an area is designated nonattainment, the respective states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months , designed to achieve the NAAQS within five years . PSCo cannot evaluate the impacts of this ruling until the final designation of unclassified and nonattainment areas is made and any required state plan has been developed. Revisions to the NAAQS for Ozone — In October 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. In Colorado, the Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with the CACJA, PSCo has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in late 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014 through 2016. PSCo cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should NOx control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. 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 and common general property. The electric production obligations include asbestos, 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 ash-containment facilities such as bottom 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 an ARO for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering, extraction 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 many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks, radiation sources and office buildings. In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the final rule were incorporated into the cash flow revisions in 2015. A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2015 Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2015 (b) Electric plant Steam and other production asbestos $ 36,856 $ 1,820 $ — $ 38,676 Steam and other production ash containment 61,885 2,769 6,113 70,767 Wind production 2,095 18 (121 ) 1,992 Electric distribution 1,182 47 (99 ) 1,130 Other 1,150 46 (142 ) 1,054 Natural gas plant Gas transmission and distribution 117,474 4,694 — 122,168 Other 3,886 153 (114 ) 3,925 Common and other property Common miscellaneous 768 28 — 796 Total liability $ 225,296 $ 9,575 $ 5,637 $ 240,508 (a) In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above. (b) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015. (Thousands of Dollars) Beginning Balance Jan. 1, 2014 Liabilities Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2014 (b) Electric plant Steam and other production asbestos $ 23,914 $ 747 $ 1,597 $ 10,598 $ 36,856 Steam and other production ash containment 29,234 — 1,897 30,754 61,885 Wind production 2,953 — 22 (880 ) 2,095 Electric distribution 1,176 — 43 (37 ) 1,182 Other 1,017 — 41 92 1,150 Natural gas plant Gas transmission and distribution 788 18,252 50 98,384 117,474 Other 575 2,865 24 422 3,886 Common and other property Common miscellaneous 741 — 27 — 768 Total liability $ 60,398 $ 21,864 $ 3,701 $ 139,333 $ 225,296 (a) In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution. (b) There were no ARO liabilities settled during the year ended Dec. 31, 2014. Indeterminate AROs — PSCo has certain underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined. Additionally, 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, 2015. 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, 2015 and 2014 were $364 million and $366 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 Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In May 2015 in the remand proceeding, the FERC issued an order rejecting the City's claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City may appeal this order. Also in December 2015, the Ninth Circuit issued an order and held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC's proceedings are final. The City joined the State of California in its request seeking rehearing of this order. Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the scope of the proceeding established by FERC is being challenged in the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. 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, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | 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, 2015 and 2014 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2015 Dec. 31, 2014 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 8 Various $ 29,260 $ 497,973 $ 32,195 $ 500,889 Recoverable deferred taxes on AFUDC recorded in plant 1 Plant lives — 144,953 — 141,214 Depreciation differences 1 One to sixteen years 14,221 99,835 10,700 104,743 Net AROs (b) 1, 12 Plant lives — 62,948 — 46,213 Purchased power contract costs 12 Term of related contract 1,319 29,143 858 29,596 Property tax One to six years 21,558 14,428 28,024 31,429 Contract valuation adjustments (c) 10 Term of related contract 9,376 9,526 8,901 12,999 Losses on reacquired debt 4 Term of related debt 1,421 6,957 1,426 8,378 Conservation programs (d) 1, 11 One to five years 8,466 6,947 10,198 10,906 Gas pipeline inspection costs 12 Less than one year 3,611 — 5,416 3,611 Recoverable purchased natural gas and electric energy costs 1 Less than one year 408 — 18,410 — Other Various 2,432 33,565 3,992 13,995 Total regulatory assets $ 92,072 $ 906,275 $ 120,120 $ 903,973 (a) Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively. (b) Includes amounts recorded for future recovery of AROs. (c) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2015 and 2014 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2015 Dec. 31, 2014 Regulatory Liabilities Current Noncurrent Current Noncurrent Plant removal costs 1, 12 Plant lives $ — $ 364,291 $ — $ 366,359 Renewable resources and environmental initiatives 11, 12 Various 3,311 40,988 3,308 10,376 Investment tax credit deferrals 1, 7 Various — 20,515 — 22,225 Deferred income tax adjustment 1 Various — 16,891 — 18,672 PSCo earnings test 11 One to two years 42,868 9,472 57,127 42,819 Gas pipeline inspection costs 12 One to two years 1,140 4,273 13,970 642 Deferred electric, gas and steam production costs 1 Less than one year 66,696 — 24,035 — Conservation programs (a) 1, 11 Less than one year 33,460 — 32,226 — Low income discount program Less than one year 1,393 — 1,680 — Gain from asset sales One to three years — — 316 4 Other Various 3,955 14,991 1,797 3,324 Total regulatory liabilities (b) $ 152,823 $ 471,421 $ 134,459 $ 464,421 (a) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (b) Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities. At Dec. 31, 2015 and 2014, approximately $54 million and $104 million of PSCo’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives. |
Other Comprehensive Income
Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Year Ended Dec. 31, 2015 Year Ended Dec. 31, 2014 Accumulated other comprehensive loss at Jan. 1 $ (23,878 ) $ (23,338 ) Other comprehensive loss before reclassifications (30 ) (72 ) Losses (gains) reclassified from net accumulated other comprehensive loss 72 (468 ) Net current period other comprehensive income (loss) 42 (540 ) Accumulated other comprehensive loss at Dec. 31 $ (23,836 ) $ (23,878 ) Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2015 Year Ended Dec. 31, 2014 Losses (gains) on cash flow hedges: Interest rate derivatives $ 54 (a) $ (730 ) (a) Vehicle fuel derivatives 57 (b) (25 ) (b) Total, pre-tax 111 (755 ) Tax expense (39 ) 287 Total amounts reclassified, net of tax $ 72 $ (468 ) (a) Included in interest charges. (b) Included in O&M expenses. |
Segments and Related Informatio
Segments and Related Information | 12 Months Ended |
Dec. 31, 2015 | |
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 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 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2014 Operating revenues (a) $ 3,125,937 $ 1,215,324 $ 41,888 $ — $ 4,383,149 Intersegment revenues 339 180 — (519 ) — Total revenues $ 3,126,276 $ 1,215,504 $ 41,888 $ (519 ) $ 4,383,149 Depreciation and amortization $ 285,968 $ 89,186 $ 4,048 $ — $ 379,202 Interest charges and financing costs 124,118 29,987 535 — 154,640 Income tax expense (benefit) 208,095 50,874 (15,378 ) — 243,591 Net income 349,793 84,324 21,071 — 455,188 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2013 Operating revenues (a) $ 3,081,171 $ 1,080,703 $ 40,754 $ — $ 4,202,628 Intersegment revenues 302 110 — (412 ) — Total revenues $ 3,081,473 $ 1,080,813 $ 40,754 $ (412 ) $ 4,202,628 Depreciation and amortization $ 280,972 $ 75,510 $ 3,935 $ — $ 360,417 Interest charges and financing costs 129,787 30,604 554 — 160,945 Income tax expense (benefit) 220,356 42,294 (11,910 ) — 250,740 Net income 368,586 69,682 15,115 — 453,383 (a) Operating revenues include $13 million , $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015 , 2014 and 2013 , 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, 2015 | |
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) 2015 2014 2013 Operating revenues: Electric $ 8,632 $ 9,614 $ 8,136 Other 4,441 4,441 4,441 Operating expenses: Purchased power — 23 1,331 Other operating expenses — paid to Xcel Energy Services Inc. 414,620 454,250 375,766 Interest expense 211 158 132 Interest income 45 61 273 Accounts receivable and payable with affiliates at Dec. 31 were: 2015 2014 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 4,419 $ — $ — $ 6,706 NSP-Wisconsin 71 — 22 — SPS 414 — 5,803 — Other subsidiaries of Xcel Energy Inc. 5 76,643 45,017 40,030 $ 4,909 $ 76,643 $ 50,842 $ 46,736 |
Summarized Quarterly Financial
Summarized Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Thousands of Dollars) March 31, 2015 June 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Operating revenues $ 1,135,450 $ 952,521 $ 1,044,704 $ 1,030,838 Operating income 215,400 195,176 315,174 173,951 Net income 110,966 98,500 173,081 84,255 Quarter Ended (Thousands of Dollars) March 31, 2014 June 30, 2014 Sept. 30, 2014 Dec. 31, 2014 Operating revenues $ 1,203,543 $ 993,704 $ 1,049,111 $ 1,136,791 Operating income 208,437 163,437 261,073 169,423 Net income 118,403 89,792 154,159 92,834 |
Schedule II, Valuation and Qual
Schedule II, Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014 AND 2013 (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: 2015 $ 23,122 $ 13,052 $ 5,175 $ 21,227 $ 20,122 2014 22,505 17,005 6,240 22,628 23,122 2013 21,918 16,784 7,005 23,202 22,505 (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, 2015 | |
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 but not limited to, 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 commercial and industrial 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 that is required to be decommissioned early by a regulator is reclassified as plant to be retired. 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 , 2.7 and 2.8 percent for the years ended Dec. 31, 2015 , 2014 and 2013 , 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 income in the period that includes the enactment date. 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. 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 only applies to federal ITCs. 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. 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 or 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 net asset values. 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. See Note 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, 2015 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, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 321,004 $ 346,007 Less allowance for bad debts (20,122 ) (23,122 ) $ 300,882 $ 322,885 |
Inventories | (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 58,128 $ 55,491 Fuel 78,586 80,963 Natural gas 68,848 102,525 $ 205,562 $ 238,979 |
Property, Plant and Equipment, Net | (Thousands of Dollars) Dec. 31, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 11,856,126 $ 10,927,867 Natural gas plant 3,420,249 3,210,242 Common and other property 862,840 827,708 Plant to be retired (a) 38,249 71,534 Construction work in progress 408,963 828,620 Total property, plant and equipment 16,586,427 15,865,971 Less accumulated depreciation (4,414,216 ) (4,239,015 ) $ 12,172,211 $ 11,626,956 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financin32
Borrowings and Other Financing Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Borrowings and Other Financing Instruments [Abstract] | |
Credit Facilities | At Dec. 31, 2015 , PSCo had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 700 $ 18 $ 682 (a) This credit facility matures in October 2019. (b) Includes outstanding commercial paper and letters of credit. |
Money Pool | |
Borrowings and Other Financing Instruments [Abstract] | |
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. Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2015 Borrowing limit $ 250 Amount outstanding at period end — Average amount outstanding 4 Maximum amount outstanding 34 Weighted average interest rate, computed on a daily basis 0.36 % Weighted average interest rate at period end N/A (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Twelve Months Ended Dec. 31, 2013 Borrowing limit $ 250 $ 250 $ 250 Amount outstanding at period end — — — Average amount outstanding 1 4 — Maximum amount outstanding 34 97 12 Weighted average interest rate, computed on a daily basis 0.41 % 0.25 % 0.36 % 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 — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2014 Borrowing limit $ 700 Amount outstanding at period end 14 Average amount outstanding 14 Maximum amount outstanding 68 Weighted average interest rate, computed on a daily basis 0.50 % Weighted average interest rate at period end 0.60 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Twelve Months Ended Dec. 31, 2013 Borrowing limit $ 700 $ 700 $ 700 Amount outstanding at period end 14 382 — Average amount outstanding 95 167 38 Maximum amount outstanding 449 393 332 Weighted average interest rate, computed on a daily basis 0.51 % 0.31 % 0.34 % Weighted average interest rate at period end 0.60 0.65 N/A |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 | |
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, 2015 : (Thousands of Dollars) Plant in Service Accumulated CWIP Ownership % Electric Generation: Hayden Unit 1 $ 155,159 $ 69,679 $ 147 76 % Hayden Unit 2 121,486 61,780 20,840 37 Hayden Common Facilities 37,756 17,910 321 53 Craig Units 1 and 2 60,158 36,570 8,518 10 Craig Common Facilities 1, 2 and 3 37,418 18,520 505 7 Comanche Unit 3 892,340 95,029 452 67 Comanche Common Facilities 23,826 1,430 894 82 Electric Transmission: Transmission and other facilities, including substations 152,460 62,324 5,378 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 19,928 7,165 — 60 Gas Transportation Compressor $ 8,353 $ 124 $ 127 50 Total $ 1,508,884 $ 370,531 $ 37,182 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 2.4 $ 1.9 Unrecognized tax benefit — Temporary tax positions 15.0 10.0 Total unrecognized tax benefit $ 17.4 $ 11.9 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2015 2014 2013 Balance at Jan. 1 $ 11.9 $ 8.4 $ 9.6 Additions based on tax positions related to the current year 4.5 3.7 3.9 Reductions based on tax positions related to the current year (1.5 ) (0.7 ) — Additions for tax positions of prior years 2.5 2.8 3.3 Reductions for tax positions of prior years — (1.2 ) (0.9 ) Settlements with taxing authorities — (1.1 ) (7.5 ) Balance at Dec. 31 $ 17.4 $ 11.9 $ 8.4 |
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, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (4.3 ) $ (3.9 ) |
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) 2015 2014 Federal NOL carryforward $ 328 $ 320 Federal tax credit carryforwards 24 22 State NOL carryforwards 684 690 State tax credit carryforwards, net of federal detriment (a) 13 12 Valuation allowances for state credit carryforwards, net of federal detriment (b) (1 ) — (a) State tax credit carryforwards are net of federal detriment of $7 million and $7 million as of Dec. 31, 2015 and 2014, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million as of Dec. 31, 2015. |
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: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 3.2 2.8 3.0 Change in unrecognized tax benefits 0.1 (0.1 ) 0.1 Regulatory differences — utility plant items (0.3 ) (2.1 ) (1.4 ) Tax credits recognized, net of federal income tax expense (0.7 ) (0.8 ) (0.8 ) Other, net 0.1 0.1 (0.3 ) Effective income tax rate 37.4 % 34.9 % 35.6 % |
Schedule of Components of Income Tax Expense (Benefit) | The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2015 2014 2013 Current federal tax (benefit) expense $ (1,166 ) $ 9,550 $ (52,408 ) Current state tax (benefit) expense (727 ) 2,611 (7,252 ) Current change in unrecognized tax expense (benefit) 5,244 6,548 (2,918 ) Deferred federal tax expense 246,096 208,781 273,916 Deferred state tax expense 36,450 26,196 38,243 Deferred change in unrecognized tax (benefit) expense (4,650 ) (7,154 ) 4,094 Deferred investment tax credits (2,807 ) (2,941 ) (2,935 ) Total income tax expense $ 278,440 $ 243,591 $ 250,740 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2015 2014 2013 Deferred tax expense excluding items below $ 285,144 $ 254,142 $ 335,580 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (7,229 ) (26,649 ) (19,616 ) Tax benefit allocated to other comprehensive income and other (19 ) 330 289 Deferred tax expense $ 277,896 $ 227,823 $ 316,253 |
Schedule of Deferred Tax Assets and Liabilities | The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows: (Thousands of Dollars) 2015 2014 Deferred tax liabilities: Differences between book and tax bases of property $ 2,772,043 $ 2,467,260 Employee benefits 105,049 110,556 Other 101,219 140,080 Total deferred tax liabilities $ 2,978,311 $ 2,717,896 Deferred tax assets: NOL carryforward $ 147,763 $ 143,158 Unbilled revenue - fuel costs 48,181 57,654 Rate refund 23,352 43,735 Tax credit carryforward 35,240 34,493 Regulatory liabilities 17,201 14,549 Deferred investment tax credits 12,718 13,781 Other 35,658 37,472 Total deferred tax assets $ 320,113 $ 344,842 Net deferred tax liability $ 2,658,198 $ 2,373,054 |
Benefit Plans and Other Postr36
Benefit Plans and Other Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 2016 $ 77,898 $ 32,197 $ 2,234 $ 29,963 2017 77,952 32,356 2,373 29,983 2018 80,583 32,381 2,517 29,864 2019 82,760 32,402 2,647 29,755 2020 83,372 33,093 2,753 30,340 2021-2025 430,762 158,040 15,450 142,590 |
Pension Plans | |
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, 2015 and 2014 : Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 81,954 $ — $ — $ 81,954 Derivatives — 1,204 — 1,204 Government securities — 214,341 — 214,341 Corporate bonds — 86,914 — 86,914 Asset-backed securities — 881 — 881 Common stock 28,797 — — 28,797 Private equity investments — — 34,353 34,353 Commingled funds — 573,009 — 573,009 Real estate — — 18,681 18,681 Other — (3,453 ) — (3,453 ) Total $ 110,751 $ 872,896 $ 53,034 $ 1,036,681 Dec. 31, 2014 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 82,486 $ — $ — $ 82,486 Derivatives — 508 — 508 Government securities — 180,912 — 180,912 Corporate bonds — 115,593 — 115,593 Asset-backed securities — 1,360 — 1,360 Mortgage-backed securities — 3,997 — 3,997 Common stock 37,067 — — 37,067 Private equity investments — — 50,210 50,210 Commingled funds — 629,439 — 629,439 Real estate — — 18,410 18,410 Securities lending collateral obligation and other — (16,117 ) — (16,117 ) Total $ 119,553 $ 915,692 $ 68,620 $ 1,103,865 The following table presents the target pension asset allocations for PSCo at Dec. 31 for the upcoming year: 2015 2014 Domestic and international equity securities 36 % 32 % Long-duration fixed income and interest rate swap securities 32 35 Short-to-intermediate fixed income securities 12 12 Alternative investments 18 18 Cash 2 3 Total 100 % 100 % |
Changes in Level 3 Plan Assets | The following tables present the changes in PSCo’s Level 3 pension plan assets for the years ended Dec. 31, 2015 , 2014 and 2013 : (Thousands of Dollars) Jan. 1, 2015 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 Dec. 31, 2015 Private equity investments $ 50,210 $ 7,636 $ (20,036 ) $ (3,457 ) $ — $ 34,353 Real estate 18,410 1,925 (2,371 ) 717 — 18,681 Total $ 68,620 $ 9,561 $ (22,407 ) $ (2,740 ) $ — $ 53,034 (Thousands of Dollars) Jan. 1, 2014 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 Dec. 31, 2014 Private equity investments $ 49,022 $ 8,495 $ (4,299 ) $ (3,008 ) $ — $ 50,210 Real estate 15,556 1,180 (302 ) 1,976 — 18,410 Total $ 64,578 $ 9,675 $ (4,601 ) $ (1,032 ) $ — $ 68,620 (Thousands of Dollars) Jan. 1, 2013 Net Realized Gains (Losses) Net Unrealized Gains (Losses) Purchases, Transfers Out of Level 3 (a) Dec. 31, 2013 Asset-backed securities $ 4,604 $ — $ — $ — $ (4,604 ) $ — Mortgage-backed securities 12,058 — — — (12,058 ) — Private equity investments 47,056 7,074 (4,027 ) (1,081 ) — 49,022 Real estate 19,273 (870 ) 3,769 3,048 (9,664 ) 15,556 Total $ 82,991 $ 6,204 $ (258 ) $ 1,967 $ (26,326 ) $ 64,578 (a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
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) 2015 2014 Accumulated Benefit Obligation at Dec. 31 $ 1,192,798 $ 1,249,739 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 1,277,957 $ 1,152,836 Service cost 28,260 23,939 Interest cost 50,857 53,277 Transfer to other plan (2,938 ) (13,404 ) Actuarial (gain) loss (54,737 ) 133,215 Benefit payments (74,749 ) (71,906 ) Obligation at Dec. 31 $ 1,224,650 $ 1,277,957 |
Change in Fair Value of Plan Assets | (Thousands of Dollars) 2015 2014 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 1,103,865 $ 1,067,057 Actual (loss) return on plan assets (9,122 ) 84,871 Employer contributions 20,056 35,156 Transfer to other plan (3,369 ) (11,313 ) Benefit payments (74,749 ) (71,906 ) Fair value of plan assets at Dec. 31 $ 1,036,681 $ 1,103,865 |
Funded Status of Plans | (Thousands of Dollars) 2015 2014 Funded Status of Plans at Dec. 31: Funded status (a) $ (187,969 ) $ (174,092 ) (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) 2015 2014 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 521,703 $ 530,674 Prior service credit (15,572 ) (18,708 ) Total $ 506,131 $ 511,966 |
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) 2015 2014 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 $ 28,852 $ 31,774 Noncurrent regulatory assets 477,279 480,192 Total $ 506,131 $ 511,966 |
Schedule of Assumptions Used | Measurement date Dec. 31, 2015 Dec. 31, 2014 2015 2014 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.66 % 4.11 % Expected average long-term increase in compensation level 4.00 3.75 Mortality table RP 2014 RP 2014 2015 2014 2013 Significant Assumptions Used to Measure Costs: Discount rate 4.11 % 4.75 % 4.00 % Expected average long-term increase in compensation level 3.75 3.75 3.75 Expected average long-term rate of return on assets 6.81 6.81 6.47 |
Components of Net Periodic Benefit Costs | Benefit Costs — The components of PSCo’s net periodic pension cost were: (Thousands of Dollars) 2015 2014 2013 Service cost $ 28,260 $ 23,939 $ 25,206 Interest cost 50,857 53,277 46,160 Expected return on plan assets (72,590 ) (70,709 ) (63,821 ) Amortization of prior service credit (3,136 ) (3,092 ) (1,064 ) Amortization of net loss 36,377 33,892 43,418 Net periodic pension cost 39,768 37,307 49,899 Costs not recognized due to effects of regulation (1,464 ) — — Net benefit cost recognized for financial reporting $ 38,304 $ 37,307 $ 49,899 |
Postretirement Benefit Plan | |
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, 2015 and 2014 : Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents $ 17,524 $ — $ — $ 17,524 Government securities — 35,016 — 35,016 Insurance contracts — 42,123 — 42,123 Corporate bonds — 65,031 — 65,031 Asset-backed securities — 25,602 — 25,602 Mortgage-backed securities — 31,778 — 31,778 Commingled funds — 182,736 — 182,736 Other — (368 ) — (368 ) Total $ 17,524 $ 381,918 $ — $ 399,442 Dec. 31, 2014 (Thousands of Dollars) Level 1 Level 2 Level 3 Total Cash equivalents (a) $ 23,566 $ — $ — $ 23,566 Derivatives — 166 — 166 Government securities — 43,494 — 43,494 Insurance contracts — 45,075 — 45,075 Corporate bonds — 48,527 — 48,527 Asset-backed securities — 3,240 — 3,240 Mortgage-backed securities — 10,071 — 10,071 Commingled funds — 252,790 — 252,790 Other — (1,647 ) — (1,647 ) Total $ 23,566 $ 401,716 $ — $ 425,282 (a) Includes restricted cash of $0.9 million at Dec. 31, 2014. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and PSCo at Dec. 31 for the upcoming year: 2015 2014 Domestic and international equity securities 25 % 25 % Short-to-intermediate fixed income securities 57 57 Alternative investments 13 13 Cash 5 5 Total 100 % 100 % |
Changes in Level 3 Plan Assets | For the years ended Dec. 31, 2015 and 2014, there were no assets transferred in or out of Level 3. The following table presents the changes in PSCo’s Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2013 : (Thousands of Dollars) Jan. 1, 2013 Net Realized Net Unrealized Purchases, Transfers Out of Level 3 (a) Dec. 31, 2013 Asset-backed securities $ 670 $ — $ — $ — $ (670 ) $ — Mortgage-backed securities 35,394 — — — (35,394 ) — Total $ 36,064 $ — $ — $ — $ (36,064 ) $ — (a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
Change in Projected Benefit Obligation | Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for PSCo is presented in the following table: (Thousands of Dollars) 2015 2014 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 443,753 $ 508,971 Service cost 928 1,915 Interest cost 17,498 23,704 Medicare subsidy reimbursements 1,712 1,753 Plan participants’ contributions 4,961 4,625 Actuarial gain (32,001 ) (63,130 ) Benefit payments (33,277 ) (34,085 ) Obligation at Dec. 31 $ 403,574 $ 443,753 |
Change in Fair Value of Plan Assets | (Thousands of Dollars) 2015 2014 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 425,282 $ 438,193 Actual (loss) return on plan assets (3,076 ) 11,060 Plan participants’ contributions 4,961 4,625 Employer contributions 5,552 5,489 Benefit payments (33,277 ) (34,085 ) Fair value of plan assets at Dec. 31 $ 399,442 $ 425,282 |
Funded Status of Plans | (Thousands of Dollars) 2015 2014 Funded Status at Dec. 31: Funded status (a) $ (4,132 ) $ (18,471 ) (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) 2015 2014 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 49,226 $ 56,823 Prior service credit (33,942 ) (40,189 ) Total $ 15,284 $ 16,634 |
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) 2015 2014 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 $ 15,284 $ 16,634 |
Schedule of Assumptions Used | Measurement date Dec. 31, 2015 Dec. 31, 2014 2015 2014 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.65 % 4.08 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial 6.00 % 6.50 % 2015 2014 2013 Significant Assumptions Used to Measure Costs: Discount rate 4.08 % 4.82 % 4.10 % Expected average long-term rate of return on assets 5.80 7.18 7.11 |
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 $ 38,946 $ (33,136 ) Service and interest components 2,093 (1,743 ) |
Components of Net Periodic Benefit Costs | Benefit Costs — The components of PSCo’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2015 2014 2013 Service cost $ 928 $ 1,915 $ 2,564 Interest cost 17,498 23,704 22,210 Expected return on plan assets (23,803 ) (30,214 ) (29,227 ) Amortization of transition obligation — — 785 Amortization of prior service credit (6,247 ) (6,247 ) (7,666 ) Amortization of net loss 2,475 6,434 13,699 Net periodic postretirement benefit (credit) cost $ (9,149 ) $ (4,408 ) $ 2,365 |
Fair Value of Financial Asset37
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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) 2015 2014 MWh of electricity 684 — MMBtu of natural gas 12,515 735 Gallons of vehicle fuel 63 127 (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) 2015 2014 2013 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (23,878 ) $ (23,338 ) $ (22,871 ) After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (30 ) (72 ) 9 After-tax net realized losses (gains) on derivative transactions reclassified into earnings 72 (468 ) (476 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (23,836 ) $ (23,878 ) $ (23,338 ) |
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, 2015, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2015 Pre-Tax Fair Value Losses Recognized During the Period in: Pre-Tax Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Gains (Losses) Recognized in Income 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 (e) (7,620 ) (e) Total $ — $ (10,635 ) $ — $ 10,158 $ (7,256 ) Year Ended Dec. 31, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax Gains Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (730 ) (a) $ — $ — Vehicle fuel and other commodity (115 ) — (25 ) (b) — — Total $ (115 ) $ — $ (755 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ 451 $ — $ (4,631 ) (e) $ (9,850 ) (e) Total $ — $ 451 $ — $ (4,631 ) $ (9,850 ) Year Ended Dec. 31, 2013 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Loss Regulatory Liabilities Accumulated Loss Regulatory (Liabilities) Pre-Tax Losses in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (730 ) (a) $ — $ — Vehicle fuel and other commodity 14 — (40 ) (b) — — Total $ 14 $ — $ (770 ) $ — $ — Other derivative instruments Natural gas commodity — (4,001 ) — 4,340 (e) (5,850 ) (d) Total $ — $ (4,001 ) $ — $ 4,340 $ (5,850 ) (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) Amounts are recorded to electric fuel and purchased power. (e) Amounts for the year ended Dec. 31, 2015 included $1.1 million 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. Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2015, 2014 and 2013 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, 2015: Dec. 31, 2015 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 $ 137 $ 351 $ — $ 488 $ (324 ) $ 164 Natural gas commodity — 352 — 352 (286 ) 66 Total current derivative assets $ 137 $ 703 $ — $ 840 $ (610 ) 230 PPAs (a) 1,715 Current derivative instruments $ 1,945 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 16 $ — $ 16 $ — $ 16 Total noncurrent derivative assets $ — $ 16 $ — $ 16 $ — 16 PPAs (a) 3,462 Noncurrent derivative instruments $ 3,478 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 92 $ — $ 92 $ — $ 92 Other derivative instruments: Commodity trading 34 325 — 359 (324 ) 35 Natural gas commodity — 3,850 — 3,850 (286 ) 3,564 Total current derivative liabilities $ 34 $ 4,267 $ — $ 4,301 $ (610 ) 3,691 PPAs (a) 5,190 Current derivative instruments $ 8,881 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 33 $ — $ 33 $ — $ 33 Total noncurrent derivative liabilities $ — $ 33 $ — $ 33 $ — 33 PPAs (a) 12,987 Noncurrent derivative instruments $ 13,020 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral 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. 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, 2014: Dec. 31, 2014 Fair Value (Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting (b) Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 33 $ — $ 33 $ (18 ) $ 15 Total current derivative assets $ — $ 33 $ — $ 33 $ (18 ) 15 PPAs (a) 1,716 Current derivative instruments $ 1,731 Noncurrent derivative assets PPAs (a) 5,176 Noncurrent derivative instruments $ 5,176 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 53 $ — $ 53 $ — $ 53 Other derivative instruments: Natural gas commodity — 548 — 548 (18 ) 530 Total current derivative liabilities $ — $ 601 $ — $ 601 $ (18 ) 583 PPAs (a) 5,191 Current derivative instruments $ 5,774 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 46 $ — $ 46 $ — $ 46 Other derivative instruments: Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 81 $ — $ 81 $ — 81 PPAs (a) 18,176 Noncurrent derivative instruments $ 18,257 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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, 2014. At Dec. 31, 2014, 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, 2015 and 2014, other financial instruments for which the carrying amount did not equal fair value were as follows: 2015 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,132,191 $ 4,376,875 $ 3,890,229 $ 4,328,968 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2015 2014 2013 Interest income $ 753 $ 1,470 $ 1,761 Other nonoperating income 2,408 3,601 2,603 Insurance policy expense (197 ) (806 ) (1,228 ) Other income, net $ 2,964 $ 4,265 $ 3,136 |
Rate Matters (Tables)
Rate Matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Colorado 2015 Multi-Year Gas Rate Case - Rebuttal Testimony | In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate increase $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 Requested ROE 10.1 % 10.1 % 10.3 % Rate base $ 1,260 $ 1,310 $ 1,360 |
Colorado 2015 Multi-Year Gas Rate Case - Base Rate ALJ Recommendation and CPUC Deliberations | The following table reflects the ALJ’s position and the CPUC’s written order (estimated): (Millions of Dollars) ALJ CPUC ’ s Written Order PSCo’s filed 2015 base rate request (a) $ 40.5 $ 40.5 ROE (7.8 ) (7.8 ) Capital structure and cost of debt (0.5 ) (0.5 ) Cherokee pipeline adjustment 4.1 4.1 Move to 2014 HTY (14.1 ) (14.1 ) O&M expenses (3.0 ) (2.4 ) Other, net (1.1 ) (1.1 ) Overall recommended rate increase $ 18.1 $ 18.7 (a) The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016. |
Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider ALJ Recommendation and CPUC Deliberations | The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated): ALJ CPUC ’ s Written Order (Millions of Dollars) 2016 2017 2016 2017 PSCo’s filed incremental PSIA request $ 21.7 $ 21.2 $ 21.7 $ 21.2 Transfer PSIA costs to base rates (20.5 ) — (20.5 ) — PSIA cost recovery remaining in base (4.3 ) — (4.3 ) — Projects not recovered through the PSIA (3.6 ) (2.0 ) (3.3 ) (0.8 ) ROE and capital structure (0.3 ) (1.6 ) (0.3 ) (1.6 ) Total $ (7.0 ) $ 17.6 $ (6.7 ) $ 18.8 |
Colorado 2015 Multi-Year Gas Rate Case - Impact of CPUC Written Order | The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order: (Millions of Dollars) 2015 2016 2017 Base rate increase $ 18.7 $ 19.7 $ — Incremental PSIA rider revenues (0.2 ) (6.7 ) 18.8 Expense deferrals, net amortization (a) (3.6 ) 1.5 5.2 Estimated pre-tax impact $ 14.9 $ 14.5 $ 24.0 (a) Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Estimated Minimum Purchases Under Fuel Contracts | The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2015 , are as follows: (Millions of Dollars) Coal Natural gas supply Natural gas 2016 $ 302.3 $ 231.1 $ 137.5 2017 230.3 129.5 137.2 2018 118.5 181.0 85.5 2019 42.0 187.6 51.0 2020 43.6 203.4 50.4 Thereafter 332.3 409.6 773.2 Total $ 1,069.0 $ 1,342.2 $ 1,234.8 |
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements | At Dec. 31, 2015 , the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity Energy (a) 2016 $ 44.5 $ 25.3 2017 24.3 4.4 2018 19.2 — 2019 10.3 — 2020 1.5 — Thereafter 9.5 — Total $ 109.3 $ 29.7 (a) Excludes contingent energy payments for renewable energy PPAs. |
Summary of Property Held Under Capital Leases | Total amortization expenses under capital lease assets were approximately $8.2 million , $7.2 million , and $6.3 million for 2015 , 2014 and 2013 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2015 Dec. 31, 2014 Gas storage facilities $ 200.5 $ 200.5 Gas pipeline 20.7 20.7 Property held under capital leases 221.2 221.2 Accumulated depreciation (57.2 ) (49.0 ) Total property held under capital leases, net $ 164.0 $ 172.2 |
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 2016 $ 12.0 $ 102.2 $ 114.2 $ 29.3 2017 7.8 95.8 103.6 25.7 2018 7.4 96.0 103.4 25.3 2019 7.4 96.9 104.3 25.1 2020 7.4 97.7 105.1 24.9 Thereafter 39.5 579.7 619.2 486.5 Total minimum obligation 616.8 Interest component of obligation (452.8 ) Present value of minimum obligation $ 164.0 (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2032 . |
Asset Retirement Obligations | A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2015 Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2015 (b) Electric plant Steam and other production asbestos $ 36,856 $ 1,820 $ — $ 38,676 Steam and other production ash containment 61,885 2,769 6,113 70,767 Wind production 2,095 18 (121 ) 1,992 Electric distribution 1,182 47 (99 ) 1,130 Other 1,150 46 (142 ) 1,054 Natural gas plant Gas transmission and distribution 117,474 4,694 — 122,168 Other 3,886 153 (114 ) 3,925 Common and other property Common miscellaneous 768 28 — 796 Total liability $ 225,296 $ 9,575 $ 5,637 $ 240,508 (a) In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above. (b) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015. (Thousands of Dollars) Beginning Balance Jan. 1, 2014 Liabilities Accretion Cash Flow Revisions (a) Ending Balance Dec. 31, 2014 (b) Electric plant Steam and other production asbestos $ 23,914 $ 747 $ 1,597 $ 10,598 $ 36,856 Steam and other production ash containment 29,234 — 1,897 30,754 61,885 Wind production 2,953 — 22 (880 ) 2,095 Electric distribution 1,176 — 43 (37 ) 1,182 Other 1,017 — 41 92 1,150 Natural gas plant Gas transmission and distribution 788 18,252 50 98,384 117,474 Other 575 2,865 24 422 3,886 Common and other property Common miscellaneous 741 — 27 — 768 Total liability $ 60,398 $ 21,864 $ 3,701 $ 139,333 $ 225,296 |
Regulatory Assets and Liabili41
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets | The components of regulatory assets shown on the consolidated balance sheets of PSCo at Dec. 31, 2015 and 2014 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2015 Dec. 31, 2014 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 8 Various $ 29,260 $ 497,973 $ 32,195 $ 500,889 Recoverable deferred taxes on AFUDC recorded in plant 1 Plant lives — 144,953 — 141,214 Depreciation differences 1 One to sixteen years 14,221 99,835 10,700 104,743 Net AROs (b) 1, 12 Plant lives — 62,948 — 46,213 Purchased power contract costs 12 Term of related contract 1,319 29,143 858 29,596 Property tax One to six years 21,558 14,428 28,024 31,429 Contract valuation adjustments (c) 10 Term of related contract 9,376 9,526 8,901 12,999 Losses on reacquired debt 4 Term of related debt 1,421 6,957 1,426 8,378 Conservation programs (d) 1, 11 One to five years 8,466 6,947 10,198 10,906 Gas pipeline inspection costs 12 Less than one year 3,611 — 5,416 3,611 Recoverable purchased natural gas and electric energy costs 1 Less than one year 408 — 18,410 — Other Various 2,432 33,565 3,992 13,995 Total regulatory assets $ 92,072 $ 906,275 $ 120,120 $ 903,973 (a) Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively. (b) Includes amounts recorded for future recovery of AROs. (c) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Regulatory Liabilities | The components of regulatory liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2015 and 2014 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2015 Dec. 31, 2014 Regulatory Liabilities Current Noncurrent Current Noncurrent Plant removal costs 1, 12 Plant lives $ — $ 364,291 $ — $ 366,359 Renewable resources and environmental initiatives 11, 12 Various 3,311 40,988 3,308 10,376 Investment tax credit deferrals 1, 7 Various — 20,515 — 22,225 Deferred income tax adjustment 1 Various — 16,891 — 18,672 PSCo earnings test 11 One to two years 42,868 9,472 57,127 42,819 Gas pipeline inspection costs 12 One to two years 1,140 4,273 13,970 642 Deferred electric, gas and steam production costs 1 Less than one year 66,696 — 24,035 — Conservation programs (a) 1, 11 Less than one year 33,460 — 32,226 — Low income discount program Less than one year 1,393 — 1,680 — Gain from asset sales One to three years — — 316 4 Other Various 3,955 14,991 1,797 3,324 Total regulatory liabilities (b) $ 152,823 $ 471,421 $ 134,459 $ 464,421 (a) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (b) Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Year Ended Dec. 31, 2015 Year Ended Dec. 31, 2014 Accumulated other comprehensive loss at Jan. 1 $ (23,878 ) $ (23,338 ) Other comprehensive loss before reclassifications (30 ) (72 ) Losses (gains) reclassified from net accumulated other comprehensive loss 72 (468 ) Net current period other comprehensive income (loss) 42 (540 ) Accumulated other comprehensive loss at Dec. 31 $ (23,836 ) $ (23,878 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2015 Year Ended Dec. 31, 2014 Losses (gains) on cash flow hedges: Interest rate derivatives $ 54 (a) $ (730 ) (a) Vehicle fuel derivatives 57 (b) (25 ) (b) Total, pre-tax 111 (755 ) Tax expense (39 ) 287 Total amounts reclassified, net of tax $ 72 $ (468 ) (a) Included in interest charges. (b) Included in O&M expenses. |
Segments and Related Informat43
Segments and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Thousands of Dollars) Regulated Regulated All Other Reconciling Consolidated 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 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2014 Operating revenues (a) $ 3,125,937 $ 1,215,324 $ 41,888 $ — $ 4,383,149 Intersegment revenues 339 180 — (519 ) — Total revenues $ 3,126,276 $ 1,215,504 $ 41,888 $ (519 ) $ 4,383,149 Depreciation and amortization $ 285,968 $ 89,186 $ 4,048 $ — $ 379,202 Interest charges and financing costs 124,118 29,987 535 — 154,640 Income tax expense (benefit) 208,095 50,874 (15,378 ) — 243,591 Net income 349,793 84,324 21,071 — 455,188 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2013 Operating revenues (a) $ 3,081,171 $ 1,080,703 $ 40,754 $ — $ 4,202,628 Intersegment revenues 302 110 — (412 ) — Total revenues $ 3,081,473 $ 1,080,813 $ 40,754 $ (412 ) $ 4,202,628 Depreciation and amortization $ 280,972 $ 75,510 $ 3,935 $ — $ 360,417 Interest charges and financing costs 129,787 30,604 554 — 160,945 Income tax expense (benefit) 220,356 42,294 (11,910 ) — 250,740 Net income 368,586 69,682 15,115 — 453,383 (a) Operating revenues include $13 million , $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015 , 2014 and 2013 , 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, 2015 | |
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) 2015 2014 2013 Operating revenues: Electric $ 8,632 $ 9,614 $ 8,136 Other 4,441 4,441 4,441 Operating expenses: Purchased power — 23 1,331 Other operating expenses — paid to Xcel Energy Services Inc. 414,620 454,250 375,766 Interest expense 211 158 132 Interest income 45 61 273 Accounts receivable and payable with affiliates at Dec. 31 were: 2015 2014 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 4,419 $ — $ — $ 6,706 NSP-Wisconsin 71 — 22 — SPS 414 — 5,803 — Other subsidiaries of Xcel Energy Inc. 5 76,643 45,017 40,030 $ 4,909 $ 76,643 $ 50,842 $ 46,736 |
Summarized Quarterly Financia45
Summarized Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Quarter Ended (Thousands of Dollars) March 31, 2015 June 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Operating revenues $ 1,135,450 $ 952,521 $ 1,044,704 $ 1,030,838 Operating income 215,400 195,176 315,174 173,951 Net income 110,966 98,500 173,081 84,255 Quarter Ended (Thousands of Dollars) March 31, 2014 June 30, 2014 Sept. 30, 2014 Dec. 31, 2014 Operating revenues $ 1,203,543 $ 993,704 $ 1,049,111 $ 1,136,791 Operating income 208,437 163,437 261,073 169,423 Net income 118,403 89,792 154,159 92,834 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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% | 2.70% | 2.80% |
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 |
Selected Balance Sheet Data (De
Selected Balance Sheet Data (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts receivable, net | ||
Accounts receivable | $ 321,004 | $ 346,007 |
Less allowance for bad debts | (20,122) | (23,122) |
Accounts receivable, net | $ 300,882 | $ 322,885 |
Selected Balance Sheet Data Bal
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 205,562 | $ 238,979 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 58,128 | 55,491 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 78,586 | 80,963 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 68,848 | $ 102,525 |
Selected Balance Sheet Data B49
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 16,586,427 | $ 15,865,971 | |
Less accumulated depreciation | (4,414,216) | (4,239,015) | |
Property, plant and equipment, net | 12,172,211 | 11,626,956 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 11,856,126 | 10,927,867 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 3,420,249 | 3,210,242 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 862,840 | 827,708 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 38,249 | 71,534 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 408,963 | $ 828,620 | |
[1] | PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Borrowings and Other Financin50
Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Short-term Debt [Line Items] | ||||
Amount outstanding at period end | $ 14,000 | $ 14,000 | $ 382,000 | |
Money Pool | ||||
Short-term Debt [Line Items] | ||||
Borrowing limit | 250,000 | 250,000 | 250,000 | $ 250,000 |
Amount outstanding at period end | 0 | 0 | 0 | 0 |
Average amount outstanding | 4,000 | 1,000 | 4,000 | 0 |
Maximum amount outstanding | $ 34,000 | $ 34,000 | $ 97,000 | $ 12,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.36% | 0.41% | 0.25% | 0.36% |
Commercial Paper | ||||
Short-term Debt [Line Items] | ||||
Borrowing limit | $ 700,000 | $ 700,000 | $ 700,000 | $ 700,000 |
Amount outstanding at period end | 14,000 | 14,000 | 382,000 | 0 |
Average amount outstanding | 14,000 | 95,000 | 167,000 | 38,000 |
Maximum amount outstanding | $ 68,000 | $ 449,000 | $ 393,000 | $ 332,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.50% | 0.51% | 0.31% | 0.34% |
Weighted average interest rate at period end (percentage) | 0.60% | 0.60% | 0.65% |
Borrowings and Other Financin51
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 14,000 | $ 382,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 4,000 | $ 6,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin52
Borrowings and Other Financing Instruments, Credit Facility (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Line of Credit Facility [Line Items] | |||
Line Of Credit Facility Debt To Total Capitalization Ratio | 45.00% | 47.00% | |
Direct advances on the credit facility outstanding | $ 0 | ||
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 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 | ||
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 | ||
Credit Facility | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Term | 5 years | ||
Credit Facility | $ 700,000,000 | ||
Drawn | [1] | 18,000,000 | |
Available | 682,000,000 | ||
Direct advances on the credit facility outstanding | $ 0 | ||
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.075% | ||
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit | 0.275% | ||
Eurodollar [Member] | Credit Facility | |||
Line of Credit Facility [Line Items] | |||
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings | 0.875% | ||
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings | 1.75% | ||
[1] | Includes outstanding commercial paper and letters of credit. |
Borrowings and Other Financin53
Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Long-Term Borrowings [Line Items] | |||
Long-term Line of Credit | $ 0 | ||
Deferred Finance Costs, Noncurrent, Net | $ 26,600,000 | 26,500,000 | |
First Mortgage Bonds | Series Due May 15, 2025 [Member] | |||
Long-Term Borrowings [Line Items] | |||
Interest rate, stated percentage (in hundredths) | 2.90% | ||
Maturity date | May 15, 2025 | ||
Long-term Debt, Gross | $ 250,000,000 | 0 | |
First Mortgage Bonds | Series Due March 15, 2044 | |||
Long-Term Borrowings [Line Items] | |||
Face amount | $ 300,000,000 | ||
Interest rate, stated percentage (in hundredths) | 4.30% | 4.30% | |
Maturity date | Mar. 15, 2044 | Mar. 15, 2044 | |
Long-term Debt, Gross | $ 300,000,000 | $ 300,000,000 | |
First Mortgage Bonds | Series Due Sept. 1, 2017 | |||
Long-Term Borrowings [Line Items] | |||
Interest rate, stated percentage (in hundredths) | 4.375% | 4.375% | |
Maturity date | Sep. 1, 2017 | Sep. 1, 2017 | |
Long-term Debt, Gross | [1] | $ 129,500,000 | $ 129,500,000 |
First Mortgage Bonds | Series Due Aug. 1, 2018 | |||
Long-Term Borrowings [Line Items] | |||
Interest rate, stated percentage (in hundredths) | 5.80% | 5.80% | |
Maturity date | Aug. 1, 2018 | Aug. 1, 2018 | |
Long-term Debt, Gross | $ 300,000,000 | $ 300,000,000 | |
First Mortgage Bonds | Series Due June 1, 2019 | |||
Long-Term Borrowings [Line Items] | |||
Interest rate, stated percentage (in hundredths) | 5.125% | 5.125% | |
Maturity date | Jun. 1, 2019 | Jun. 1, 2019 | |
Long-term Debt, Gross | $ 400,000,000 | $ 400,000,000 | |
First Mortgage Bonds | Series Due Nov. 15, 2020 | |||
Long-Term Borrowings [Line Items] | |||
Interest rate, stated percentage (in hundredths) | 3.20% | 3.20% | |
Maturity date | Nov. 15, 2020 | Nov. 15, 2020 | |
Long-term Debt, Gross | $ 400,000,000 | $ 400,000,000 | |
PSCo [Member] | First Mortgage Bonds | Series Due May 15, 2025 [Member] | |||
Long-Term Borrowings [Line Items] | |||
Face amount | $ 250,000,000 | ||
Interest rate, stated percentage (in hundredths) | 2.90% | ||
[1] | Pollution control financing. |
Preferred Stock (Details)
Preferred Stock (Details) | Dec. 31, 2015$ / 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 Generation55
Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)MW | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 1,508,884 |
Accumulated depreciation | 370,531 |
Construction work in progress | $ 37,182 |
Generating capacity (in MW) | MW | 820 |
Electric Generation | Hayden Unit 1 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 155,159 |
Accumulated depreciation | 69,679 |
Construction work in progress | $ 147 |
Ownership percentage (in hundredths) | 76.00% |
Electric Generation | Hayden Unit 2 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 121,486 |
Accumulated depreciation | 61,780 |
Construction work in progress | $ 20,840 |
Ownership percentage (in hundredths) | 37.00% |
Electric Generation | Hayden Common Facilities | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 37,756 |
Accumulated depreciation | 17,910 |
Construction work in progress | $ 321 |
Ownership percentage (in hundredths) | 53.00% |
Electric Generation | Craig Units 1 and 2 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 60,158 |
Accumulated depreciation | 36,570 |
Construction work in progress | $ 8,518 |
Ownership percentage (in hundredths) | 10.00% |
Electric Generation | Craig Common Facilities 1, 2 and 3 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 37,418 |
Accumulated depreciation | 18,520 |
Construction work in progress | $ 505 |
Ownership percentage (in hundredths) | 7.00% |
Electric Generation | Comanche Unit 3 | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 892,340 |
Accumulated depreciation | 95,029 |
Construction work in progress | $ 452 |
Ownership percentage (in hundredths) | 67.00% |
Electric Generation | Comanche Common Facilities | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 23,826 |
Accumulated depreciation | 1,430 |
Construction work in progress | $ 894 |
Ownership percentage (in hundredths) | 82.00% |
Electric Transmission | Transmission and other facilities, including substations | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 152,460 |
Accumulated depreciation | 62,324 |
Construction work in progress | $ 5,378 |
Ownership percentage of group of jointly owned facilities | Various |
Gas Transportation | Rifle to Avon | |
Jointly Owned Utility Plant [Abstract] | |
Plant in service | $ 19,928 |
Accumulated depreciation | 7,165 |
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 | $ 8,353 |
Accumulated depreciation | 124 |
Construction work in progress | $ 127 |
Ownership percentage (in hundredths) | 50.00% |
Income Taxes (Details)
Income Taxes (Details) | 12 Months Ended | ||||||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | Dec. 31, 2015USD ($)$ / kWh | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Excise Tax Delay | 2 years | ||||||
Tax Increase Prevention Act of 2014 [Abstract] | |||||||
Number of years bonus depreciation was extended | 1 year | 1 year | |||||
American Taxpayer Relief Act of 2012 [Abstract] | |||||||
Original top tax rate for dividends | 15.00% | ||||||
New top tax rate for dividends | 20.00% | ||||||
Unrecognized Tax Benefits [Abstract] | |||||||
Unrecognized tax benefit — Permanent tax positions | $ 2,400,000 | $ 1,900,000 | |||||
Unrecognized tax benefit — Temporary tax positions | 15,000,000 | 10,000,000 | |||||
Total unrecognized tax benefit | $ 11,900,000 | $ 8,400,000 | $ 9,600,000 | $ 9,600,000 | 17,400,000 | 11,900,000 | $ 8,400,000 |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||||||
Balance at Jan. 1 | 11,900,000 | 8,400,000 | 9,600,000 | ||||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 4,500,000 | 3,700,000 | 3,900,000 | ||||
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions | (1,500,000) | (700,000) | 0 | ||||
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions | 2,500,000 | 2,800,000 | 3,300,000 | ||||
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions | 0 | (1,200,000) | (900,000) | ||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | (1,100,000) | (7,500,000) | ||||
Balance at Dec. 31 | $ 17,400,000 | $ 11,900,000 | $ 8,400,000 | $ 9,600,000 | |||
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract] | |||||||
NOL and tax credit carryforwards | (4,300,000) | (3,900,000) | |||||
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 11,000,000 | ||||||
Amounts accrued for penalties related to unrecognized tax benefits | 0 | 0 | $ 0 | ||||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% | 35.00% | ||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.20% | 2.80% | 3.00% | ||||
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent | 0.10% | (0.10%) | 0.10% | ||||
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent | (0.30%) | (2.10%) | (1.40%) | ||||
Effective Income Tax Rate Reconciliation, Tax Credit, Percent | (0.70%) | (0.80%) | (0.80%) | ||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 0.10% | 0.10% | (0.30%) | ||||
Effective Income Tax Rate Reconciliation, Percent | 37.40% | 34.90% | 35.60% | ||||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Current Federal Tax Expense (Benefit) | $ (1,166,000) | $ 9,550,000 | $ (52,408,000) | ||||
Current State and Local Tax Expense (Benefit) | (727,000) | 2,611,000 | (7,252,000) | ||||
Current Change In Unrecognized Tax Expense (Benefit) | 5,244,000 | 6,548,000 | (2,918,000) | ||||
Deferred Federal Income Tax Expense (Benefit) | 246,096,000 | 208,781,000 | 273,916,000 | ||||
Deferred State and Local Income Tax Expense (Benefit) | 36,450,000 | 26,196,000 | 38,243,000 | ||||
Deferred Change In Unrecognized Tax Expense (Benefit) | (4,650,000) | (7,154,000) | 4,094,000 | ||||
Deferred investment tax credits | (2,807,000) | (2,941,000) | (2,935,000) | ||||
Income Tax Expense (Benefit) | 278,440,000 | 243,591,000 | 250,740,000 | ||||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Deferred tax expense (benefit) excluding selected items | 285,144,000 | 254,142,000 | 335,580,000 | ||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (7,229,000) | (26,649,000) | (19,616,000) | ||||
Other Comprehensive Income (Loss), Tax | (19,000) | 330,000 | 289,000 | ||||
Deferred Income Tax Expense (Benefit) | $ 277,896,000 | $ 227,823,000 | $ 316,253,000 | ||||
Deferred Tax Liabilities, Gross [Abstract] | |||||||
Deferred Tax Liabilities, Property, Plant and Equipment | 2,772,043,000 | 2,467,260,000 | |||||
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits | 105,049,000 | 110,556,000 | |||||
Deferred Tax Liabilities, Other | 101,219,000 | 140,080,000 | |||||
Deferred Tax Liabilities, Net | 2,658,198,000 | 2,373,054,000 | |||||
Deferred Tax Liabilities, Gross | 2,978,311,000 | 2,717,896,000 | |||||
Deferred Tax Assets, Gross [Abstract] | |||||||
Deferred Tax Assets, Operating Loss Carryforwards | 147,763,000 | 143,158,000 | |||||
Deferred Tax Assets Unbilled Revenue Fuel Costs | 48,181,000 | 57,654,000 | |||||
Deferred Tax Assets Rate Refund | 23,352,000 | 43,735,000 | |||||
Deferred Tax Assets Tax credit carryforward | 35,240,000 | 34,493,000 | |||||
Deferred Tax Assets Regulatory Liabilities | 17,201,000 | 14,549,000 | |||||
Deferred Tax Assets Deferred Investment Tax Credits | 12,718,000 | 13,781,000 | |||||
Deferred Tax Assets, Other | 35,658,000 | 37,472,000 | |||||
Deferred Tax Assets, Net of Valuation Allowance | 320,113,000 | 344,842,000 | |||||
Internal Revenue Service (IRS) | |||||||
Tax Audits [Abstract] | |||||||
Year(s) under examination | 2012 and 2013 | 2010 and 2011 | |||||
Year of carryback claim under examination | 2,009 | ||||||
Potential Tax Adjustments | $ 14,000,000 | ||||||
Operating Loss Carryforwards | 328,000,000 | 320,000,000 | |||||
Tax Credit Carryforward, Amount | 24,000,000 | 22,000,000 | |||||
Carryforward expiration date range, low | 2,021 | ||||||
Carryforward expiration date range, high | 2,035 | ||||||
State and Local Jurisdiction | |||||||
Tax Audits [Abstract] | |||||||
Earliest year subject to examination | 2,009 | ||||||
Operating Loss Carryforwards | 684,000,000 | 690,000,000 | |||||
Tax Credit Carryforward Net Of Federal Detriment | 13,000,000 | 12,000,000 | |||||
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit | (1,000,000) | 0 | |||||
Federal detriment | 7,000,000 | $ 7,000,000 | |||||
Federal Benefit | $ 1,000,000 | ||||||
Carryforward expiration date range, low | 2,017 | ||||||
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; 2018 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 40.00% | ||||||
Production Tax Credit Rate, Percent | 60.00% | ||||||
Consolidated Appropriations Act of 2016; 2019 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 30.00% | ||||||
Production Tax Credit Rate, Percent | 40.00% | ||||||
Investment Tax Credit Rate, Percent | 30.00% | ||||||
Consolidated Appropriations Act of 2016; 2016 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Production Tax Credit Rate, Percent | 100.00% | ||||||
Production Tax Credit per KWh | $ / kWh | 0.023 | ||||||
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; 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% | ||||||
Tax Increase Prevention Act of 2014; 2014 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 50.00% | ||||||
Tax Increase Prevention Act of 2014; 2015 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 50.00% | ||||||
American Taxpayer Relief Act of 2012; 2013 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 50.00% | ||||||
American Taxpayer Relief Act of 2012; 2014 Impact [Member] | |||||||
Consolidated Appropriations Act of 2016 [Abstract] | |||||||
Bonus depreciation rate, Percent | 50.00% |
Benefit Plans and Other Postr57
Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details) | Dec. 31, 2015Employee |
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) | 77.00% |
Number of bargaining employees receiving benefits under several collective bargaining agreements | 2,024 |
Benefit Plans and Other Postr58
Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Commingled funds | Minimum | |
Defined Benefit Plan Disclosure [Line Items] | |
Notice period for investment redemption | 1 day |
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 Postr59
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | $ 3,600 | $ 3,800 | |
Net benefit cost recognized for financial reporting | 600 | 600 | |
Pension Plans | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | 1,224,650 | 1,277,957 | $ 1,152,836 |
Net benefit cost recognized for financial reporting | $ 38,304 | $ 37,307 | $ 49,899 |
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years) | 20 years | ||
Expected average long-term rate of return on assets (as a percent) | 6.81% | 6.81% | 6.47% |
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 Plans | Domestic and international equity securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 36.00% | 32.00% | |
Pension Plans | Long-duration fixed income and interest rate swap securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 32.00% | 35.00% | |
Pension Plans | Short-to-intermediate fixed income securities | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 12.00% | 12.00% | |
Pension Plans | Alternative investments | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 18.00% | 18.00% | |
Pension Plans | Cash | |||
Target Pension Asset Allocations [Abstract] | |||
Target pension asset allocations (as a percent) | 2.00% | 3.00% | |
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | |||
Pension Benefits [Abstract] | |||
Total benefit obligation | $ 41,800 | $ 46,500 | |
Net benefit cost recognized for financial reporting | $ 9,500 | $ 4,700 |
Benefit Plans and Other Postr60
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | $ 1,036,681 | $ 1,103,865 | $ 1,067,057 | |
Level 1 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 110,751 | 119,553 | ||
Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 872,896 | 915,692 | ||
Level 3 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 53,034 | 68,620 | 64,578 | $ 82,991 |
Cash equivalents | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 81,954 | 82,486 | ||
Cash equivalents | Level 1 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 81,954 | 82,486 | ||
Cash equivalents | 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 equivalents | Level 3 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 0 | 0 | ||
Derivatives | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 1,204 | 508 | ||
Derivatives | Level 1 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 0 | 0 | ||
Derivatives | Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 1,204 | 508 | ||
Derivatives | 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 | 214,341 | 180,912 | ||
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 | 214,341 | 180,912 | ||
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 | ||
Corporate bonds | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 86,914 | 115,593 | ||
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 | ||
Corporate bonds | Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 86,914 | 115,593 | ||
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 | 881 | 1,360 | ||
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 | 881 | 1,360 | ||
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 | 0 | 4,604 |
Mortgage-backed securities | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 3,997 | |||
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 | 3,997 | |||
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 | 12,058 | |
Common stock | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 28,797 | 37,067 | ||
Common stock | Level 1 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 28,797 | 37,067 | ||
Common stock | Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 0 | 0 | ||
Common stock | Level 3 | ||||
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 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 34,353 | 50,210 | ||
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 | 34,353 | 50,210 | 49,022 | 47,056 |
Commingled funds | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 573,009 | 629,439 | ||
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 | 0 | ||
Commingled funds | Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 573,009 | 629,439 | ||
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 | ||
Real estate | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | 18,681 | 18,410 | 15,556 | |
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 | 18,681 | 18,410 | $ 15,556 | $ 19,273 |
Securities lending collateral obligation and other | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | (3,453) | (16,117) | ||
Securities lending collateral obligation and 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 | ||
Securities lending collateral obligation and other | Level 2 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | ||||
Fair value of plan assets | (3,453) | (16,117) | ||
Securities lending collateral obligation and 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 Postr61
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | $ 1,103,865 | $ 1,067,057 | |||
Fair value of plan assets at Dec. 31 | 1,036,681 | 1,103,865 | $ 1,067,057 | ||
Level 3 | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 68,620 | 64,578 | 82,991 | ||
Net realized gains (losses) | 9,561 | 9,675 | 6,204 | ||
Net unrealized gains (losses) | (22,407) | (4,601) | (258) | ||
Purchases, issuances and settlements, net | (2,740) | (1,032) | 1,967 | ||
Transfers in (out) of Level 3 | 0 | 0 | (26,326) | [1] | |
Fair value of plan assets at Dec. 31 | 53,034 | 68,620 | 64,578 | ||
Asset-backed securities | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 1,360 | ||||
Fair value of plan assets at Dec. 31 | 881 | 1,360 | |||
Asset-backed securities | Level 3 | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 0 | 0 | 4,604 | ||
Net realized gains (losses) | 0 | ||||
Net unrealized gains (losses) | 0 | ||||
Purchases, issuances and settlements, net | 0 | ||||
Transfers in (out) of Level 3 | [1] | (4,604) | |||
Fair value of plan assets at Dec. 31 | 0 | 0 | 0 | ||
Mortgage-backed securities | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 3,997 | ||||
Fair value of plan assets at Dec. 31 | 3,997 | ||||
Mortgage-backed securities | Level 3 | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 0 | 0 | 12,058 | ||
Net realized gains (losses) | 0 | ||||
Net unrealized gains (losses) | 0 | ||||
Purchases, issuances and settlements, net | 0 | ||||
Transfers in (out) of Level 3 | [1] | (12,058) | |||
Fair value of plan assets at Dec. 31 | 0 | 0 | |||
Private equity investments | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 50,210 | ||||
Fair value of plan assets at Dec. 31 | 34,353 | 50,210 | |||
Private equity investments | Level 3 | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 50,210 | 49,022 | 47,056 | ||
Net realized gains (losses) | 7,636 | 8,495 | 7,074 | ||
Net unrealized gains (losses) | (20,036) | (4,299) | (4,027) | ||
Purchases, issuances and settlements, net | (3,457) | (3,008) | (1,081) | ||
Transfers in (out) of Level 3 | 0 | 0 | 0 | [1] | |
Fair value of plan assets at Dec. 31 | 34,353 | 50,210 | 49,022 | ||
Real estate | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 18,410 | 15,556 | |||
Fair value of plan assets at Dec. 31 | 18,681 | 18,410 | 15,556 | ||
Real estate | Level 3 | |||||
Changes in Level 3 Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 18,410 | 15,556 | 19,273 | ||
Net realized gains (losses) | 1,925 | 1,180 | (870) | ||
Net unrealized gains (losses) | (2,371) | (302) | 3,769 | ||
Purchases, issuances and settlements, net | 717 | 1,976 | 3,048 | ||
Transfers in (out) of Level 3 | 0 | 0 | (9,664) | [1] | |
Fair value of plan assets at Dec. 31 | $ 18,681 | $ 18,410 | $ 15,556 | ||
[1] | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
Benefit Plans and Other Postr62
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Pension Plans $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2016USD ($)Plan | Dec. 31, 2015USD ($)Plan | Dec. 31, 2014USD ($)Plan | Dec. 31, 2013USD ($)Plan | ||
Defined Benefit Plan Disclosure [Line Items] | |||||
Accumulated Benefit Obligation at Dec. 31 | $ 1,192,798 | $ 1,249,739 | |||
Change in Projected Benefit Obligation [Roll Forward] | |||||
Obligation at Jan. 1 | $ 1,224,650 | 1,277,957 | 1,152,836 | ||
Service cost | 28,260 | 23,939 | $ 25,206 | ||
Interest cost | 50,857 | 53,277 | 46,160 | ||
Transfer (to) from other plan | (2,938) | (13,404) | |||
Actuarial (gain) loss | (54,737) | 133,215 | |||
Benefit payments | (74,749) | (71,906) | |||
Obligation at Dec. 31 | 1,224,650 | 1,277,957 | 1,152,836 | ||
Change in Fair Value of Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 1,036,681 | 1,103,865 | 1,067,057 | ||
Actual return (loss) on plan assets | (9,122) | 84,871 | |||
Employer contributions | 20,056 | 35,156 | |||
Transfer (to) from other plan | (3,369) | (11,313) | |||
Benefit payments | (74,749) | (71,906) | |||
Fair value of plan assets at Dec. 31 | 1,036,681 | 1,103,865 | 1,067,057 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Funded status | [1] | (187,969) | (174,092) | ||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | |||||
Net loss | 521,703 | 530,674 | |||
Prior service (credit) cost | (15,572) | (18,708) | |||
Total | 506,131 | 511,966 | |||
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 | 28,852 | 31,774 | |||
Noncurrent regulatory assets | 477,279 | 480,192 | |||
Total | $ 506,131 | $ 511,966 | |||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | |||||
Measurement date | Dec. 31, 2015 | Dec. 31, 2014 | |||
Discount rate for year-end valuation (as a percent) | 4.66% | 4.11% | |||
Expected average long-term increase in compensation level (as a percent) | 4.00% | 3.75% | |||
Mortality table | RP 2,014 | RP 2,014 | |||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 20,100 | $ 35,200 | 44,600 | ||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 28,260 | 23,939 | 25,206 | ||
Interest cost | 50,857 | 53,277 | 46,160 | ||
Expected return on plan assets | (72,590) | (70,709) | (63,821) | ||
Amortization of prior service (credit) cost | (3,136) | (3,092) | (1,064) | ||
Amortization of net loss | 36,377 | 33,892 | 43,418 | ||
Net periodic benefit cost | 39,768 | 37,307 | 49,899 | ||
Costs not recognized due to regulation | (1,464) | 0 | 0 | ||
Net benefit cost recognized for financial reporting | $ 38,304 | $ 37,307 | $ 49,899 | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Discount rate (as a percent) | 4.11% | 4.75% | 4.00% | ||
Expected average long-term increase in compensation level (as a percent) | 3.75% | 3.75% | 3.75% | ||
Expected average long-term rate of return on assets (as a percent) | 6.81% | 6.81% | 6.47% | ||
Allocated costs for pension plans sponsored by Xcel Energy Inc. | $ 9,900 | $ 9,400 | $ 11,600 | ||
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% | ||||
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 | $ 90,100 | $ 130,600 | $ 192,400 | ||
Subsequent Event | |||||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 16,800 | ||||
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 | $ 125,000 | ||||
[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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Contribution Plans [Abstract] | |||
Contributions to 401(k) and other defined contribution plans | $ 9.5 | $ 9.1 | $ 8.7 |
Benefit Plans and Other Postr64
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
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) | 25.00% | 25.00% |
Short-to-intermediate fixed income securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 57.00% | 57.00% |
Alternative investments | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 13.00% | 13.00% |
Cash | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 5.00% | 5.00% |
Benefit Plans and Other Postr65
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | $ 399,442 | $ 425,282 | $ 438,193 | ||
Level 1 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 17,524 | 23,566 | |||
Level 2 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 381,918 | 401,716 | |||
Level 3 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 0 | 0 | 0 | $ 36,064 | |
Cash equivalents | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Cash collateral restricted for use | 900 | ||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 17,524 | 23,566 | [1] | ||
Cash equivalents | Level 1 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 17,524 | 23,566 | [1] | ||
Cash equivalents | Level 2 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 0 | 0 | [1] | ||
Cash equivalents | Level 3 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 0 | 0 | [1] | ||
Derivatives | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 166 | ||||
Derivatives | Level 1 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 0 | ||||
Derivatives | Level 2 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 166 | ||||
Derivatives | 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 | 35,016 | 43,494 | |||
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 | 35,016 | 43,494 | |||
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 | |||
Insurance contracts | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 42,123 | 45,075 | |||
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 | 42,123 | 45,075 | |||
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 | |||
Corporate bonds | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 65,031 | 48,527 | |||
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 | |||
Corporate bonds | Level 2 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 65,031 | 48,527 | |||
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 | 25,602 | 3,240 | 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 | 25,602 | 3,240 | |||
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 | 670 | ||
Mortgage-backed securities | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 31,778 | 10,071 | |||
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 | 31,778 | 10,071 | |||
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 | $ 0 | $ 35,394 | |
Commingled funds | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 182,736 | 252,790 | |||
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 | 0 | |||
Commingled funds | Level 2 | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | 182,736 | 252,790 | |||
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 | |||
Other | |||||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||||
Fair value of plan assets | (368) | (1,647) | |||
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 | (368) | (1,647) | |||
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 | |||
[1] | Includes restricted cash of $0.9 million at Dec. 31, 2014. |
Benefit Plans and Other Postr66
Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | $ 425,282 | $ 438,193 | ||
Fair value of plan assets at Dec. 31 | 399,442 | 425,282 | $ 438,193 | |
Level 3 | ||||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 0 | 0 | 36,064 | |
Net realized gains (losses) | 0 | |||
Net unrealized gains (losses) | 0 | |||
Purchases, issuances and settlements, net | 0 | |||
Transfers in (out) of Level 3 | [1] | (36,064) | ||
Fair value of plan assets at Dec. 31 | 0 | 0 | 0 | |
Asset-backed securities | ||||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 3,240 | 0 | ||
Fair value of plan assets at Dec. 31 | 25,602 | 3,240 | 0 | |
Asset-backed securities | Level 3 | ||||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 0 | 670 | ||
Net realized gains (losses) | 0 | |||
Net unrealized gains (losses) | 0 | |||
Purchases, issuances and settlements, net | 0 | |||
Transfers in (out) of Level 3 | [1] | (670) | ||
Fair value of plan assets at Dec. 31 | 0 | 0 | ||
Mortgage-backed securities | ||||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 10,071 | |||
Fair value of plan assets at Dec. 31 | 31,778 | 10,071 | ||
Mortgage-backed securities | Level 3 | ||||
Changes in Level 3 Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 0 | 0 | 35,394 | |
Net realized gains (losses) | 0 | |||
Net unrealized gains (losses) | 0 | |||
Purchases, issuances and settlements, net | 0 | |||
Transfers in (out) of Level 3 | [1] | (35,394) | ||
Fair value of plan assets at Dec. 31 | $ 0 | $ 0 | $ 0 | |
[1] | Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013. |
Benefit Plans and Other Postr67
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Change in Projected Benefit Obligation [Roll Forward] | ||||
Obligation at Jan. 1 | $ 443,753 | $ 508,971 | ||
Service cost | 928 | 1,915 | $ 2,564 | |
Interest cost | 17,498 | 23,704 | 22,210 | |
Medicare subsidy reimbursements | 1,712 | 1,753 | ||
Plan participants' contributions | 4,961 | 4,625 | ||
Actuarial (gain) loss | (32,001) | (63,130) | ||
Benefit payments | (33,277) | (34,085) | ||
Obligation at Dec. 31 | 403,574 | 443,753 | 508,971 | |
Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of plan assets at Jan. 1 | 425,282 | 438,193 | ||
Actual return (loss) on plan assets | (3,076) | 11,060 | ||
Plan participants' contributions | 4,961 | 4,625 | ||
Employer contributions | 5,552 | 5,489 | ||
Benefit payments | (33,277) | (34,085) | ||
Fair value of plan assets at Dec. 31 | 399,442 | 425,282 | 438,193 | |
Funded Status of Plans at Dec. 31 [Abstract] | ||||
Funded status | [1] | (4,132) | (18,471) | |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | ||||
Net loss | 49,226 | 56,823 | ||
Prior service (credit) cost | (33,942) | (40,189) | ||
Total | 15,284 | 16,634 | ||
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 | $ 15,284 | $ 16,634 | ||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | ||||
Measurement date | 12/31/2015 | 12/31/2014 | ||
Discount rate for year-end valuation (as a percent) | 4.65% | 4.08% | ||
Mortality table | RP 2,014 | RP 2,014 | ||
Health care costs trend rate - initial (as a percent) | 6.00% | 6.50% | ||
Ultimate health care trend assumption rate (as a percent) | 4.50% | 4.50% | ||
Period until ultimate trend rate is reached (in years) | 3 years | |||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | ||||
One-percent increase in APBO | $ 38,946 | |||
One-percent decrease in APBO | (33,136) | |||
One-percent increase in service and interest components | 2,093 | |||
One-percent decrease in service and interest components | (1,743) | |||
Cash Flows [Abstract] | ||||
Total contributions to Xcel Energy's postretirement health care plans during the year | 5,600 | $ 5,500 | 7,000 | |
Expected contribution to postretirement health care plans during 2016 | 0 | |||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | ||||
Service cost | 928 | 1,915 | 2,564 | |
Interest cost | 17,498 | 23,704 | 22,210 | |
Expected return on plan assets | (23,803) | (30,214) | (29,227) | |
Amortization of transition obligation | 0 | 0 | 785 | |
Amortization of prior service (credit) cost | (6,247) | (6,247) | (7,666) | |
Amortization of net loss | 2,475 | 6,434 | 13,699 | |
Net periodic benefit cost | $ (9,149) | $ (4,408) | $ 2,365 | |
Significant Assumptions Used to Measure Costs [Abstract] | ||||
Discount rate (as a percent) | 4.08% | 4.82% | 4.10% | |
Expected average long-term rate of return on assets (as a percent) | 5.80% | 7.18% | 7.11% | |
Xcel Energy Inc. | ||||
Cash Flows [Abstract] | ||||
Total contributions to Xcel Energy's postretirement health care plans during the year | $ 18,300 | $ 17,100 | $ 17,600 | |
Expected contribution to postretirement health care plans during 2016 | $ 12,300 | |||
[1] | Amounts are recognized in noncurrent liabilities on PSCo’s consolidated balance sheets. |
Benefit Plans and Other Postr68
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Pension Plans | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2,016 | $ 77,898 |
2,017 | 77,952 |
2,018 | 80,583 |
2,019 | 82,760 |
2,020 | 83,372 |
2021-2025 | 430,762 |
Postretirement Benefit Plan | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2,016 | 32,197 |
2,017 | 32,356 |
2,018 | 32,381 |
2,019 | 32,402 |
2,020 | 33,093 |
2021-2025 | 158,040 |
Expected Medicare Part D Subsidies [Abstract] | |
2,016 | 2,234 |
2,017 | 2,373 |
2,018 | 2,517 |
2,019 | 2,647 |
2,020 | 2,753 |
2021-2025 | 15,450 |
Defined Benefit Plan, Net Projected Benefit Payments [Abstract] | |
2,016 | 29,963 |
2,017 | 29,983 |
2,018 | 29,864 |
2,019 | 29,755 |
2,020 | 30,340 |
2021-2025 | $ 142,590 |
Fair Value of Financial Asset69
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions | Dec. 31, 2015USD ($)galMWhMMBTUCounterparty | Dec. 31, 2014galMWhMMBTU | |
Commodity Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | $ (0.1) | ||
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 | Counterparty | 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 | Counterparty | 9 | ||
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 | Counterparty | 3 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 1.2 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 2.00% | ||
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 | Counterparty | 6 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 33.2 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 48.00% | ||
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 4.9 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 7.00% | ||
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) | ||
Electric Commodity | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1],[2] | 684 | 0 |
Natural Gas Commodity | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 12,515 | 735 |
Vehicle Fuel Commodity | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | gal | [1],[2] | 63 | 127 |
[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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Income and Expenses [Abstract] | |||
Interest income | $ 753 | $ 1,470 | $ 1,761 |
Other nonoperating income | 2,408 | 3,601 | 2,603 |
Insurance Policy Expense (Income), Net | (197) | (806) | (1,228) |
Other income, net | $ 2,964 | $ 4,265 | $ 3,136 |
Fair Value of Financial Asset71
Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ (23,878) | $ (23,338) | $ (22,871) |
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges | (30) | (72) | 9 |
After-tax net realized losses (gains) on derivative transactions reclassified into earnings | 72 | (468) | (476) |
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | $ (23,836) | $ (23,878) | $ (23,338) |
Fair Value of Financial Asset72
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
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 | (50,000) | (115,000) | 14,000 | ||||
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 | 111,000 | (755,000) | (770,000) | ||||
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] | 54,000 | (730,000) | (730,000) | |||
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 | (50,000) | (115,000) | 14,000 | ||||
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 | [2] | 57,000 | (25,000) | (40,000) | |||
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 | ||||
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 | (10,635,000) | 451,000 | (4,001,000) | ||||
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) | 10,158,000 | (4,631,000) | 4,340,000 | ||||
Pre-tax gains (losses) recognized during the period in income | (7,256,000) | (9,850,000) | (5,850,000) | ||||
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 | ||||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | ||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | ||||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | ||||||
Pre-tax gains (losses) recognized during the period in income | [3] | 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 | (10,635,000) | 451,000 | (4,001,000) | ||||
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] | 10,158,000 | (4,631,000) | 4,340,000 | |||
Pre-tax gains (losses) recognized during the period in income | (7,620,000) | [4] | $ (9,850,000) | [4] | $ (5,850,000) | [5] | |
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 (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | $ 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] | Amounts for the year ended Dec. 31, 2015 included $1.1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2015, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. | ||||||
[5] | Amounts are recorded to electric fuel and purchased power. |
Fair Value of Financial Asset73
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
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 Asset74
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ 0 | $ 0 | |||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | 0 | |||
Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,945 | 1,731 | |||
Other Noncurrent Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,478 | 5,176 | |||
Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 8,881 | 5,774 | |||
Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 13,020 | 18,257 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 230 | 15 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 164 | ||||
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 66 | 15 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,691 | 583 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 92 | 53 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,564 | 530 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | 81 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 46 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 137 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 137 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | 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 [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 34 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 34 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities [Member] | 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 1 | Other Noncurrent Liabilities [Member] | 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 2 | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 703 | 33 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 351 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 352 | 33 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 4,267 | 601 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 92 | 53 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 325 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,850 | 548 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | 81 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 46 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | 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 [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | 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 3 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities [Member] | 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 3 | Other Noncurrent Liabilities [Member] | 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 | Fair Value Total | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 840 | 33 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 488 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 352 | 33 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 16 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 4,301 | 601 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 92 | 53 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 359 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 3,850 | 548 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | 81 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 46 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 33 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (610) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | [1] | (324) | |||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (286) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (610) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | (324) | |||
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (286) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [2] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Commodity Trading | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [2] | 0 | |||
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,715 | [3] | 1,716 | [4] | |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,462 | [3] | 5,176 | [4] | |
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,190 | [3] | 5,191 | [4] | |
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ 12,987 | [3] | $ 18,176 | [4] | |
[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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral 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. | ||||
[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, 2014. At Dec. 31, 2014, 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] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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 Asset75
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 Asset76
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 4,132,191 | $ 3,890,229 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 4,376,875 | $ 4,328,968 |
Rate Matters (Details)
Rate Matters (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||||||
Feb. 29, 2016USD ($) | Dec. 31, 2015USD ($) | Nov. 30, 2015USD ($) | Jul. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Dec. 31, 2015USD ($)MWh | Dec. 31, 2014USD ($)MWh | Dec. 31, 2012USD ($) | Dec. 31, 2011 | |
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Original Request - Gas Rates PSIA Rider 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Revenue Impact Of Requested Rider | $ 21,700 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Original Request - Gas Rates PSIA Rider 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Revenue Impact Of Requested Rider | 21,200 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 66,200 | |||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 3 years | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 56.00% | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,260 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 40,500 | |||||||||
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates | $ 0 | |||||||||
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||||||
Public Utilities, Revised Base Rate Request From Rebuttal Testimony | 40,500 | |||||||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 40,400 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7,600 | |||||||||
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates | 7,000 | |||||||||
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||||||
Public Utilities, Revised Base Rate Request From Rebuttal Testimony | 14,600 | |||||||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 29,300 | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,310 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18,100 | |||||||||
Public Utilities, Increase in Request By Shift in O&M Expenses Between Rider And Base Rates | 6,400 | |||||||||
Public Utilities, Decrease in Request by Corrections And Adjustments Based On Rebuttal Testimony | (7,700) | |||||||||
Public Utilities, Revised Base Rate Request From Rebuttal Testimony | 16,800 | |||||||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 38,500 | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.30% | |||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,360 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Number Of Years Rate Case Is Applicable For | 3 years | |||||||||
Public Utilities, Revenue Impact Of Requested Rider | $ 42,800 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Revenue Impact Of Requested Rider | (100) | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Revenue Impact Of Requested Rider | 14,700 | |||||||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Revenue Impact Of Requested Rider | 21,700 | |||||||||
Colorado 2015 Steam Rate Case | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 3,500 | |||||||||
Colorado 2015 Steam Rate Case, Phase 1 - Jan. 1, 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 2,800 | |||||||||
Colorado 2015 Steam Rate Case, Phase 2 - Nov. 1, 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 700 | |||||||||
CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Return on Equity Threshold for Earnings Sharing | 9.83% | |||||||||
2015 Electric Earnings Test | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Refund to Customers Due to Annual Earnings Test | $ 15,000 | |||||||||
CPUC Proceeding - Demand Side Management Cost Adjustment | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Incentive Award Upon Achieving Savings Goal | $ 5,000 | |||||||||
Public Utilities, Percentage of Net Economic Benefits on Which Incentive is Earned | 5.00% | |||||||||
Public Utilities, Maximum Annual Incentive | $ 30,000 | |||||||||
CPUC Proceeding - Demand Side Management Cost Adjustment, 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Electric Demand Side Management Budget | 81,600 | |||||||||
Public Utilities, Approved Gas Demand Side Management Budget | 13,100 | |||||||||
CPUC Proceeding - Demand Side Management Cost Adjustment, 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Electric Demand Side Management Budget | 78,700 | |||||||||
Public Utilities, Approved Gas Demand Side Management Budget | $ 13,600 | |||||||||
CPUC Proceeding - Renewable Energy Credit Sharing | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Customers Share of Margins Credited Against RESA Regulatory Asset Balance | 5,500 | $ 600 | ||||||||
Public Utilities, Cumulative Credit Against RESA Regulatory Asset Balance | $ 110,600 | $ 110,600 | $ 105,100 | |||||||
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Recommended Length Of Average Rate Base By Third Parties (in Months) | 13 | |||||||||
Public utilities, ROE recommended by third parties | 9.50% | |||||||||
Public Utilities, Recommended Equity Capital Structure, Percentage | 56.51% | |||||||||
Public Utilities, Proposed Number of Years Extending PSIA Rider Recommended by Third Parties | 3 years | |||||||||
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease to Requested Return on Equity | $ (7,800) | |||||||||
Public Utilities, Decrease to Cost of Debt and Capital Structure | (500) | |||||||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | 4,100 | |||||||||
Public Utilities, Decrease in Move to Historical Test Year | (14,100) | |||||||||
Public Utilities, Decrease to O&M Expenses | (3,000) | |||||||||
Public Utilities, Decrease Related To Other, Net | (1,100) | |||||||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | 18,100 | |||||||||
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Recommended Rider Costs to be Recovered Through Base Rates, Amount | 20,000 | |||||||||
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease in Request by Transfer Of Costs To Base Rates | (20,500) | |||||||||
Public Utilities, Decrease in Request By Cost Recovery Remaining In Base | (4,300) | |||||||||
Public Utilities, Decrease In Request For Projects Not Recovered Through The Rider | (3,600) | |||||||||
Public Utilities, Decrease to Return on Equity and Capital Structure | (300) | |||||||||
Public Utilities, Recommended Rider Increase (Decrease) | (7,000) | |||||||||
Administrative Law Judge | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease in Request by Transfer Of Costs To Base Rates | 0 | |||||||||
Public Utilities, Decrease in Request By Cost Recovery Remaining In Base | 0 | |||||||||
Public Utilities, Decrease In Request For Projects Not Recovered Through The Rider | (2,000) | |||||||||
Public Utilities, Decrease to Return on Equity and Capital Structure | (1,600) | |||||||||
Public Utilities, Recommended Rider Increase (Decrease) | $ 17,600 | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2014 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Maximum Savings Goal (in MWh) | MWh | 384 | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Maximum Savings Goal (in MWh) | MWh | 400 | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Margin Threshold Determining Percentage of Margin Sharing | $ 20,000 | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing | Shareholders | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Ultimate Margin Sharing Associated With Stand Alone REC Transactions | 10.00% | |||||||||
Public Utilities, Percentage of Margin on REC Margin Limit Approved | 20.00% | |||||||||
Public Utilities, Percentage of Margin in Excess of REC Margin Limit Approved | 10.00% | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Renewable Energy Credit Sharing | Customers | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Ultimate Margin Sharing Associated With Stand Alone REC Transactions | 90.00% | |||||||||
Public Utilities, Percentage of Margin on REC Margin Limit Approved | 80.00% | |||||||||
Public Utilities, Percentage of Margin in Excess of REC Margin Limit Approved | 90.00% | |||||||||
Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Demand Side Management Cost Adjustment, 2016 through 2020 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Maximum Savings Goal (in MWh) | MWh | 400 | |||||||||
Public Utilities, Annual Spending Limit | $ 84,300 | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Length Of Average Rate Base By Third Parties (in Months) | 13 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.50% | |||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 56.51% | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease to Approved Return on Equity | $ (7,800) | |||||||||
Public Utilities, Decrease to Cost of Debt and Capital Structure | (500) | |||||||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | 4,100 | |||||||||
Public Utilities, Decrease in Move to Historical Test Year | (14,100) | |||||||||
Public Utilities, Decrease to O&M Expenses | (2,400) | |||||||||
Public Utilities, Decrease Related To Other, Net | (1,100) | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 18,700 | |||||||||
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization | (3,600) | |||||||||
Public Utilities, Estimated Pre-Tax Impact | 14,900 | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 19,700 | |||||||||
Public Utilities, Approved Rider Costs To Be Recovered Through Base Rates, Amount | 20,000 | |||||||||
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization | 1,500 | |||||||||
Public Utilities, Estimated Pre-Tax Impact | 14,500 | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 0 | |||||||||
Public Utilities, Increase (Decrease) In Estimated Pre-Tax Impact For Expense Deferrals, Net Amortization | 5,200 | |||||||||
Public Utilities, Estimated Pre-Tax Impact | 24,000 | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Approved Rider Increase (Decrease) | (200) | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease To Written Order By Transfer Of Costs To Base Rates | (20,500) | |||||||||
Public Utilities, Decrease to Written Order By Cost Recovery Remaining In Base | (4,300) | |||||||||
Public Utilities, Decrease To Written Order For Projects Not Recovered Through The Rider | (3,300) | |||||||||
Public Utilities, Decrease To Written Order For Approved Return on Equity and Capital Structure | (300) | |||||||||
Public Utilities, Approved Rider Increase (Decrease) | (6,700) | |||||||||
Subsequent Event | Colorado Public Utilities Commission (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 | ||||||||||
Rate Matters [Abstract] | ||||||||||
Public Utilities, Decrease To Written Order By Transfer Of Costs To Base Rates | 0 | |||||||||
Public Utilities, Decrease to Written Order By Cost Recovery Remaining In Base | 0 | |||||||||
Public Utilities, Decrease To Written Order For Projects Not Recovered Through The Rider | (800) | |||||||||
Public Utilities, Decrease To Written Order For Approved Return on Equity and Capital Structure | (1,600) | |||||||||
Public Utilities, Approved Rider Increase (Decrease) | $ 18,800 |
Commitments and Contingencies,
Commitments and Contingencies, Fuel Contracts (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Minimum | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Fuel Contract Expiration Date (year) | 2,016 |
Maximum | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Fuel Contract Expiration Date (year) | 2,060 |
Coal | |
Fuel Contracts [Abstract] | |
2,016 | $ 302.3 |
2,017 | 230.3 |
2,018 | 118.5 |
2,019 | 42 |
2,020 | 43.6 |
Thereafter | 332.3 |
Total | 1,069 |
Natural Gas Supply | |
Fuel Contracts [Abstract] | |
2,016 | 231.1 |
2,017 | 129.5 |
2,018 | 181 |
2,019 | 187.6 |
2,020 | 203.4 |
Thereafter | 409.6 |
Total | 1,342.2 |
Natural Gas Storage and Transportation | |
Fuel Contracts [Abstract] | |
2,016 | 137.5 |
2,017 | 137.2 |
2,018 | 85.5 |
2,019 | 51 |
2,020 | 50.4 |
Thereafter | 773.2 |
Total | $ 1,234.8 |
Commitments and Contingencies79
Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Long-term Contract for Purchase of Electric Power [Line Items] | ||||
Purchase Power Agreement Expiration (year) | 2,032 | |||
Capacity | ||||
Purchased Power Agreements (PPAs) [Abstract] | ||||
Payments for capacity | $ 69.5 | $ 69.5 | $ 72.7 | |
Estimated Future Payments Under PPAs [Abstract] | ||||
2,016 | 44.5 | |||
2,017 | 24.3 | |||
2,018 | 19.2 | |||
2,019 | 10.3 | |||
2,020 | 1.5 | |||
Thereafter | 9.5 | |||
Total | 109.3 | |||
Energy | ||||
Estimated Future Payments Under PPAs [Abstract] | ||||
2,016 | [1] | 25.3 | ||
2,017 | [1] | 4.4 | ||
2,018 | [1] | 0 | ||
2,019 | [1] | 0 | ||
2,020 | [1] | 0 | ||
Thereafter | [1] | 0 | ||
Total | [1] | $ 29.7 | ||
[1] | Excludes contingent energy payments for renewable energy PPAs |
Commitments and Contingencies80
Commitments and Contingencies, Leases (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015USD ($)Lease | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | ||
Capital Leases [Abstract] | ||||
Number of leases qualifying as capital leases | Lease | 3 | |||
Amortization expense under capital lease assets | $ 8.2 | $ 7.2 | $ 6.3 | |
Property Held Under Capital Leases, Net [Abstract] | ||||
Property held under capital lease | 221.2 | 221.2 | ||
Accumulated depreciation | (57.2) | (49) | ||
Total property held under capital leases, net | $ 164 | 172.2 | ||
Operating Leased Assets [Line Items] | ||||
Operating Lease Purchase Power Agreement Expiration (years) | 2,032 | |||
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,016 | $ 114.2 | |||
2,017 | 103.6 | |||
2,018 | 103.4 | |||
2,019 | 104.3 | |||
2,020 | 105.1 | |||
Thereafter | 619.2 | |||
Capital Leases, Future Minimum Payments Due [Abstract] | ||||
2,016 | 29.3 | |||
2,017 | 25.7 | |||
2,018 | 25.3 | |||
2,019 | 25.1 | |||
2,020 | 24.9 | |||
Thereafter | 486.5 | |||
Total minimum obligation | 616.8 | |||
Interest component of obligation | (452.8) | |||
Present value of minimum obligation | $ 164 | |||
WYCO Totem Gas Storage Facilities | ||||
Capital Leases [Abstract] | ||||
Ownership interest in joint venture (in hundredths) | 50.00% | |||
Capital lease obligations | $ 132.9 | 138.9 | ||
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 | 130.5 | 126.2 | 96.6 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,016 | 12 | |||
2,017 | 7.8 | |||
2,018 | 7.4 | |||
2,019 | 7.4 | |||
2,020 | 7.4 | |||
Thereafter | 39.5 | |||
Purchased Power Agreements | ||||
Operating Leases [Abstract] | ||||
Payments for capacity for PPAs under operating lease obligations | 113.5 | $ 110.1 | $ 79.6 | |
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2,016 | [1],[2] | 102.2 | ||
2,017 | [1],[2] | 95.8 | ||
2,018 | [1],[2] | 96 | ||
2,019 | [1],[2] | 96.9 | ||
2,020 | [1],[2] | 97.7 | ||
Thereafter | [1],[2] | $ 579.7 | ||
[1] | Amounts do not include PPAs accounted for as executory contracts. | |||
[2] | PPA operating leases contractually expire through 2032. |
Commitments and Contingencies81
Commitments and Contingencies, Variable Interest Entities (Details) - MW | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Purchased Power Agreements (PPAs) [Abstract] | ||
VIE Purchase Power Agreement Expiration (year) | 2,032 | |
Independent Power Producing Entities | ||
Purchased Power Agreements (PPAs) [Abstract] | ||
Generating capacity (in MW) | 1,802 | 1,802 |
Commitments and Contingencies82
Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)Site | Oct. 30, 2015Period | Dec. 31, 2014USD ($) | |
Regional Haze Rules | |||
Environmental Requirements [Abstract] | |||
Amount spent on installation of emission controls | $ 75.2 | ||
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 | ||
Number of months in which the state would have to submit an implementation plan for the respective nonattaiment areas | 18 months | ||
Number of years for the state to achieve the designated attainment standard | 5 years | ||
National Ambient Air Quality Standards for Ozone | |||
Environmental Requirements [Abstract] | |||
Number of hours measured for standard | Period | 8 | ||
Current level of air quality concentrations (in parts per billion) | 75 | ||
Proposed level of air quality concentrations (in parts per billion) | 70 | ||
Minimum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines | |||
Environmental Requirements [Abstract] | |||
Liability for estimated cost to comply with regulation | $ 9 | ||
Maximum | Capital Commitments | Federal Clean Water Act Effluent Limitations Guidelines | |||
Environmental Requirements [Abstract] | |||
Liability for estimated cost to comply with regulation | $ 21 | ||
Other MGP Sites | |||
Site Contingency [Line Items] | |||
Number of identified MGP sites under current investigation and/or remediation | Site | 2 | ||
Liability for estimated cost of remediating sites | $ 1.7 | $ 1.8 |
Commitments and Contingencies83
Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | $ 225,296 | [1] | $ 60,398 | |
Liabilities recognized | 0 | 21,864 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 9,575 | 3,701 | ||
Cash Flow Revisions | 5,637 | [2] | 139,333 | [3] |
Ending balance | 240,508 | [4] | 225,296 | [1] |
Electric Plant Steam and Other Production Asbestos | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 36,856 | [1] | 23,914 | |
Liabilities recognized | 0 | 747 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 1,820 | 1,597 | ||
Cash Flow Revisions | 0 | [2] | 10,598 | [3] |
Ending balance | 38,676 | [4] | 36,856 | [1] |
Electric Plant Steam and Other Production Ash Containment | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 61,885 | [1] | 29,234 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 2,769 | 1,897 | ||
Cash Flow Revisions | 6,113 | [2] | 30,754 | [3] |
Ending balance | 70,767 | [4] | 61,885 | [1] |
Electric Plant Wind Production | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 2,095 | [1] | 2,953 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 18 | 22 | ||
Cash Flow Revisions | (121) | [2] | (880) | [3] |
Ending balance | 1,992 | [4] | 2,095 | [1] |
Electric Plant Electric Distribution | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 1,182 | [1] | 1,176 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 47 | 43 | ||
Cash Flow Revisions | (99) | [2] | (37) | [3] |
Ending balance | 1,130 | [4] | 1,182 | [1] |
Electric Plant Other | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 1,150 | [1] | 1,017 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 46 | 41 | ||
Cash Flow Revisions | (142) | [2] | 92 | [3] |
Ending balance | 1,054 | [4] | 1,150 | [1] |
Natural Gas Plant Gas Transmission and Distribution | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 117,474 | [1] | 788 | |
Liabilities recognized | 0 | 18,252 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 4,694 | 50 | ||
Cash Flow Revisions | 0 | [2] | 98,384 | [3] |
Ending balance | 122,168 | [4] | 117,474 | [1] |
Natural Gas Plant Other | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 3,886 | [1] | 575 | |
Liabilities recognized | 0 | 2,865 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 153 | 24 | ||
Cash Flow Revisions | (114) | [2] | 422 | [3] |
Ending balance | 3,925 | [4] | 3,886 | [1] |
Common and Other Property Common Miscellaneous | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | 768 | [1] | 741 | |
Liabilities recognized | 0 | 0 | ||
Liabilities settled | 0 | 0 | ||
Accretion | 28 | 27 | ||
Cash Flow Revisions | 0 | [2] | 0 | [3] |
Ending balance | $ 796 | [4] | $ 768 | [1] |
[1] | There were no ARO liabilities settled during the year ended Dec. 31, 2014. | |||
[2] | In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above. | |||
[3] | In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution. | |||
[4] | There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015. |
Commitments and Contingencies84
Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Plant Removal Costs | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | $ 364 | $ 366 |
Commitments and Contingencies85
Commitments and Contingencies, Legal Contingencies (Details) - Pacific Northwest FERC Refund Proceeding [Member] | 12 Months Ended |
Dec. 31, 2015USD ($)Factor | |
Legal Contingencies [Abstract] | |
Estimated City of Seattle's claim for refunds not including interest | $ 28,000,000 |
Number of factors considered in assessment | Factor | 2 |
Accrual for legal contingency | $ 0 |
PSCo [Member] | Maximum | |
Legal Contingencies [Abstract] | |
Amount of Sales Claimed as Subject to Refund | 50,000,000 |
PSCo [Member] | Minimum | |
Legal Contingencies [Abstract] | |
Amount of Sales Claimed as Subject to Refund | $ 34,000,000 |
Regulatory Assets and Liabili86
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | $ 92,072 | $ 120,120 | |
Regulatory Asset, Noncurrent | 906,275 | 903,973 | |
Past expenditures not currently earning a return | $ 54,000 | 104,000 | |
Pension and Retiree Medical Obligations | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Various | ||
Regulatory Asset, Current | [1] | $ 29,260 | 32,195 |
Regulatory Asset, Noncurrent | [1] | 497,973 | 500,889 |
Non Qualified Pension Plan | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 400 | 400 | |
Regulatory Asset | $ 4,400 | 4,500 | |
Recoverable Deferred Taxes on AFUDC Recorded in Plant | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Plant lives | ||
Regulatory Asset, Current | $ 0 | 0 | |
Regulatory Asset, Noncurrent | $ 144,953 | 141,214 | |
Contract Valuation Adjustments | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Term of related contract | ||
Regulatory Asset, Current | [2] | $ 9,376 | 8,901 |
Regulatory Asset, Noncurrent | [2] | $ 9,526 | 12,999 |
Depreciation Differences | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | One to sixteen years | ||
Regulatory Asset, Current | $ 14,221 | 10,700 | |
Regulatory Asset, Noncurrent | $ 99,835 | 104,743 | |
Net AROs | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Plant lives | ||
Regulatory Asset, Current | [3] | $ 0 | 0 |
Regulatory Asset, Noncurrent | [3] | $ 62,948 | 46,213 |
Conservation Programs | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | One to five years | ||
Regulatory Asset, Current | [4] | $ 8,466 | 10,198 |
Regulatory Asset, Noncurrent | [4] | $ 6,947 | 10,906 |
Gas Pipeline Inspection Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Less than one year | ||
Regulatory Asset, Current | $ 3,611 | 5,416 | |
Regulatory Asset, Noncurrent | $ 0 | 3,611 | |
Purchased Power Agreements | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Term of related contract | ||
Regulatory Asset, Current | $ 1,319 | 858 | |
Regulatory Asset, Noncurrent | $ 29,143 | 29,596 | |
Losses on Reacquired Debt | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Term of related debt | ||
Regulatory Asset, Current | $ 1,421 | 1,426 | |
Regulatory Asset, Noncurrent | $ 6,957 | 8,378 | |
Recoverable Purchased Natural Gas and Electric Energy Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Less than one year | ||
Regulatory Asset, Current | $ 408 | 18,410 | |
Regulatory Asset, Noncurrent | $ 0 | 0 | |
Property Tax | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | One to six years | ||
Regulatory Asset, Current | $ 21,558 | 28,024 | |
Regulatory Asset, Noncurrent | $ 14,428 | 31,429 | |
Other Regulatory Assets | |||
Regulatory Assets [Line Items] | |||
Regulatory asset, remaining amortization period | Various | ||
Regulatory Asset, Current | $ 2,432 | 3,992 | |
Regulatory Asset, Noncurrent | $ 33,565 | $ 13,995 | |
[1] | Includes $4.4 million and $4.5 million of regulatory assets related to the nonqualified pension plan, of which $0.4 million is included in the current asset at Dec. 31, 2015 and 2014, respectively. | ||
[2] | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | ||
[3] | Includes amounts recorded for future recovery of AROs. | ||
[4] | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Regulatory Assets and Liabili87
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [1] | $ 152,823 | $ 134,459 |
Regulatory Liability, Noncurrent | 471,421 | 464,421 | |
Plant Removal Costs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 0 | 0 | |
Regulatory Liability, Noncurrent | $ 364,291 | 366,359 | |
Regulatory Noncurrent Liability, Amortization Period | Plant lives | ||
Deferred Electric, Gas, and Steam Production Costs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 66,696 | 24,035 | |
Regulatory Liability, Noncurrent | $ 0 | 0 | |
Regulatory Noncurrent Liability, Amortization Period | Less than one year | ||
Investment Tax Credit Deferrals | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 0 | 0 | |
Regulatory Liability, Noncurrent | $ 20,515 | 22,225 | |
Regulatory Noncurrent Liability, Amortization Period | Various | ||
Deferred Income Tax Adjustment | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 0 | 0 | |
Regulatory Liability, Noncurrent | $ 16,891 | 18,672 | |
Regulatory Noncurrent Liability, Amortization Period | Various | ||
Conservation Programs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [2] | $ 33,460 | 32,226 |
Regulatory Liability, Noncurrent | [2] | $ 0 | 0 |
Regulatory Noncurrent Liability, Amortization Period | Less than one year | ||
Renewable Resources and Environmental Initiatives | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 3,311 | 3,308 | |
Regulatory Liability, Noncurrent | $ 40,988 | 10,376 | |
Regulatory Noncurrent Liability, Amortization Period | Various | ||
Low Income Discount Program | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 1,393 | 1,680 | |
Regulatory Liability, Noncurrent | $ 0 | 0 | |
Regulatory Noncurrent Liability, Amortization Period | Less than one year | ||
Gain From Asset Sales | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 0 | 316 | |
Regulatory Liability, Noncurrent | $ 0 | 4 | |
Regulatory Noncurrent Liability, Amortization Period | One to three years | ||
PSCo Earnings Test | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 42,868 | 57,127 | |
Regulatory Liability, Noncurrent | $ 9,472 | 42,819 | |
Regulatory Noncurrent Liability, Amortization Period | One to two years | ||
Gas Pipeline Inspection Costs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 1,140 | 13,970 | |
Regulatory Liability, Noncurrent | $ 4,273 | 642 | |
Regulatory Noncurrent Liability, Amortization Period | One to two years | ||
Other Regulatory Liabilities | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | $ 3,955 | 1,797 | |
Regulatory Liability, Noncurrent | $ 14,991 | 3,324 | |
Regulatory Noncurrent Liability, Amortization Period | Various | ||
Other Current Liabilities [Member] | |||
Regulatory Liabilities [Line Items] | |||
Entity's Recorded Provision for Revenue Subject To Refund | $ 9,100 | $ 4,400 | |
[1] | Revenue subject to refund of $9.1 million and $4.4 million for 2015 and 2014, respectively, is included in other current liabilities. | ||
[2] | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | $ (23,878) | |||
Accumulated other comprehensive income (loss) at end of period | (23,836) | $ (23,878) | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||||
Operating and maintenance expenses | 761,901 | 751,786 | $ 762,322 | |
Total, pre-tax | (745,242) | (698,779) | (704,123) | |
Income tax expense (benefit) | 278,440 | 243,591 | 250,740 | |
Gains and Losses on Cash Flow Hedges | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Accumulated other comprehensive income (loss) at beginning of period | (23,878) | (23,338) | ||
Other comprehensive income (loss) before reclassifications | (30) | (72) | ||
(Gains) losses reclassified from net accumulated other comprehensive loss | 72 | (468) | ||
Net current period other comprehensive income (loss) | 42 | (540) | ||
Accumulated other comprehensive income (loss) at end of period | (23,836) | (23,878) | $ (23,338) | |
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 | 111 | (755) | ||
Income tax expense (benefit) | (39) | 287 | ||
Total, net of tax | 72 | (468) | ||
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] | 54 | (730) | |
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] | $ 57 | $ (25) | |
[1] | Included in interest charges. | |||
[2] | Included in O&M expenses |
Segments and Related Informat89
Segments and Related Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Segment Reporting Information [Line Items] | ||||||||||||
Intercompany Revenue | $ 13,000 | $ 14,000 | $ 13,000 | |||||||||
Operating revenues | $ 1,030,838 | $ 1,044,704 | $ 952,521 | $ 1,135,450 | $ 1,136,791 | $ 1,049,111 | $ 993,704 | $ 1,203,543 | 4,163,513 | 4,383,149 | 4,202,628 | |
Depreciation and amortization | 411,667 | 379,202 | 360,417 | |||||||||
Total interest charges and financing costs | 171,908 | 154,640 | 160,945 | |||||||||
Income tax expense (benefit) | 278,440 | 243,591 | 250,740 | |||||||||
Net income (loss) | $ 84,255 | $ 173,081 | $ 98,500 | $ 110,966 | $ 92,834 | $ 154,159 | $ 89,792 | $ 118,403 | 466,802 | 455,188 | 453,383 | |
Regulated Electric | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 3,115,558 | 3,126,276 | 3,081,473 | |||||||||
Depreciation and amortization | 311,122 | 285,968 | 280,972 | |||||||||
Total interest charges and financing costs | 136,397 | 124,118 | 129,787 | |||||||||
Income tax expense (benefit) | 234,873 | 208,095 | 220,356 | |||||||||
Net income (loss) | 391,257 | 349,793 | 368,586 | |||||||||
Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 1,006,733 | 1,215,504 | 1,080,813 | |||||||||
Depreciation and amortization | 96,384 | 89,186 | 75,510 | |||||||||
Total interest charges and financing costs | 34,935 | 29,987 | 30,604 | |||||||||
Income tax expense (benefit) | 44,192 | 50,874 | 42,294 | |||||||||
Net income (loss) | 74,267 | 84,324 | 69,682 | |||||||||
All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 41,590 | 41,888 | 40,754 | |||||||||
Depreciation and amortization | 4,161 | 4,048 | 3,935 | |||||||||
Total interest charges and financing costs | 576 | 535 | 554 | |||||||||
Income tax expense (benefit) | (625) | (15,378) | (11,910) | |||||||||
Net income (loss) | 1,278 | 21,071 | 15,115 | |||||||||
Operating Segments | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 4,163,513 | 4,383,149 | 4,202,628 | ||||||||
Operating Segments | Regulated Electric | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 3,115,257 | 3,125,937 | 3,081,171 | ||||||||
Operating Segments | Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 1,006,666 | 1,215,324 | 1,080,703 | ||||||||
Operating Segments | All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | [1] | 41,590 | 41,888 | 40,754 | ||||||||
Intersegment Eliminations | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | (368) | (519) | (412) | |||||||||
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 | 301 | 339 | 302 | |||||||||
Intersegment Eliminations | Regulated Natural Gas | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | 67 | 180 | 110 | |||||||||
Intersegment Eliminations | All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenues | $ 0 | $ 0 | $ 0 | |||||||||
[1] | Operating revenues include $13 million, $14 million and $13 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013, respectively. See Note 16 for further discussion of related party transactions by reportable segment. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues | |||
Electric | $ 8,632 | $ 9,614 | $ 8,136 |
Other | 4,441 | 4,441 | 4,441 |
Operating expenses | |||
Purchased power | 0 | 23 | 1,331 |
Other operating expenses - paid to Xcel Energy Services Inc. | 414,620 | 454,250 | 375,766 |
Interest expense | 211 | 158 | 132 |
Interest income | 45 | 61 | $ 273 |
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 4,909 | 50,842 | |
Accounts payable | 76,643 | 46,736 | |
NSP-Minnesota | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 4,419 | 0 | |
Accounts payable | 0 | 6,706 | |
NSP-Wisconsin | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 71 | 22 | |
Accounts payable | 0 | 0 | |
SPS | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 414 | 5,803 | |
Accounts payable | 0 | 0 | |
Other subsidiaries of Xcel Energy Inc. | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 5 | 45,017 | |
Accounts payable | $ 76,643 | $ 40,030 |
Summarized Quarterly Financia91
Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 1,030,838 | $ 1,044,704 | $ 952,521 | $ 1,135,450 | $ 1,136,791 | $ 1,049,111 | $ 993,704 | $ 1,203,543 | $ 4,163,513 | $ 4,383,149 | $ 4,202,628 |
Operating income | 173,951 | 315,174 | 195,176 | 215,400 | 169,423 | 261,073 | 163,437 | 208,437 | 899,701 | 802,370 | 828,759 |
Net income | $ 84,255 | $ 173,081 | $ 98,500 | $ 110,966 | $ 92,834 | $ 154,159 | $ 89,792 | $ 118,403 | $ 466,802 | $ 455,188 | $ 453,383 |
Schedule II, Valuation and Qu92
Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Jan. 1 | $ 23,122 | $ 22,505 | $ 21,918 | |
Charged to costs and expenses | 13,052 | 17,005 | 16,784 | |
Charged to other accounts | [1] | 5,175 | 6,240 | 7,005 |
Deductions from reserves | [2] | 21,227 | 22,628 | 23,202 |
Balance at Dec. 31 | $ 20,122 | $ 23,122 | $ 22,505 | |
[1] | Recovery of amounts previously written off. | |||
[2] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjZhOWU0NmJhMjIzYzQ0MGM4MGI3NmY1MTljZjA5MDRlfFRleHRTZWxlY3Rpb246NkJENUMzQ0M4MzlGQTU3MTUyOUJGNzlEN0IxM0IzRTEM} |