10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-3280

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

Colorado	84-0296600
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1800 Larimer, Suite 1100
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(Do not check if smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at Aug. 4, 2014
Common Stock, $0.01 par value	100 shares

Public Service Company of Colorado meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 4 —	Controls and Procedures	27
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	28
Item 1A —	Risk Factors	28
Item 4 —	Mine Safety Disclosures	28
Item 5 —	Other Information	28
Item 6 —	Exhibits	28
SIGNATURES		29
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Public Service Company of Colorado, a Colorado corporation (PSCo). PSCo is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); PSCo; and Southwestern Public Service Company, a New Mexico corporation (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

2

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2014			2013			2014			2013
Operating revenues
Electric	$	761,569		$	747,882		$	1,495,833		$	1,469,230
Natural gas	223,187			209,296			679,524			593,220
Steam and other	8,948			9,251			21,890			21,436
Total operating revenues	993,704			966,429			2,197,247			2,083,886
Operating expenses
Electric fuel and purchased power	349,070			322,787			683,540			642,668
Cost of natural gas sold and transported	117,281			109,697			427,086			359,317
Cost of sales — steam and other	3,435			4,008			8,413			8,813
Operating and maintenance expenses	188,901			188,152			364,425			361,193
Demand side management program expenses	34,678			32,938			69,873			66,059
Depreciation and amortization	95,115			89,079			188,431			178,629
Taxes (other than income taxes)	41,787			36,093			83,605			71,233
Total operating expenses	830,267			782,754			1,825,373			1,687,912
Operating income	163,437			183,675			371,874			395,974
Other income, net	912			1,322			1,709			2,899
Allowance for funds used during construction — equity	12,952			6,791			24,382			12,714
Interest charges and financing costs
Interest charges — includes other financing costs of $1,532, $1,723,     $3,252, and $3,371, respectively	42,429			43,231			86,401			84,619
Allowance for funds used during construction — debt	(4,812		)	(3,100		)	(9,020		)	(5,251		)
Total interest charges and financing costs	37,617			40,131			77,381			79,368
Income before income taxes	139,684			151,657			320,584			332,219
Income taxes	49,892			54,358			112,389			118,315
Net income	$	89,792		$	97,299		$	208,195		$	213,904

See Notes to Consolidated Financial Statements

3

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2014			2013			2014			2013
Net income	$	89,792		$	97,299		$	208,195		$	213,904
Other comprehensive loss
Derivative instruments:
Net fair value increase (decrease), net of tax of $3, $(11), $1, and $(7), respectively	5			(20		)	2			(13		)
Reclassification of gains to net income, net of tax of $(72), $(71), $(145), and $(145), respectively	(117		)	(118		)	(237		)	(236		)
Other comprehensive loss	(112		)	(138		)	(235		)	(249		)
Comprehensive income	$	89,680		$	97,161		$	207,960		$	213,655

See Notes to Consolidated Financial Statements

4

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2014			2013
Operating activities
Net income	$	208,195		$	213,904
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	190,911			181,222
Demand side management program amortization	2,288			2,514
Deferred income taxes	65,725			127,490
Amortization of investment tax credits	(1,468		)	(1,479		)
Allowance for equity funds used during construction	(24,382		)	(12,714		)
Net realized and unrealized hedging and derivative transactions	(2,892		)	(5,094		)
Changes in operating assets and liabilities:
Accounts receivable	20,170			83,949
Accrued unbilled revenues	53,838			56,802
Inventories	31,490			32,123
Prepayments and other	4,636			(8,183		)
Accounts payable	(83,451		)	(16,087		)
Net regulatory assets and liabilities	51,798			64,131
Other current liabilities	(69,978		)	(63,653		)
Pension and other employee benefit obligations	(36,769		)	(44,007		)
Change in other noncurrent assets	5,811			479
Change in other noncurrent liabilities	(7,313		)	2,860
Net cash provided by operating activities	408,609			614,257
Investing activities
Utility capital/construction expenditures	(573,401		)	(497,626		)
Allowance for equity funds used during construction	24,382			12,714
Investments in utility money pool arrangement	(567,000		)	(617,000		)
Repayments from utility money pool arrangement	639,000			531,000
Net cash used in investing activities	(477,019		)	(570,912		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	256,800			(154,000		)
Borrowings under utility money pool arrangement	129,000			14,000
Repayments under utility money pool arrangement	(129,000		)	(14,000		)
Proceeds from issuance of long-term debt	295,642			492,383
Repayments of long-term debt	(275,000		)	(250,000		)
Capital contributions from parent	35,486			460
Dividends paid to parent	(259,156		)	(133,481		)
Net cash provided by (used in) financing activities	53,772			(44,638		)
Net change in cash and cash equivalents	(14,638		)	(1,293		)
Cash and cash equivalents at beginning of period	21,089			5,150
Cash and cash equivalents at end of period	$	6,451		$	3,857
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(74,848	)	$	(76,228	)
Cash paid for income taxes, net	(39,649		)	(14,922		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	104,927		$	73,152

See Notes to Consolidated Financial Statements

5

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	June 30, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	6,451		$	21,089
Accounts receivable, net	270,395			328,675
Accounts receivable from affiliates	57,246			19,136
Investments in utility money pool arrangement	—			72,000
Accrued unbilled revenues	217,079			270,917
Inventories	206,517			238,007
Regulatory assets	158,129			150,163
Deferred income taxes	75,389			87,267
Derivative instruments	5,448			6,576
Prepayments and other	27,993			32,629
Total current assets	1,024,647			1,226,459
Property, plant and equipment, net	11,125,478			10,742,397
Other assets
Regulatory assets	833,950			826,037
Derivative instruments	6,049			6,905
Other	48,813			52,520
Total other assets	888,812			885,462
Total assets	$	13,038,937		$	12,854,318
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	7,631		$	282,143
Short-term debt	256,800			—
Accounts payable	345,356			451,243
Accounts payable to affiliates	31,162			45,902
Regulatory liabilities	125,380			79,499
Taxes accrued	85,180			154,194
Accrued interest	48,617			48,492
Dividends payable to parent	96,391			65,134
Derivative instruments	5,270			6,734
Other	71,492			89,571
Total current liabilities	1,073,279			1,222,912
Deferred credits and other liabilities
Deferred income taxes	2,274,042			2,206,179
Deferred investment tax credits	37,761			39,230
Regulatory liabilities	453,273			424,690
Asset retirement obligations	97,862			60,398
Derivative instruments	20,798			23,366
Customer advances	243,103			251,062
Pension and employee benefit obligations	130,358			167,127
Other	67,490			66,855
Total deferred credits and other liabilities	3,324,687			3,238,907
Commitments and contingencies
Capitalization
Long-term debt	3,885,939			3,590,500
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	—			—
Additional paid in capital	3,476,776			3,441,290
Retained earnings	1,301,829			1,384,047
Accumulated other comprehensive loss	(23,573		)	(23,338		)
Total common stockholder’s equity	4,755,032			4,801,999
Total liabilities and equity	$	13,038,937		$	12,854,318

See Notes to Consolidated Financial Statements

6

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of June 30, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013, filed with the SEC on Feb. 24, 2014. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	291,856		$	351,180
Less allowance for bad debts	(21,461		)	(22,505		)
	$	270,395		$	328,675

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	53,452	$	53,127
Fuel	82,680		86,062
Natural gas	70,385		98,818
	$	206,517	$	238,007

7

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,356,644		$	10,177,056
Natural gas plant	2,866,667			2,757,605
Common and other property	751,236			762,916
Plant to be retired (a)	85,808			101,279
Construction work in progress	1,191,676			952,469
Total property, plant and equipment	15,252,031			14,751,325
Less accumulated depreciation	(4,126,553		)	(4,008,928		)
	$	11,125,478		$	10,742,397

^(a)  As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. PSCo is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2014, 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 effective tax rate (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)	June 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.3	$	2.5
Unrecognized tax benefit — Temporary tax positions	7.8		5.9
Total unrecognized tax benefit	$	9.1	$	8.4

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(4.6	)	$	(7.0	)

8

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 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 June 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2014 Electric Rate Case —In June 2014, PSCo filed an electric rate case in Colorado with the CPUC requesting an increase in annual revenue of approximately $137.7 million, or 4.89 percent. The request includes the initiation of a CACJA rider as part of the overall 2015 rate case request of approximately $95 million, as well as additional amounts for calendar years 2016 and 2017. The CACJA rider is anticipated to increase revenue recovery by approximately $40 million in 2016 and then decline to approximately $36 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers.

The rate filing is based on a 2015 test year, a requested return on equity (ROE) of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates. This transfer will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017.

In July 2014, the CPUC set hearings for early December 2014. A decision as well as implementation of final rates are anticipated in the first quarter of 2015.

Manufacturer’s Sales Tax Refund —Pursuant to the multi-year settlement agreement with the CPUC, PSCo defers 2012-2014 annual property taxes in excess of $76.7 million. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014. 

After PSCo’s initial successes in the District Court and Court of Appeals, the Colorado Supreme Court on June 30, 2014 ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001. Under the multi-year settlement agreement, as a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates.  This impact is reflected in PSCo’s pending electric rate case before the CPUC.

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 to be effective Aug. 1, 2014. As of June 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test.

9

2012 Pipeline System Integrity Adjustment (PSIA) Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. In February 2014, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of operating and maintenance (O&M) expenditures and an agreement not to disallow capital expenditures related to a pipeline replacement project. In July 2014, the Administrative Law Judge (ALJ) issued a final decision approving the settlement agreement.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended June 30, 2014. For the three months ended June 30, 2013, PSCo credited the RESA regulatory asset balance $6.5 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at June 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

The current sharing mechanism will be effective through 2014. In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an ALJ. A decision is anticipated later in 2014.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a confidential settlement in principle to resolve the complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing.

In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues.

10

In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. In June 2014, PSCo and its transmission customers reached a confidential settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, PSCo purchases power from independent power producing entities that own natural gas fueled power plants 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 had approximately 1,802 megawatts (MW) and 1,441 MW of capacity under long-term PPAs as of June 30, 2014 and Dec. 31, 2013, respectively, with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through 2032.

Environmental Contingencies

Environmental Requirements

Water and waste

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (EPA) published a proposed 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. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. At June 30, 2014, the estimated cost of compliance for PSCo did not have a material impact on the results of operations, financial position or cash flows.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

11

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. PSCo is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at PSCo’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in Colorado. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at PSCo’s power plants.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (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 state implementation plan (SIP), Colorado identified the PSCo facilities that will have to reduce sulfur dioxide, nitrous oxide and particulate matter 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 the facilities included in 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 the Hayden and Pawnee plants are projected to cost $359.7 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

12

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction be added to the units. PSCo intervened in the case. The 10^th Circuit is anticipated to hear argument in January 2015, following completion of the briefs in November 2014.

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the Clean Air Act mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

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 — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit Court of Appeals (Ninth Circuit).

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

13

A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle may contest the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC.

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, not withstanding 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 FERC’s standard has been challenged on appeal to 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 potentially responsible parties. No accrual has been recorded for this matter.

7. 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 June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	6			0.1
Maximum amount outstanding	70			12
Weighted average interest rate, computed on a daily basis	0.24		%	0.36		%
Weighted average interest rate at period end	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 outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700
Amount outstanding at period end	257			—
Average amount outstanding	127			38
Maximum amount outstanding	261			332
Weighted average interest rate, computed on a daily basis	0.24		%	0.34		%
Weighted average interest rate at period end	0.29			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 June 30, 2014 and Dec. 31, 2013, there were $6.5 million and $6.4 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.

14

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.

At June 30, 2014, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	263.3	$	436.7

^(a)  Credit facility expires in July 2017.

^(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 June 30, 2014 and Dec. 31, 2013.

Long-Term Borrowings

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044.

8. 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.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. 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.

15

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 June 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

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 June 30, 2014, 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 other comprehensive income 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 three and six months ended June 30, 2014 and 2013.

At June 30, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains 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 June 30, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Megawatt hours of electricity	—	326
Million British thermal units of natural gas	6,791	6,398
Gallons of vehicle fuel	172	217

^(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.

16

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2014
	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 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	$	—	$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	8		—			(7		)	(b)	—		—
Total	$	8	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,916	)	$	—			$	—	$	(65	)	(c)
Total	$	—	$	(1,916	)	$	—			$	—	$	(65	)

	Six Months Ended June 30, 2014
	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 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	$	—	$	—	$	(362	)	(a)	$	—			$	—
Vehicle fuel and other commodity	3		—		(20		)	(b)	—				—
Total	$	3	$	—	$	(382	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—	$	7,910	$	—			$	(8,579	)	(d)	$	(4,381	)	(d)
Total	$	—	$	7,910	$	—			$	(8,579	)		$	(4,381	)

	Three Months Ended June 30, 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 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	$	—		$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	(31		)	—			(7		)	(b)	—		—
Total	$	(31	)	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,211	)	$	—			$	—	$	(244	)	(c)
Total	$	—		$	(3,211	)	$	—			$	—	$	(244	)

17

	Six Months Ended June 30, 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 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	$	—		$	—		$	(362	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(20		)	—			(19		)	(b)	—			—
Total	$	(20	)	$	—		$	(381	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,169	)	$	—			$	7	(d)	$	(228	)	(c)
Total	$	—		$	(3,169	)	$	—			$	7		$	(228	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

^(c)  Amounts are recorded to electric fuel and purchased power.

^(d)  Amounts for the six months ended June 30, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the six months ended June 30, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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 June 30, 2014, five of PSCo’s 10 most significant counterparties, comprising $28.0 million or 38 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining five significant counterparties, comprising $25.5 million or 34 percent of this credit exposure, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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 June 30, 2014, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of PSCo were downgraded below investment grade. If the credit ratings of PSCo were downgraded below investment grade at Dec. 31, 2013, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million. At June 30, 2014 and Dec. 31, 2013, there was no collateral posted on these specific contracts.

18

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 June 30, 2014 and Dec. 31, 2013.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at June 30, 2014:

	June 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	27	$	—	$	27	$	—		$	27
Other derivative instruments:
Natural gas commodity	—		3,715		—		3,715		(9		)	3,706
Total current derivative assets	$	—	$	3,742	$	—	$	3,742	$	(9	)	3,733
PPAs (a)												1,715
Current derivative instruments												$	5,448
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	15	$	—	$	15	$	—		$	15
Total noncurrent derivative assets	$	—	$	15	$	—	$	15	$	—		15
PPAs (a)												6,034
Noncurrent derivative instruments												$	6,049
Current derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	63	$	—	$	63	$	(9	)	$	54
Total current derivative liabilities	$	—	$	63	$	—	$	63	$	(9	)	54
PPAs (a)												5,216
Current derivative instruments												$	5,270
Noncurrent derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	27	$	—	$	27	$	—		$	27
Total noncurrent derivative liabilities	$	—	$	27	$	—	$	27	$	—		27
PPAs (a)												20,771
Noncurrent derivative instruments												$	20,798

^(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 onthis 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 June 30, 2014. At June 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and no 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.

19

The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												$	23,366
Noncurrent derivative instruments												$	23,366

^(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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no 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 three and six months ended June 30, 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 three and six months ended June 30, 2014 and 2013.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,893,570	$	4,216,091	$	3,872,643	$	4,059,661

20

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 June 30, 2014 and Dec. 31, 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	157		$	843		$	646		$	1,757
Other nonoperating income	1,200			637			1,875			1,519
Insurance policy expense	(445		)	(158		)	(812		)	(377		)
Other income, net	$	912		$	1,322		$	1,709		$	2,899

10. Segment 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, transmits and distributes electricity primarily in portions of 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 commodity trading operations.

• PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas primarily 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.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)(b)	$	761,569	$	223,187	$	8,948	$	—		$	993,704
Intersegment revenues	62		49		—		(111		)	—
Total revenues	$	761,631	$	223,236	$	8,948	$	(111	)	$	993,704
Net income	$	75,741	$	10,846	$	3,205	$	—		$	89,792

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)(b)	$	747,882	$	209,296	$	9,251	$	—		$	966,429
Intersegment revenues	61		25		—		(86		)	—
Total revenues	$	747,943	$	209,321	$	9,251	$	(86	)	$	966,429
Net income	$	85,603	$	8,786	$	2,910	$	—		$	97,299

^(a)    Operating revenues include $3 million and $2 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2014 and 2013.

21

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)(b)	$	1,495,833	$	679,524	$	21,890	$	—		$	2,197,247
Intersegment revenues	159		108		—		(267		)	—
Total revenues	$	1,495,992	$	679,632	$	21,890	$	(267	)	$	2,197,247
Net income	$	149,709	$	48,995	$	9,491	$	—		$	208,195

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)(b)	$	1,469,230	$	593,220	$	21,436	$	—		$	2,083,886
Intersegment revenues	149		72		—		(221		)	—
Total revenues	$	1,469,379	$	593,292	$	21,436	$	(221	)	$	2,083,886
Net income	$	164,071	$	42,585	$	7,248	$	—		$	213,904

^(a)    Operating revenues include $5 million and $4 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2014 and 2013.

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,985		$	6,301		$	478		$	803
Interest cost	13,319			11,540			5,926			5,934
Expected return on plan assets	(17,677		)	(15,955		)	(7,553		)	(7,307		)
Amortization of transition obligation	—			—			—			196
Amortization of prior service credit	(773		)	(266		)	(1,561		)	(1,229		)
Amortization of net loss	8,473			10,854			1,608			3,489
Net benefit cost (credit) recognized for financial reporting	$	9,327		$	12,474		$	(1,102	)	$	1,886

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	11,970		$	12,603		$	957		$	1,606
Interest cost	26,638			23,080			11,852			11,868
Expected return on plan assets	(35,354		)	(31,910		)	(15,107		)	(14,614		)
Amortization of transition obligation	—			—			—			392
Amortization of prior service credit	(1,546		)	(532		)	(3,123		)	(2,458		)
Amortization of net loss	16,946			21,708			3,217			6,979
Net benefit cost (credit) recognized for financial reporting	$	18,654		$	24,949		$	(2,204	)	$	3,773

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $35.1 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2014.

12. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(23,461	)	$	(22,982	)
Other comprehensive gain (loss) before reclassifications	5			(20		)
Gains reclassified from net accumulated other comprehensive loss	(117		)	(118		)
Net current period other comprehensive loss	(112		)	(138		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive gain (loss) before reclassifications	2			(13		)
Gains reclassified from net accumulated other comprehensive loss	(237		)	(236		)
Net current period other comprehensive loss	(235		)	(249		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(182	)	(a)	$	(182	)	(a)
Vehicle fuel derivatives	(7		)	(b)	(7		)	(b)
Total, pre-tax	(189		)		(189		)
Tax expense	72				71
Total amounts reclassified, net of tax	$	(117	)		$	(118	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(362	)	(a)	$	(362	)	(a)
Vehicle fuel derivatives	(20		)	(b)	(19		)	(b)
Total, pre-tax	(382		)		(381		)
Tax expense	145				145
Total amounts reclassified, net of tax	$	(237	)		$	(236	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

22

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of slow down in the U.S. economy or delay in growth recovery; actions of credit rating agencies; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

Results of Operations

PSCo’s net income was approximately $208.2 million for the six months ended June 30, 2014, compared with approximately $213.9 million for the same period in 2013. Higher electric and natural gas rates and weather-normalized sales growth (which is adjusted against a 30-year average of actual historical weather conditions) were offset by increased property taxes, depreciation, accruals associated with electric earnings test refund obligations as well as the impact of weather. See Note 5 to the consolidated financial statements for further discussion of rate matters.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Electric revenues	$	1,496		$	1,469
Electric fuel and purchased power	(684		)	(643		)
Electric margin	$	812		$	826

23

The following tables summarize the components of the changes in electric revenues and electric margin for the six months ended June 30:

Electric Revenues

(Millions of Dollars)	2014 vs. 2013
Fuel and purchased power cost recovery	$	45
Retail rate increases	12
Retail sales growth, excluding weather impact	7
Demand side management (DSM) program revenues (offset by expenses)	5
PSCo earnings test refund obligations	(20		)
Estimated impact of weather	(14		)
Trading, including REC sales	(6		)
Other, net	(2		)
Total increase in electric revenues	$	27

Electric Margin

(Millions of Dollars)	2014 vs. 2013
PSCo earnings test refund obligations	$	(20	)
Estimated impact of weather	(14		)
DSM program incentives	(3		)
Retail rate increases	12
Retail sales growth, excluding weather impact	7
DSM program revenues	5
Other, net	(1		)
Total decrease in electric margin	$	(14	)

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Natural gas revenues	$	680		$	593
Cost of natural gas sold and transported	(427		)	(359		)
Natural gas margin	$	253		$	234

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the six months ended June 30:

Natural Gas Revenues

(Millions of Dollars)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	69
Retail rate increase, net of refund	16
PSIA rider	4
Retail sales growth	4
Estimated impact of weather	(6		)
Total increase in natural gas revenues	$	87

24

Natural Gas Margin

(Millions of Dollars)	2014 vs. 2013
Retail rate increase, net of refund	$	16
PSIA rider, partially offset in O&M expenses	4
Retail sales growth	4
Estimated impact of weather	(6		)
Other, net	1
Total increase in natural gas margin	$	19

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased $3.2 million, or 0.9 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2014 vs. 2013
Electric and gas distribution expenses	$	8
Transmission costs	2
Plant generation costs	1
Employee benefits	(9		)
Other, net	1
Total increase in O&M expenses	$	3

• Electric and gas distribution expenses were primarily driven by increased maintenance activities due to vegetation management and repairs and amounts related to pipeline system integrity; and

• Lower employee benefit costs are mainly due to decreased pension expense.

DSM Program Expenses— DSM program expenses increased $3.8 million, or 5.8 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The higher expense is primarily attributable to an increase in the electric rate used to recover program expenses. DSM program expenses are recovered from customers and expensed on a kilowatt hour basis. As such, increased sales due to cold winter temperatures or hot summer temperatures will increase revenues and expenses.

Depreciation and Amortization— Depreciation and amortization expense increased $9.8 million, or 5.5 percent, for the six months ended June 30, 2014 compared with the same period for 2013. The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes)— Taxes (other than income taxes) increased $12.4 million, or 17.4 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to higher property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)— AFUDC increased $15.4 million for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to construction related to the CACJA project.

Interest Charges —Interest charges increased $1.8 million, or 2.1 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $5.9 million for the six months ended June 30, 2014 compared with the same period in 2013. The decrease in income tax expense was primarily due to lower pre-tax earnings in 2014 and increased permanent plant-related adjustments in 2014. The ETR was 35.1 percent for the six months ended June 30, 2014 compared with 35.6 percent for the same period in 2013. The lower ETR was primarily due to the same adjustments mentioned above.

Public Utility Regulation

Brush, Colo. to Castle Pines, Colo. 345 Kilovolt (KV) Transmission Line — In March 2014, PSCo filed with the CPUC for a certificate of public convenience and necessity (CPCN) to construct a new 345 KV transmission line originating from Pawnee Station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. The estimated cost of the project is $178 million. Evidentiary hearings are scheduled for September 2014. A CPUC decision is expected in early 2015.

25

Renewable Energy Standard (RES) Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard. In July 2013, PSCo filed its 2014 RES compliance plan that included the continuation of both the Solar*Rewards and Solar*Rewards Community programs. Hearings for the 2014 RES compliance plan were held in May 2014. A decision is anticipated in the third quarter of 2014.

Net Metering Standard — In conjunction with its 2014 RES compliance plan filing, PSCo proposed to track and quantify the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive,” for purposes of equitably recovering costs between customers who participate in distributed generation and customers that do not. In December 2013, parties including the OCC filed answer testimony supporting PSCo’s net metering proposal. However, rooftop solar advocates opposed it and also argued for higher solar installation levels and a slower reduction in incentives over time. The CPUC has assigned the net metering issue to its own docket and established key dates to evaluate this matter. A CPUC decision is expected in the fourth quarter of 2014.

Solar*Connect Program — In April 2014, PSCo filed an application with the CPUC seeking approval for a program that would allow customers the option to purchase a portion or all of their electricity from a utility scale solar facility approximately 50 MW in size. Customer contracts under the program would run a minimum of one year. Hearings have been set for November 2014.

Boulder, Colo. Municipalization — PSCo’s franchise agreement with the City of Boulder (Boulder) expired on Dec. 31, 2010. In November 2011, a ballot measure was passed by the citizens of Boulder, which authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.

In May 2014, the Boulder City Council passed an ordinance to establish an electric utility. In June 2014, PSCo filed a complaint in the Boulder District Court seeking a declaratory ruling that this ordinance violates Boulder’s charter requirements. Subsequently, Boulder filed a motion to dismiss PSCo’s complaint, which is still pending.

Boulder sent PSCo its final offer of $128 million for certain portions of PSCo’s transmission and distribution business, which includes Boulder and certain areas outside city limits. PSCo has notified Boulder that its offer has deficiencies related to property descriptions as well as other relevant information impacting the remainder of PSCo’s system. Under Colorado law, a condemning entity must pay the owner fair market value for the taking of and damages to the remainder of the property. In July 2014, Boulder filed a petition for condemnation in the Boulder District Court.

The CPUC has previously ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine certain system separation matters as well as what facilities need to be constructed to ensure reliable service. The CPUC has declared that it should make its determinations prior to any eminent domain actions. In January 2014, Boulder appealed this ruling to the Boulder District Court. PSCo and the CPUC filed briefs in June 2014 in opposition of Boulder’s appeal. This matter is currently pending.

If Boulder were to succeed in the eminent domain proceeding, PSCo would seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

26

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area.

In Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. PSCo made its initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Various parties appealed Order 1000 final rules to the D.C. Circuit. The date for a Court decision in the appeal is uncertain. The FERC ruled on the initial regional compliance filings for PSCo, directing further compliance changes and thus the PSCo regional compliance filings remain pending action by the FERC. Initial filings to address interregional planning and cost allocation requirements with other regions were made by PSCo and are pending action by the FERC.

Colorado does not have legislation protecting ROFR rights for incumbent utilities. PSCo submitted its FERC compliance filing proposing that PSCo would join the WestConnect region, a consortium of utilities in the Western Interconnection and the FERC issued its initial order. In April 2013, PSCo and other WestConnect members requested rehearing. PSCo and other WestConnect jurisdictional utilities made their compliance filings to address directives in the March 2013 order. The FERC is expected to rule in 2014 on the compliance filing and the requests for rehearing. PSCo and other WestConnect members filed the interregional compliance filings in May 2013 and action on those filings is pending. The WestConnect members proposed that the regional and inter-regional compliance tariffs be effective prospectively after the final FERC orders, and not earlier than Jan. 1, 2015.

NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. PSCo is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In July 2014, the FERC issued a notice of proposed rulemaking (NOPR) generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. The new standard would likely be effective in 2015. PSCo is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

Wind Integration Tariff Filing—In May 2014, PSCo filed proposed amendments to its Open Access Transmission Tariff with FERC designed to better allocate ancillary services costs associated with renewable generation to those customers on the PSCo system that use renewable resources to serve load. The proposed amendments include changes to the mechanism used to recover the cost of capacity associated with balancing of loads and resources and a new charge designed to recover the cost of additional capacity needed to respond to situations where the output of wind generators decreases significantly over a short period of time. PSCo proposed an effective date of Aug. 1, 2014 with rates suspended until Jan. 1, 2015. The FERC is required to take action on the filing within 60 days. The proposed tariff changes would not materially affect 2014 revenues, but would provide more appropriate cost allocation as additional renewable generation is connected to PSCo.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2014, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

27

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

PSCo’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2013, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

Item 6 — EXHIBITS

* Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*	By-Laws of PSCo as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03280)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Consolidated Financial Statements, and (vi) document and entity information.

28

SIGNATURES

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

		Public Service Company of Colorado
Aug. 4, 2014	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

29

EX-31.01

Exhibit 31.01

CERTIFICATION

I, David L. Eves, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Colorado;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Aug. 4, 2014

/s/ DAVID L. EVES

David L. Eves

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Colorado;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Aug. 4, 2014

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Public Service Company of Colorado (PSCo) on Form 10-Q for the quarter ended June 30, 2014, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-Q.

Date: Aug. 4, 2014

/s/ DAVID L. EVES

David L. Eves

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to PSCo and will be retained by PSCo and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

Public Service Company of Colorado Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of PSCo.  These statements are based on management’s beliefs as well as assumptions and information currently available to management. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause PSCo’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where PSCo has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, PSCo, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by PSCo, Xcel Energy Inc. or any of its other subsidiaries;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of   compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in PSCo’s SEC filings, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2013, or in other publicly disseminated written documents.

PSCo undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 6.5	$ 6.4

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 3,893,570	$ 3,872,643
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,216,091	$ 4,059,661

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 200,000
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,448,000		6,576,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,049,000		6,905,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	5,270,000		6,734,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	20,798,000		23,366,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,733,000		4,861,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	27,000		40,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			1,480,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,706,000		3,341,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	54,000		1,399,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			1,399,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	54,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | 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
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,742,000		6,137,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	27,000		40,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			2,756,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,715,000		3,341,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	63,000		2,438,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			2,438,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	63,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
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 | 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 | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | 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
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,742,000		6,137,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	27,000		40,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			2,756,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,715,000		3,341,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,000		13,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	63,000		2,438,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			2,438,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	63,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,000
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(9,000)	[1]	(1,276,000)	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			(1,276,000)	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(9,000)	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(9,000)	[1]	(1,039,000)	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			(1,039,000)	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(9,000)	[1]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	[1]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,715,000	[3]	1,715,000	[3]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,034,000	[3]	6,892,000	[3]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	5,216,000	[3]	5,335,000	[3]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 20,771,000	[3]	$ 23,366,000	[3]

[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 June 30, 2014. At June 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and no 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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no 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.

XML

Income Taxes (Details) (USD $)			3 Months Ended	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2012 Internal Revenue Service (IRS)	Jun. 30, 2014 Internal Revenue Service (IRS)	Jun. 30, 2014 State Jurisdiction (Colorado)
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired				2008
Earliest year subject to examination				2009	2009
Year(s) under examination			2010 and 2011
Potential Tax Adjustments				$ 10,000,000
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	1,300,000	2,500,000
Unrecognized tax benefit — Temporary tax positions	7,800,000	5,900,000
Total unrecognized tax benefit	9,100,000	8,400,000
NOL and tax credit carryforwards	(4,600,000)	(7,000,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	(1,000,000)
Amounts accrued for penalties related to unrecognized tax benefits	$ 0	$ 0

XML

Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2014

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 June 30, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Megawatt hours of electricity	—	326
Million British thermal units of natural gas	6,791	6,398
Gallons of vehicle fuel	172	217

^(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.

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 three and six months ended June 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2014
	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 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	$	—	$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	8		—			(7		)	(b)	—		—
Total	$	8	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,916	)	$	—			$	—	$	(65	)	(c)
Total	$	—	$	(1,916	)	$	—			$	—	$	(65	)

	Six Months Ended June 30, 2014
	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 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	$	—	$	—	$	(362	)	(a)	$	—			$	—
Vehicle fuel and other commodity	3		—		(20		)	(b)	—				—
Total	$	3	$	—	$	(382	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—	$	7,910	$	—			$	(8,579	)	(d)	$	(4,381	)	(d)
Total	$	—	$	7,910	$	—			$	(8,579	)		$	(4,381	)

	Three Months Ended June 30, 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 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	$	—		$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	(31		)	—			(7		)	(b)	—		—
Total	$	(31	)	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,211	)	$	—			$	—	$	(244	)	(c)
Total	$	—		$	(3,211	)	$	—			$	—	$	(244	)

	Six Months Ended June 30, 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 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	$	—		$	—		$	(362	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(20		)	—			(19		)	(b)	—			—
Total	$	(20	)	$	—		$	(381	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,169	)	$	—			$	7	(d)	$	(228	)	(c)
Total	$	—		$	(3,169	)	$	—			$	7		$	(228	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

^(c)  Amounts are recorded to electric fuel and purchased power.

^(d)  Amounts for the six months ended June 30, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the six months ended June 30, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, 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 assets and liabilities measured at fair value on a recurring basis at June 30, 2014:

	June 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	27	$	—	$	27	$	—		$	27
Other derivative instruments:
Natural gas commodity	—		3,715		—		3,715		(9		)	3,706
Total current derivative assets	$	—	$	3,742	$	—	$	3,742	$	(9	)	3,733
PPAs (a)												1,715
Current derivative instruments												$	5,448
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	15	$	—	$	15	$	—		$	15
Total noncurrent derivative assets	$	—	$	15	$	—	$	15	$	—		15
PPAs (a)												6,034
Noncurrent derivative instruments												$	6,049
Current derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	63	$	—	$	63	$	(9	)	$	54
Total current derivative liabilities	$	—	$	63	$	—	$	63	$	(9	)	54
PPAs (a)												5,216
Current derivative instruments												$	5,270
Noncurrent derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	27	$	—	$	27	$	—		$	27
Total noncurrent derivative liabilities	$	—	$	27	$	—	$	27	$	—		27
PPAs (a)												20,771
Noncurrent derivative instruments												$	20,798

^(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 onthis 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 June 30, 2014. At June 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and no 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 assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												$	23,366
Noncurrent derivative instruments												$	23,366

^(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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no 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 June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,893,570	$	4,216,091	$	3,872,643	$	4,059,661

XML

Segment Information (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Segment Reporting Information [Line Items]
Operating revenues	$ 993,704,000		$ 966,429,000		$ 2,197,247,000		$ 2,083,886,000
Net income	89,792,000		97,299,000		208,195,000		213,904,000
Affiliate electric revenue	3,000,000		2,000,000		5,000,000		4,000,000
Affiliate other revenue	1,000,000		1,000,000		2,000,000		2,000,000
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	761,631,000		747,943,000		1,495,992,000		1,469,379,000
Net income	75,741,000		85,603,000		149,709,000		164,071,000
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	223,236,000		209,321,000		679,632,000		593,292,000
Net income	10,846,000		8,786,000		48,995,000		42,585,000
All Other
Segment Reporting Information [Line Items]
Operating revenues	8,948,000		9,251,000		21,890,000		21,436,000
Net income	3,205,000		2,910,000		9,491,000		7,248,000
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	993,704,000	[1],[2]	966,429,000	[1],[2]	2,197,247,000	[3],[4]	2,083,886,000	[3],[4]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	761,569,000	[2]	747,882,000	[2]	1,495,833,000	[3]	1,469,230,000	[3]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	223,187,000		209,296,000		679,524,000		593,220,000
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	8,948,000	[1]	9,251,000	[1]	21,890,000	[4]	21,436,000	[4]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(111,000)		(86,000)		(267,000)		(221,000)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	62,000		61,000		159,000		149,000
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	49,000		25,000		108,000		72,000
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0

[1] Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2014 and 2013.

[2] Operating revenues include $3 million and $2 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013, respectively.

[3] Operating revenues include $5 million and $4 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

[4] Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2014 and 2013.

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014 MWh		Dec. 31, 2013 MWh
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	$ 0.5
Electric Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	0	[1],[2]	326,000	[1],[2]
Natural Gas Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	6,791,000	[1],[2]	6,398,000	[1],[2]
Vehicle Fuel Commodity
Gross Notional Amounts of Commodity Forwards and Options [Abstract]
Notional amount	172,000	[1],[2]	217,000	[1],[2]

[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.

XML

Commitments and Contingencies, Legal Contingencies (Details) (USD $)	3 Months Ended		6 Months Ended			13 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014 Pacific Northwest FERC Refund Proceeding [Member] Factor	Jun. 30, 2001 Pacific Northwest FERC Refund Proceeding [Member]
Legal Contingencies [Abstract]
Accrual for legal contingency					$ 0
Minimum amount of damages claimed by plaintiff					34,000,000
Sales to the City of Seattle	993,704,000	966,429,000	2,197,247,000	2,083,886,000		50,000,000
Estimated City of Seattle's claim for refunds not including interest					$ 28,000,000
Number of factors considered in assessment					2

XML

Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period					$ (23,338)
Accumulated other comprehensive loss at end of period	(23,573)				(23,573)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	188,901		188,152		364,425		361,193
Total, pre-tax	(139,684)		(151,657)		(320,584)		(332,219)
Tax expense	49,892		54,358		112,389		118,315
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(23,461)		(22,982)		(23,338)		(22,871)
Other comprehensive gain (loss) before reclassifications	5		(20)		2		(13)
Gains reclassified from net accumulated other comprehensive loss	(117)		(118)		(237)		(236)
Net current period other comprehensive loss	(112)		(138)		(235)		(249)
Accumulated other comprehensive loss at end of period	(23,573)		(23,120)		(23,573)		(23,120)
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	(189)		(189)		(382)		(381)
Tax expense	72		71		145		145
Total, net of tax	(117)		(118)		(237)		(236)
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	(182)	[1]	(182)	[1]	(362)	[1]	(362)	[1]
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	$ (7)	[2]	$ (7)	[2]	$ (20)	[2]	$ (19)	[2]

[1] Included in interest charges.

[2] Included in O&M expenses

XML

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract, USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Commodity Contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Transfers into Level 3	$ 0	$ 0	$ 0	$ 0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

XML

Management's Opinion

6 Months Ended

Jun. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Opinion

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of June 30, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013, filed with the SEC on Feb. 24, 2014. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0		$ 0		$ 0		$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0		0		0		0
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	8,000		(31,000)		3,000		(20,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(189,000)		(189,000)		(382,000)		(381,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
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		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(182,000)	[1]	(182,000)	[1]	(362,000)	[1]	(362,000)	[1]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
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	8,000		(31,000)		3,000		(20,000)
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	(7,000)	[2]	(7,000)	[2]	(20,000)	[2]	(19,000)	[2]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		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		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(1,916,000)		(3,211,000)		7,910,000		(3,169,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		(8,579,000)		7,000
Pre-tax gains (losses) recognized during the period in income	(65,000)		(244,000)		(4,381,000)		(228,000)
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		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(1,916,000)		(3,211,000)		7,910,000		(3,169,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		(8,579,000)	[3]	7,000	[3]
Pre-tax gains (losses) recognized during the period in income	$ (65,000)	[4]	$ (244,000)	[4]	$ (4,381,000)	[3]	$ (228,000)	[4]

[1] Recorded to interest charges.

[2] Recorded to O&M expenses.

[3] Amounts for the six months ended June 30, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the six months ended June 30, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

[4] Amounts are recorded to electric fuel and purchased power.

XML

Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2014

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(23,461	)	$	(22,982	)
Other comprehensive gain (loss) before reclassifications	5			(20		)
Gains reclassified from net accumulated other comprehensive loss	(117		)	(118		)
Net current period other comprehensive loss	(112		)	(138		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive gain (loss) before reclassifications	2			(13		)
Gains reclassified from net accumulated other comprehensive loss	(237		)	(236		)
Net current period other comprehensive loss	(235		)	(249		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(182	)	(a)	$	(182	)	(a)
Vehicle fuel derivatives	(7		)	(b)	(7		)	(b)
Total, pre-tax	(189		)		(189		)
Tax expense	72				71
Total amounts reclassified, net of tax	$	(117	)		$	(118	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(362	)	(a)	$	(362	)	(a)
Vehicle fuel derivatives	(20		)	(b)	(19		)	(b)
Total, pre-tax	(382		)		(381		)
Tax expense	145				145
Total amounts reclassified, net of tax	$	(237	)		$	(236	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

XML

Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,985		$	6,301		$	478		$	803
Interest cost	13,319			11,540			5,926			5,934
Expected return on plan assets	(17,677		)	(15,955		)	(7,553		)	(7,307		)
Amortization of transition obligation	—			—			—			196
Amortization of prior service credit	(773		)	(266		)	(1,561		)	(1,229		)
Amortization of net loss	8,473			10,854			1,608			3,489
Net benefit cost (credit) recognized for financial reporting	$	9,327		$	12,474		$	(1,102	)	$	1,886

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	11,970		$	12,603		$	957		$	1,606
Interest cost	26,638			23,080			11,852			11,868
Expected return on plan assets	(35,354		)	(31,910		)	(15,107		)	(14,614		)
Amortization of transition obligation	—			—			—			392
Amortization of prior service credit	(1,546		)	(532		)	(3,123		)	(2,458		)
Amortization of net loss	16,946			21,708			3,217			6,979
Net benefit cost (credit) recognized for financial reporting	$	18,654		$	24,949		$	(2,204	)	$	3,773

XML

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Counterparty Credit Risk (Details) (Credit Concentration Risk, USD $) In Millions, unless otherwise specified	Jun. 30, 2014 Counterparty
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	10
Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	$ 28.0
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	38.00%
No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	$ 25.5
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	34.00%

XML

Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$ 291,856	$ 351,180
Less allowance for bad debts	(21,461)	(22,505)
Accounts receivable, net	$ 270,395	$ 328,675

XML

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Public Utilities, Inventory [Line Items]
Inventories	$ 206,517	$ 238,007
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	53,452	53,127
Fuel
Public Utilities, Inventory [Line Items]
Inventories	82,680	86,062
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 70,385	$ 98,818

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	100	100
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	100	100

XML

Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 15,252,031		$ 14,751,325
Less accumulated depreciation	(4,126,553)		(4,008,928)
Property, plant and equipment, net	11,125,478		10,742,397
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	10,356,644		10,177,056
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,866,667		2,757,605
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	751,236		762,916
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	85,808	[1]	101,279	[1]
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 1,191,676		$ 952,469

[1] As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.

XML

Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Credit Facility [Abstract]
Credit facility	$ 700,000,000	[1]
Drawn	263,300,000	[2]
Available	436,700,000
Credit facility bank borrowings outstanding	$ 0		$ 0

[1] Credit facility expires in July 2017.

[2] Includes outstanding commercial paper and letters of credit.

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating revenues
Electric	$ 761,569	$ 747,882	$ 1,495,833	$ 1,469,230
Natural gas	223,187	209,296	679,524	593,220
Steam and other	8,948	9,251	21,890	21,436
Total operating revenues	993,704	966,429	2,197,247	2,083,886
Operating expenses
Electric fuel and purchased power	349,070	322,787	683,540	642,668
Cost of natural gas sold and transported	117,281	109,697	427,086	359,317
Cost of sales — steam and other	3,435	4,008	8,413	8,813
Operating and maintenance expenses	188,901	188,152	364,425	361,193
Demand side management program expenses	34,678	32,938	69,873	66,059
Depreciation and amortization	95,115	89,079	188,431	178,629
Taxes (other than income taxes)	41,787	36,093	83,605	71,233
Total operating expenses	830,267	782,754	1,825,373	1,687,912
Operating income	163,437	183,675	371,874	395,974
Other income, net	912	1,322	1,709	2,899
Allowance for funds used during construction — equity	12,952	6,791	24,382	12,714
Interest charges and financing costs
Interest charges — includes other financing costs of $1,532, $1,723, $3,252, and $3,371, respectively	42,429	43,231	86,401	84,619
Allowance for funds used during construction — debt	(4,812)	(3,100)	(9,020)	(5,251)
Total interest charges and financing costs	37,617	40,131	77,381	79,368
Income before income taxes	139,684	151,657	320,584	332,219
Income taxes	49,892	54,358	112,389	118,315
Net income	$ 89,792	$ 97,299	$ 208,195	$ 213,904

XML

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 1,400,000
Payments required if credit ratings were downgraded below investment grade	0	1,400,000
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Operating activities
Net income	$ 208,195	$ 213,904
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	190,911	181,222
Demand side management program amortization	2,288	2,514
Deferred income taxes	65,725	127,490
Amortization of investment tax credits	(1,468)	(1,479)
Allowance for equity funds used during construction	(24,382)	(12,714)
Net realized and unrealized hedging and derivative transactions	(2,892)	(5,094)
Changes in operating assets and liabilities:
Accounts receivable	20,170	83,949
Accrued unbilled revenues	53,838	56,802
Inventories	31,490	32,123
Prepayments and other	4,636	(8,183)
Accounts payable	(83,451)	(16,087)
Net regulatory assets and liabilities	51,798	64,131
Other current liabilities	(69,978)	(63,653)
Pension and other employee benefit obligations	(36,769)	(44,007)
Change in other noncurrent assets	5,811	479
Change in other noncurrent liabilities	(7,313)	2,860
Net cash provided by operating activities	408,609	614,257
Investing activities
Utility capital/construction expenditures	(573,401)	(497,626)
Allowance for equity funds used during construction	24,382	12,714
Investments in utility money pool arrangement	(567,000)	(617,000)
Repayments from utility money pool arrangement	639,000	531,000
Net cash used in investing activities	(477,019)	(570,912)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	256,800	(154,000)
Borrowings under utility money pool arrangement	129,000	14,000
Repayments under utility money pool arrangement	(129,000)	(14,000)
Proceeds from issuance of long-term debt	295,642	492,383
Repayments of long-term debt	(275,000)	(250,000)
Contributions from Parent	35,486	460
Dividends paid to parent	(259,156)	(133,481)
Net cash provided by (used in) financing activities	53,772	(44,638)
Net change in cash and cash equivalents	(14,638)	(1,293)
Cash and cash equivalents at beginning of period	21,089	5,150
Cash and cash equivalents at end of period	6,451	3,857
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(74,848)	(76,228)
Cash paid for income taxes, net	(39,649)	(14,922)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 104,927	$ 73,152

XML

Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities)	Jun. 30, 2014 MW	Dec. 31, 2013 MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,802	1,441

XML

Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	291,856		$	351,180
Less allowance for bad debts	(21,461		)	(22,505		)
	$	270,395		$	328,675

Inventories

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	53,452	$	53,127
Fuel	82,680		86,062
Natural gas	70,385		98,818
	$	206,517	$	238,007

Property, Plant and Equipment, Net

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,356,644		$	10,177,056
Natural gas plant	2,866,667			2,757,605
Common and other property	751,236			762,916
Plant to be retired (a)	85,808			101,279
Construction work in progress	1,191,676			952,469
Total property, plant and equipment	15,252,031			14,751,325
Less accumulated depreciation	(4,126,553		)	(4,008,928		)
	$	11,125,478		$	10,742,397

^(a)  As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.

XML

Commitments and Contingencies, Environmental Contingencies (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014 Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants	Dec. 31, 2010 Regional Haze Rules Boiler Kiln Group	Jun. 30, 2014 Capital Commitments Regional Haze Rules
Environmental Requirements [Abstract]
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths)	50.00%
Liability for estimated cost to comply with regulation			$ 359.7
Number of environmental groups who petitioned the U.S. Department of the Interior		2
Number of coal-fired boilers in Colorado		12
Number of coal-fired cement kilns in Colorado		1

XML

Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Borrowings and Other Financing Instruments [Abstract]

Committed Credit Facility Available

At June 30, 2014, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	263.3	$	436.7

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper and letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for PSCo were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	6			0.1
Maximum amount outstanding	70			12
Weighted average interest rate, computed on a daily basis	0.24		%	0.36		%
Weighted average interest rate at period end	N/A			N/A

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700
Amount outstanding at period end	257			—
Average amount outstanding	127			38
Maximum amount outstanding	261			332
Weighted average interest rate, computed on a daily basis	0.24		%	0.34		%
Weighted average interest rate at period end	0.29			N/A

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 6,451	$ 21,089
Accounts receivable, net	270,395	328,675
Accounts receivable from affiliates	57,246	19,136
Investments in utility money pool arrangement	0	72,000
Accrued unbilled revenues	217,079	270,917
Inventories	206,517	238,007
Regulatory assets	158,129	150,163
Deferred income taxes	75,389	87,267
Derivative instruments	5,448	6,576
Prepayments and other	27,993	32,629
Total current assets	1,024,647	1,226,459
Property, plant and equipment, net	11,125,478	10,742,397
Other assets
Regulatory assets	833,950	826,037
Derivative instruments	6,049	6,905
Other	48,813	52,520
Total other assets	888,812	885,462
Total assets	13,038,937	12,854,318
Current liabilities
Current portion of long-term debt	7,631	282,143
Short-term Debt	256,800	0
Accounts payable	345,356	451,243
Accounts payable to affiliates	31,162	45,902
Regulatory liabilities	125,380	79,499
Taxes accrued	85,180	154,194
Accrued interest	48,617	48,492
Dividends payable to parent	96,391	65,134
Derivative instruments	5,270	6,734
Other	71,492	89,571
Total current liabilities	1,073,279	1,222,912
Deferred credits and other liabilities
Deferred income taxes	2,274,042	2,206,179
Deferred investment tax credits	37,761	39,230
Regulatory liabilities	453,273	424,690
Asset retirement obligations	97,862	60,398
Derivative instruments	20,798	23,366
Customer advances	243,103	251,062
Pension and employee benefit obligations	130,358	167,127
Other	67,490	66,855
Total deferred credits and other liabilities	3,324,687	3,238,907
Commitments and contingencies
Capitalization
Long-term debt	3,885,939	3,590,500
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	0	0
Additional paid in capital	3,476,776	3,441,290
Retained earnings	1,301,829	1,384,047
Accumulated other comprehensive loss	(23,573)	(23,338)
Total common stockholder’s equity	4,755,032	4,801,999
Total liabilities and equity	$ 13,038,937	$ 12,854,318

XML

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Interest charges and financing costs
Other financing costs	$ 1,532	$ 1,723	$ 3,252	$ 3,371

XML

Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2014

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.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. 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 June 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

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 June 30, 2014, 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 other comprehensive income 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 three and six months ended June 30, 2014 and 2013.

At June 30, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains 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 June 30, 2014 and Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	June 30, 2014	Dec. 31, 2013
Megawatt hours of electricity	—	326
Million British thermal units of natural gas	6,791	6,398
Gallons of vehicle fuel	172	217

^(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.

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2014 and 2013, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2014
	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 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	$	—	$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	8		—			(7		)	(b)	—		—
Total	$	8	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—	$	(1,916	)	$	—			$	—	$	(65	)	(c)
Total	$	—	$	(1,916	)	$	—			$	—	$	(65	)

	Six Months Ended June 30, 2014
	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 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	$	—	$	—	$	(362	)	(a)	$	—			$	—
Vehicle fuel and other commodity	3		—		(20		)	(b)	—				—
Total	$	3	$	—	$	(382	)		$	—			$	—
Other derivative instruments
Natural gas commodity	$	—	$	7,910	$	—			$	(8,579	)	(d)	$	(4,381	)	(d)
Total	$	—	$	7,910	$	—			$	(8,579	)		$	(4,381	)

	Three Months Ended June 30, 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 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	$	—		$	—		$	(182	)	(a)	$	—	$	—
Vehicle fuel and other commodity	(31		)	—			(7		)	(b)	—		—
Total	$	(31	)	$	—		$	(189	)		$	—	$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,211	)	$	—			$	—	$	(244	)	(c)
Total	$	—		$	(3,211	)	$	—			$	—	$	(244	)

	Six Months Ended June 30, 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 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	$	—		$	—		$	(362	)	(a)	$	—		$	—
Vehicle fuel and other commodity	(20		)	—			(19		)	(b)	—			—
Total	$	(20	)	$	—		$	(381	)		$	—		$	—
Other derivative instruments
Natural gas commodity	$	—		$	(3,169	)	$	—			$	7	(d)	$	(228	)	(c)
Total	$	—		$	(3,169	)	$	—			$	7		$	(228	)

^(a)  Recorded to interest charges.

^(b)  Recorded to O&M expenses.

^(c)  Amounts are recorded to electric fuel and purchased power.

^(d)  Amounts for the six months ended June 30, 2014 and 2013 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the six months ended June 30, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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 June 30, 2014, five of PSCo’s 10 most significant counterparties, comprising $28.0 million or 38 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining five significant counterparties, comprising $25.5 million or 34 percent of this credit exposure, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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 June 30, 2014, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of PSCo were downgraded below investment grade. If the credit ratings of PSCo were downgraded below investment grade at Dec. 31, 2013, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets would have required PSCo to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $1.4 million. At June 30, 2014 and Dec. 31, 2013, there was no collateral posted on these specific contracts.

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 June 30, 2014 and Dec. 31, 2013.

Recurring Fair Value Measurements—The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at June 30, 2014:

	June 30, 2014
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	27	$	—	$	27	$	—		$	27
Other derivative instruments:
Natural gas commodity	—		3,715		—		3,715		(9		)	3,706
Total current derivative assets	$	—	$	3,742	$	—	$	3,742	$	(9	)	3,733
PPAs (a)												1,715
Current derivative instruments												$	5,448
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	15	$	—	$	15	$	—		$	15
Total noncurrent derivative assets	$	—	$	15	$	—	$	15	$	—		15
PPAs (a)												6,034
Noncurrent derivative instruments												$	6,049
Current derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	63	$	—	$	63	$	(9	)	$	54
Total current derivative liabilities	$	—	$	63	$	—	$	63	$	(9	)	54
PPAs (a)												5,216
Current derivative instruments												$	5,270
Noncurrent derivative liabilities
Other derivative instruments:
Natural gas commodity	$	—	$	27	$	—	$	27	$	—		$	27
Total noncurrent derivative liabilities	$	—	$	27	$	—	$	27	$	—		27
PPAs (a)												20,771
Noncurrent derivative instruments												$	20,798

^(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 onthis 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 June 30, 2014. At June 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and no 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 assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:

	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	40	$	—	$	40	$	—		$	40
Other derivative instruments:
Commodity trading	—		2,756		—		2,756		(1,276		)	1,480
Natural gas commodity	—		3,341		—		3,341		—			3,341
Total current derivative assets	$	—	$	6,137	$	—	$	6,137	$	(1,276	)	4,861
PPAs (a)												1,715
Current derivative instruments												$	6,576
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	13	$	—	$	13	$	—		$	13
Total noncurrent derivative assets	$	—	$	13	$	—	$	13	$	—		13
PPAs (a)												6,892
Noncurrent derivative instruments												$	6,905
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	$	1,399
Total current derivative liabilities	$	—	$	2,438	$	—	$	2,438	$	(1,039	)	1,399
PPAs (a)												5,335
Current derivative instruments												$	6,734
Noncurrent derivative liabilities
PPAs (a)												$	23,366
Noncurrent derivative instruments												$	23,366

^(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, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and no 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 three and six months ended June 30, 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 three and six months ended June 30, 2014 and 2013.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	3,893,570	$	4,216,091	$	3,872,643	$	4,059,661

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 June 30, 2014 and Dec. 31, 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 04, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Central Index Key	0000081018
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
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

Other Income, Net

6 Months Ended

Jun. 30, 2014

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	157		$	843		$	646		$	1,757
Other nonoperating income	1,200			637			1,875			1,519
Insurance policy expense	(445		)	(158		)	(812		)	(377		)
Other income, net	$	912		$	1,322		$	1,709		$	2,899

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Comprehensive income:
Net income	$ 89,792	$ 97,299	$ 208,195	$ 213,904
Derivative instruments:
Net fair value increase (decrease), net of tax of $3, $(11), $1, and $(7), respectively	5	(20)	2	(13)
Reclassification of gains to net income, net of tax of $(72), $(71), $(145), and $(145), respectively	(117)	(118)	(237)	(236)
Other comprehensive loss	(112)	(138)	(235)	(249)
Comprehensive income	$ 89,680	$ 97,161	$ 207,960	$ 213,655

XML

Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	291,856		$	351,180
Less allowance for bad debts	(21,461		)	(22,505		)
	$	270,395		$	328,675

(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	53,452	$	53,127
Fuel	82,680		86,062
Natural gas	70,385		98,818
	$	206,517	$	238,007

(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	10,356,644		$	10,177,056
Natural gas plant	2,866,667			2,757,605
Common and other property	751,236			762,916
Plant to be retired (a)	85,808			101,279
Construction work in progress	1,191,676			952,469
Total property, plant and equipment	15,252,031			14,751,325
Less accumulated depreciation	(4,126,553		)	(4,008,928		)
	$	11,125,478		$	10,742,397

^(a)  As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. Amounts are presented net of accumulated depreciation.

XML

Accounting Pronouncements

6 Months Ended

Jun. 30, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.3	$	2.5
Unrecognized tax benefit — Temporary tax positions	7.8		5.9
Total unrecognized tax benefit	$	9.1	$	8.4

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(4.6	)	$	(7.0	)

XML

Segment Information

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Segment Information

Segment 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, transmits and distributes electricity primarily in portions of 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 commodity trading operations.

• PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas primarily 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.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)(b)	$	761,569	$	223,187	$	8,948	$	—		$	993,704
Intersegment revenues	62		49		—		(111		)	—
Total revenues	$	761,631	$	223,236	$	8,948	$	(111	)	$	993,704
Net income	$	75,741	$	10,846	$	3,205	$	—		$	89,792

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)(b)	$	747,882	$	209,296	$	9,251	$	—		$	966,429
Intersegment revenues	61		25		—		(86		)	—
Total revenues	$	747,943	$	209,321	$	9,251	$	(86	)	$	966,429
Net income	$	85,603	$	8,786	$	2,910	$	—		$	97,299

^(a)    Operating revenues include $3 million and $2 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2014 and 2013.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)(b)	$	1,495,833	$	679,524	$	21,890	$	—		$	2,197,247
Intersegment revenues	159		108		—		(267		)	—
Total revenues	$	1,495,992	$	679,632	$	21,890	$	(267	)	$	2,197,247
Net income	$	149,709	$	48,995	$	9,491	$	—		$	208,195

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)(b)	$	1,469,230	$	593,220	$	21,436	$	—		$	2,083,886
Intersegment revenues	149		72		—		(221		)	—
Total revenues	$	1,469,379	$	593,292	$	21,436	$	(221	)	$	2,083,886
Net income	$	164,071	$	42,585	$	7,248	$	—		$	213,904

^(a)    Operating revenues include $5 million and $4 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2014 and 2013.

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, PSCo purchases power from independent power producing entities that own natural gas fueled power plants 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 had approximately 1,802 megawatts (MW) and 1,441 MW of capacity under long-term PPAs as of June 30, 2014 and Dec. 31, 2013, respectively, with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through 2032.

Environmental Contingencies

Environmental Requirements

Water and waste

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (EPA) published a proposed 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. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on PSCo is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. At June 30, 2014, the estimated cost of compliance for PSCo did not have a material impact on the results of operations, financial position or cash flows.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. PSCo is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at PSCo’s power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in Colorado. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at PSCo’s power plants.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (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 state implementation plan (SIP), Colorado identified the PSCo facilities that will have to reduce sulfur dioxide, nitrous oxide and particulate matter 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 the facilities included in 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 the Hayden and Pawnee plants are projected to cost $359.7 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction be added to the units. PSCo intervened in the case. The 10^th Circuit is anticipated to hear argument in January 2015, following completion of the briefs in November 2014.

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the Clean Air Act mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

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 — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit Court of Appeals (Ninth Circuit).

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle may contest the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC.

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, not withstanding 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 FERC’s standard has been challenged on appeal to 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 potentially responsible parties. No accrual has been recorded for this matter.

XML

Income Taxes

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit— PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. PSCo is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2014, 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 effective tax rate (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)	June 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.3	$	2.5
Unrecognized tax benefit — Temporary tax positions	7.8		5.9
Total unrecognized tax benefit	$	9.1	$	8.4

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(4.6	)	$	(7.0	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 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 June 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

XML

Rate Matters

6 Months Ended

Jun. 30, 2014

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending and Recently Concluded Regulatory Proceedings — CPUC

Colorado 2014 Electric Rate Case —In June 2014, PSCo filed an electric rate case in Colorado with the CPUC requesting an increase in annual revenue of approximately $137.7 million, or 4.89 percent. The request includes the initiation of a CACJA rider as part of the overall 2015 rate case request of approximately $95 million, as well as additional amounts for calendar years 2016 and 2017. The CACJA rider is anticipated to increase revenue recovery by approximately $40 million in 2016 and then decline to approximately $36 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers.

The rate filing is based on a 2015 test year, a requested return on equity (ROE) of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates. This transfer will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017.

In July 2014, the CPUC set hearings for early December 2014. A decision as well as implementation of final rates are anticipated in the first quarter of 2015.

Manufacturer’s Sales Tax Refund —Pursuant to the multi-year settlement agreement with the CPUC, PSCo defers 2012-2014 annual property taxes in excess of $76.7 million. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014. 

After PSCo’s initial successes in the District Court and Court of Appeals, the Colorado Supreme Court on June 30, 2014 ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001. Under the multi-year settlement agreement, as a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates.  This impact is reflected in PSCo’s pending electric rate case before the CPUC.

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 to be effective Aug. 1, 2014. As of June 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test.

2012 Pipeline System Integrity Adjustment (PSIA) Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. In February 2014, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of operating and maintenance (O&M) expenditures and an agreement not to disallow capital expenditures related to a pipeline replacement project. In July 2014, the Administrative Law Judge (ALJ) issued a final decision approving the settlement agreement.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended June 30, 2014. For the three months ended June 30, 2013, PSCo credited the RESA regulatory asset balance $6.5 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at June 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

The current sharing mechanism will be effective through 2014. In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an ALJ. A decision is anticipated later in 2014.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a confidential settlement in principle to resolve the complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing.

In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues.

In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. In June 2014, PSCo and its transmission customers reached a confidential settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

XML

Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2014

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 June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	6			0.1
Maximum amount outstanding	70			12
Weighted average interest rate, computed on a daily basis	0.24		%	0.36		%
Weighted average interest rate at period end	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 outstanding for PSCo was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	700		$	700
Amount outstanding at period end	257			—
Average amount outstanding	127			38
Maximum amount outstanding	261			332
Weighted average interest rate, computed on a daily basis	0.24		%	0.34		%
Weighted average interest rate at period end	0.29			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 June 30, 2014 and Dec. 31, 2013, there were $6.5 million and $6.4 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.

At June 30, 2014, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	700.0	$	263.3	$	436.7

^(a)  Credit facility expires in July 2017.

^(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 June 30, 2014 and Dec. 31, 2013.

Long-Term Borrowings

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044.

XML

Rate Matters (Details) (USD $)	1 Months Ended				6 Months Ended		1 Months Ended			3 Months Ended	12 Months Ended			12 Months Ended				1 Months Ended
	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Electric Rate Case 2014	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Electric Rate Case 2014, Electric Rates 2015	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Electric Rate Case 2014, Electric Rates 2016	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Electric Rate Case 2014, Electric Rates 2017	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Manufacturer's Sales Tax Refund	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Annual Electric Earnings Test	Apr. 30, 2014 Colorado Public Utilities Commission (CPUC) 2013 Electric Earnings Test	Apr. 30, 2013 Colorado Public Utilities Commission (CPUC) 2012 PSIA Report	May 31, 2014 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing	Jun. 30, 2013 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing	Jun. 30, 2014 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing	Dec. 31, 2013 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing Shareholders	Dec. 31, 2011 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing Shareholders	Dec. 31, 2012 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing Customers	Dec. 31, 2011 Colorado Public Utilities Commission (CPUC) Renewable Energy Credit Sharing Customers	Aug. 31, 2013 Federal Energy Regulatory Commission (FERC) Production Formula Rate ROE Complaint	Mar. 31, 2014 Federal Energy Regulatory Commission (FERC) Transmission Formula Rate Case	Jun. 30, 2012 Federal Energy Regulatory Commission (FERC) Transmission Formula Rate Case	Apr. 30, 2012 Federal Energy Regulatory Commission (FERC) Transmission Formula Rate Case	Jul. 31, 2014 Subsequent Event Colorado Public Utilities Commission (CPUC) 2012 PSIA Report
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 137,700,000																				$ 2,000,000
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.89%
Public Utilities, Requested increase (decrease) to rider revenue		95,000,000	40,000,000	36,000,000				43,500,000
Public Utilities, Requested Return on Equity, Percentage	10.35%																			10.25%
Public Utilities, Requested Rate Base, Amount	6,390,000,000
Public Utilities, Requested Equity Capital Structure, Percentage	56.00%
Public Utilities, Rider costs to be recovered through base rates, amount	19,900,000
Public Utilities, Maximum annual amount of property taxes not subject to deferral					76,700,000
Public Utilities, Reduction in current year property tax deferral					10,000,000
Public Utilities, Return on equity threshold triggering earnings sharing						10.00%
Public Utilities, Proposed refund to customers due to annual earnings test							45,700,000
Public Utilities, Approved increase (decrease) to rider revenue																						43,400,000
Public Utilities, Approved disallowance																						100,000
Public Utilities, Ultimate margin sharing associated with stand alone REC transactions															10.00%		90.00%
Public Utilities, Margin threshold determining percentage of margin sharing											20,000,000
Public Utilities, Percentage of margin on hybrid REC approved for first 20 million of margins														20.00%		80.00%
Public Utilities, Percentage of margin on hybrid REC approved for margins in excess of 20 million														10.00%		90.00%
Public Utilities, Customers share of margins credited against RESA regulatory asset balance										6,500,000
Public Utilities, Cumulative credit against RESA regulatory asset balance												104,600,000	104,500,000
Public Utilities, Margin threshold proposed to be removed from sharing mechanism on hybrid REC trades									$ 20,000,000
Public Utilities, Return on equity charged to third parties, lower bound																		10.10%
Public Utilities, Return on equity charged to third parties, upper bound																		10.40%
Public Utilities, Return on equity requested by third parties																		9.04%		9.15%
Public Utilities, Return on equity requested by third parties, July 2012 through November 2012																			8.91%
Public Utilities, Return on equity requested by third parties, after November 2012																			8.70%

XML

Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 5,985,000	$ 6,301,000	$ 11,970,000	$ 12,603,000
Interest cost		13,319,000	11,540,000	26,638,000	23,080,000
Expected return on plan assets		(17,677,000)	(15,955,000)	(35,354,000)	(31,910,000)
Amortization of transition obligation		0	0	0	0
Amortization of prior service credit		(773,000)	(266,000)	(1,546,000)	(532,000)
Amortization of net loss		8,473,000	10,854,000	16,946,000	21,708,000
Net benefit cost (credit) recognized for financial reporting		9,327,000	12,474,000	18,654,000	24,949,000
Total contributions to the pension plans during the period	35,100,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		478,000	803,000	957,000	1,606,000
Interest cost		5,926,000	5,934,000	11,852,000	11,868,000
Expected return on plan assets		(7,553,000)	(7,307,000)	(15,107,000)	(14,614,000)
Amortization of transition obligation		0	196,000	0	392,000
Amortization of prior service credit		(1,561,000)	(1,229,000)	(3,123,000)	(2,458,000)
Amortization of net loss		1,608,000	3,489,000	3,217,000	6,979,000
Net benefit cost (credit) recognized for financial reporting		(1,102,000)	1,886,000	(2,204,000)	3,773,000
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 130,000,000
Number of Xcel Energy's pension plans to which contributions were made	3

XML

Other Comprehensive Income

6 Months Ended

Jun. 30, 2014

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(23,461	)	$	(22,982	)
Other comprehensive gain (loss) before reclassifications	5			(20		)
Gains reclassified from net accumulated other comprehensive loss	(117		)	(118		)
Net current period other comprehensive loss	(112		)	(138		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(23,338	)	$	(22,871	)
Other comprehensive gain (loss) before reclassifications	2			(13		)
Gains reclassified from net accumulated other comprehensive loss	(237		)	(236		)
Net current period other comprehensive loss	(235		)	(249		)
Accumulated other comprehensive loss at June 30	$	(23,573	)	$	(23,120	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(182	)	(a)	$	(182	)	(a)
Vehicle fuel derivatives	(7		)	(b)	(7		)	(b)
Total, pre-tax	(189		)		(189		)
Tax expense	72				71
Total amounts reclassified, net of tax	$	(117	)		$	(118	)

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(362	)	(a)	$	(362	)	(a)
Vehicle fuel derivatives	(20		)	(b)	(19		)	(b)
Total, pre-tax	(382		)		(381		)
Tax expense	145				145
Total amounts reclassified, net of tax	$	(237	)		$	(236	)

^(a)  Included in interest charges.

^(b)  Included in O&M expenses.

XML

Other Income, Net (Tables)

6 Months Ended

Jun. 30, 2014

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	157		$	843		$	646		$	1,757
Other nonoperating income	1,200			637			1,875			1,519
Insurance policy expense	(445		)	(158		)	(812		)	(377		)
Other income, net	$	912		$	1,322		$	1,709		$	2,899

XML

Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other Income and Expenses [Abstract]
Interest income	$ 157	$ 843	$ 646	$ 1,757
Other nonoperating income	1,200	637	1,875	1,519
Insurance policy expense	(445)	(158)	(812)	(377)
Other income, net	$ 912	$ 1,322	$ 1,709	$ 2,899

XML

Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) (First Mortgage Bonds, Series Due March 15, 2044, USD $)	1 Months Ended
	Mar. 31, 2014
First Mortgage Bonds | Series Due March 15, 2044
Long-Term Borrowings [Abstract]
Face amount	$ 300,000,000
Interest rate, stated percentage (in hundredths)	4.30%
Maturity date	Mar. 15, 2044

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative instruments:
Net fair value increase (decrease), tax	$ 3	$ (11)	$ 1	$ (7)
Reclassification of gains to net income, tax	$ (72)	$ (71)	$ (145)	$ (145)

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Results by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2014
Operating revenues (a)(b)	$	761,569	$	223,187	$	8,948	$	—		$	993,704
Intersegment revenues	62		49		—		(111		)	—
Total revenues	$	761,631	$	223,236	$	8,948	$	(111	)	$	993,704
Net income	$	75,741	$	10,846	$	3,205	$	—		$	89,792

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Operating revenues (a)(b)	$	747,882	$	209,296	$	9,251	$	—		$	966,429
Intersegment revenues	61		25		—		(86		)	—
Total revenues	$	747,943	$	209,321	$	9,251	$	(86	)	$	966,429
Net income	$	85,603	$	8,786	$	2,910	$	—		$	97,299

^(a)    Operating revenues include $3 million and $2 million of affiliate electric revenue for the three months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2014 and 2013.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2014
Operating revenues (a)(b)	$	1,495,833	$	679,524	$	21,890	$	—		$	2,197,247
Intersegment revenues	159		108		—		(267		)	—
Total revenues	$	1,495,992	$	679,632	$	21,890	$	(267	)	$	2,197,247
Net income	$	149,709	$	48,995	$	9,491	$	—		$	208,195

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2013
Operating revenues (a)(b)	$	1,469,230	$	593,220	$	21,436	$	—		$	2,083,886
Intersegment revenues	149		72		—		(221		)	—
Total revenues	$	1,469,379	$	593,292	$	21,436	$	(221	)	$	2,083,886
Net income	$	164,071	$	42,585	$	7,248	$	—		$	213,904

^(a)    Operating revenues include $5 million and $4 million of affiliate electric revenue for the six months ended June 30, 2014 and 2013, respectively.

^(b)    Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2014 and 2013.

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Amount outstanding at period end	$ 256,800,000	$ 0
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	0
Average amount outstanding	6,000,000	100,000
Maximum amount outstanding	70,000,000	12,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.24%	0.36%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	700,000,000	700,000,000
Amount outstanding at period end	257,000,000	0
Average amount outstanding	127,000,000	38,000,000
Maximum amount outstanding	$ 261,000,000	$ 332,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.24%	0.34%
Short-term Debt, Weighted Average Interest Rate	0.29%

XML

Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,985		$	6,301		$	478		$	803
Interest cost	13,319			11,540			5,926			5,934
Expected return on plan assets	(17,677		)	(15,955		)	(7,553		)	(7,307		)
Amortization of transition obligation	—			—			—			196
Amortization of prior service credit	(773		)	(266		)	(1,561		)	(1,229		)
Amortization of net loss	8,473			10,854			1,608			3,489
Net benefit cost (credit) recognized for financial reporting	$	9,327		$	12,474		$	(1,102	)	$	1,886

	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	11,970		$	12,603		$	957		$	1,606
Interest cost	26,638			23,080			11,852			11,868
Expected return on plan assets	(35,354		)	(31,910		)	(15,107		)	(14,614		)
Amortization of transition obligation	—			—			—			392
Amortization of prior service credit	(1,546		)	(532		)	(3,123		)	(2,458		)
Amortization of net loss	16,946			21,708			3,217			6,979
Net benefit cost (credit) recognized for financial reporting	$	18,654		$	24,949		$	(2,204	)	$	3,773

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $35.1 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2014.