PUBLIC SERVICE CO OF COLORADO - FORM 10-Q

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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, 2015



¨	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. 3, 2015
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	25
Item 4 —	Controls and Procedures	29

PART II — OTHER INFORMATION

Item 1 —	Legal Proceedings	30
Item 1A —	Risk Factors	30
Item 4 —	Mine Safety Disclosures	30
Item 5 —	Other Information	30
Item 6 —	Exhibits	30

SIGNATURES		31

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).

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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
	2015			2014			2015			2014
Operating revenues
Electric	$	751,531		$	761,569		$	1,500,992		$	1,495,833
Natural gas	191,975			223,187			565,178			679,524
Steam and other	9,015			8,948			21,801			21,890
Total operating revenues	952,521			993,704			2,087,971			2,197,247

Operating expenses
Electric fuel and purchased power	296,002			349,070			618,760			683,540
Cost of natural gas sold and transported	81,128			117,281			309,872			427,086
Cost of sales — steam and other	3,649			3,435			9,342			8,413
Operating and maintenance expenses	191,225			188,901			373,642			364,425
Demand side management program expenses	33,513			34,678			63,582			69,873
Depreciation and amortization	101,246			95,115			201,289			188,431
Taxes (other than income taxes)	50,582			41,787			100,908			83,605
Total operating expenses	757,345			830,267			1,677,395			1,825,373

Operating income	195,176			163,437			410,576			371,874

Other income, net	765			912			1,452			1,709
Allowance for funds used during construction — equity	3,391			12,952			6,197			24,382

Interest charges and financing costs
Interest charges — includes other financing costs of $1,555, $1,532, $3,060 and $3,252, respectively	43,894			42,429			86,984			86,401
Allowance for funds used during construction — debt	(1,325		)	(4,812		)	(2,423		)	(9,020		)
Total interest charges and financing costs	42,569			37,617			84,561			77,381

Income before income taxes	156,763			139,684			333,664			320,584
Income taxes	58,263			49,892			124,198			112,389
Net income	$	98,500		$	89,792		$	209,466		$	208,195

See Notes to Consolidated Financial Statements

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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
	2015			2014			2015			2014
Net income	$	98,500		$	89,792		$	209,466		$	208,195

Other comprehensive loss

Derivative instruments:
Net fair value decrease, net of tax of $5, $3, $2, and $1, respectively	8			5			3			2
Reclassification of gains to net income, net of tax of $(64), $(72), $(128) and $(145), respectively	(106		)	(117		)	(211		)	(237		)

Other comprehensive loss	(98		)	(112		)	(208		)	(235		)
Comprehensive income	$	98,402		$	89,680		$	209,258		$	207,960

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Six Months Ended June 30
	2015			2014
Operating activities
Net income	$	209,466		$	208,195
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	203,593			190,911
Demand side management program amortization	2,043			2,288
Deferred income taxes	88,418			65,725
Amortization of investment tax credits	(1,467		)	(1,468		)
Allowance for equity funds used during construction	(6,197		)	(24,382		)
Net realized and unrealized hedging and derivative transactions	4,909			(2,892		)
Changes in operating assets and liabilities:
Accounts receivable	76,019			20,170
Accrued unbilled revenues	80,721			53,838
Inventories	40,314			31,490
Prepayments and other	72,954			4,636
Accounts payable	(81,167		)	(83,451		)
Net regulatory assets and liabilities	61,031			51,798
Other current liabilities	(65,671		)	(69,978		)
Pension and other employee benefit obligations	(21,912		)	(36,769		)
Change in other noncurrent assets	1,467			5,811
Change in other noncurrent liabilities	(17,266		)	(7,313		)
Net cash provided by operating activities	647,255			408,609

Investing activities
Utility capital/construction expenditures	(454,190		)	(573,401		)
Allowance for equity funds used during construction	6,197			24,382
Investments in utility money pool arrangement	(141,300		)	(567,000		)
Repayments from utility money pool arrangement	157,300			639,000
Net cash used in investing activities	(431,993		)	(477,019		)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(329,000		)	256,800
Borrowings under utility money pool arrangement	45,000			129,000
Repayments under utility money pool arrangement	(45,000		)	(129,000		)
Proceeds from issuance of long-term debt	247,193			295,642
Repayments of long-term debt	—			(275,000		)
Capital contributions from parent	27,707			35,486
Dividends paid to parent	(164,302		)	(259,156		)
Net cash (used in) provided by financing activities	(218,402		)	53,772

Net change in cash and cash equivalents	(3,140		)	(14,638		)
Cash and cash equivalents at beginning of period	7,635			21,089
Cash and cash equivalents at end of period	$	4,495		$	6,451

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(81,094	)	$	(74,848	)
Cash received (paid) for income taxes, net	40,957			(39,649		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	53,449		$	104,927

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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



	June 30, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	4,495		$	7,635
Accounts receivable, net	251,750			322,885
Accounts receivable from affiliates	45,958			50,842
Investments in utility money pool arrangement	—			16,000
Accrued unbilled revenues	213,328			294,049
Inventories	198,665			238,979
Regulatory assets	97,362			120,120
Deferred income taxes	124,005			64,587
Derivative instruments	1,751			1,731
Prepaid taxes	19,519			90,365
Prepayments and other	21,871			23,979
Total current assets	978,704			1,231,172

Property, plant and equipment, net	11,796,866			11,626,956

Other assets
Regulatory assets	906,030			903,973
Derivative instruments	4,319			5,176
Other	47,614			48,506
Total other assets	957,963			957,655
Total assets	$	13,733,533		$	13,815,783

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	8,666		$	8,178
Short-term debt	53,000			382,000
Accounts payable	271,780			425,133
Accounts payable to affiliates	32,756			46,736
Regulatory liabilities	187,945			134,459
Taxes accrued	92,626			159,470
Accrued interest	49,425			48,409
Dividends payable to parent	82,871			83,652
Derivative instruments	5,967			5,774
Other	69,737			72,002
Total current liabilities	854,773			1,365,813

Deferred credits and other liabilities
Deferred income taxes	2,587,936			2,437,641
Deferred investment tax credits	34,806			36,273
Regulatory liabilities	462,737			464,421
Asset retirement obligations	229,998			225,296
Derivative instruments	15,629			18,257
Customer advances	213,089			229,990
Pension and employee benefit obligations	180,017			202,031
Other	68,031			68,171
Total deferred credits and other liabilities	3,792,243			3,682,080

Commitments and contingencies
Capitalization
Long-term debt	4,127,235			3,882,051
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	—			—
Additional paid in capital	3,550,495			3,522,788
Retained earnings	1,432,873			1,386,929
Accumulated other comprehensive loss	(24,086		)	(23,878		)
Total common stockholder’s equity	4,959,282			4,885,839
Total liabilities and equity	$	13,733,533		$	13,815,783

See Notes to Consolidated Financial Statements

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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, 2015 and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2015 and 2014; and its cash flows for the six months ended June 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 20, 2015. 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, 2014, 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 (FASB) 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. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. PSCo is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements.

Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, PSCo does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, PSCo does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

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3.	Selected Balance Sheet Data



(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	272,772		$	346,007
Less allowance for bad debts	(21,022		)	(23,122		)
	$	251,750		$	322,885



(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	57,685	$	55,491
Fuel	89,584		80,963
Natural gas	51,396		102,525
	$	198,665	$	238,979



(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	11,057,787		$	10,927,867
Natural gas plant	3,273,406			3,210,242
Common and other property	833,399			827,708
Plant to be retired ^(a)	55,397			71,534
Construction work in progress	940,878			828,620
Total property, plant and equipment	16,160,867			15,865,971
Less accumulated depreciation	(4,364,001		)	(4,239,015		)
	$	11,796,866		$	11,626,956


^(a)	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, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, 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 2009 federal income tax return expires in March 2016. 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, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. As of June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution is uncertain.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2015, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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.

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



(Millions of Dollars)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.9	$	1.9
Unrecognized tax benefit — Temporary tax positions	12.4		10.0
Total unrecognized tax benefit	$	14.3	$	11.9

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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(5.5	)	$	(3.9	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process 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, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.


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, 2014 and in Note 5 to PSCo’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests a return on equity (ROE) of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.

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In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:



(Millions of Dollars)	2015			2016 Step		2017 Step
Total base rate increase	$	40.5		$	7.6	$	18.1
Incremental PSIA rider revenues	(0.1		)	21.7		21.2
Total revenue impact	$	40.4		$	29.3	$	39.3

In June 2015, intervenors, including the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), filed testimony.


•	Staff recommended a base rate decrease of $14.7 million, based on an ROE of 9.0 percent and a 47.04 percent equity ratio;


•	OCC recommended a base rate increase of $5.8 million, based on an ROE of 9.0 percent and a 52.70 percent equity ratio;


•	A multi-year plan was opposed by both the Staff and OCC;


•	The Staff recommended deferring costs related to incremental property taxes and safety programs which are expected to be approximately $4.2 million in 2016 and $9.0 million in 2017; and


•	The Staff opposed PSCo’s proposed earnings test and the stay out provision.

Regarding the PSIA:


•	The Staff proposed extending the PSIA rider for three years;


•	The Staff recommended approximately $32.6 million of PSIA costs would be transferred to base rates, effective Jan. 1, 2016, in addition to the Staff’s proposed 2015 base rate adjustment; and


•	The OCC recommended the PSIA rider expire on June 30, 2016 and any costs be included in base rates through a step increase.

The Staff and OCC’s 2015 base rate recommendations are summarized in the following table:



(Millions of Dollars)	Staff			OCC
PSCo’s filed 2015 base rate request	$	40.5		$	40.5
ROE	(12.8		)	(13.7		)
Capital structure and cost of debt	(12.8		)	(4.8		)
Cherokee pipeline adjustment	(11.2		)	4.8
Move to 2014 historical test year	(10.5		)	(16.4		)
O&M expenses	(3.5		)	(2.7		)
Other, net	(4.4		)	(1.9		)
Total adjustments	$	(55.2	)	$	(34.7	)

Recommended (decrease) increase	$	(14.7	)	$	5.8

The Staff’s recommendation for the PSIA rider is as follows:



(Millions of Dollars)	2016			2017
PSCO’s filed incremental PSIA request	$	21.7		$	21.2
Transfer PSIA O&M to base rates	(24.1		)	(2.0		)
ROE and capital structure	(8.2		)	(3.6		)
Transfer meter replacement program from base rates to PSIA	1.7			1.7
Total	$	(8.9	)	$	17.3

On July 20, 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo also accepts portions of the Staff’s position regarding the PSIA rider. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

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(Millions of Dollars)	2015			2016 Step		2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6	$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0		6.4
Rebuttal corrections and adjustments	—			—		(7.7		)
Total base rate request	$	40.5		$	14.6	$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7		21.7
Total revenue impact from rebuttal	$	40.4		$	29.3	$	38.5

If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.

The next steps in the procedural schedule are as follows:

•Sur-Rebuttal Testimony — Aug. 3, 2015;

•Evidentiary Hearing — Aug. 18 - Aug. 31, 2015;

•Interim Rates (subject to refund) — Oct. 1, 2015; and

•Final CPUC Decision — No later than Jan. 20, 2016

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 through 2014. On April 30, 2015, PSCo filed a tariff for the 2014 earnings test with the CPUC proposing a refund obligation of $66.5 million to electric customers, which was approved by the CPUC in July 2015.

In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of June 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information.

Electric, Purchased Gas and Resource Adjustment Clauses

Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million.

In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million, a 2015 DSM gas budget of $13.1 million, a 2016 DSM electric budget of $78.7 million and a 2016 DSM gas budget of $13.6 million. PSCo has reached an agreement with all parties resolving most of the contested issues in the proceeding. The remaining issues to be litigated primarily concern the avoided costs attributable to DSM measures. In July 2015, the ALJ approved the plan.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, 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, 2014, 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.

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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) of capacity under long-term PPAs as of June 30, 2015 and Dec. 31, 2014, 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

Federal Clean Water Act (CWA) Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. PSCo does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

Air

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, PSCo had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the 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 (SO₂), 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. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable in rates.

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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 challenged 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. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. The 10^th Circuit will now resume litigation and a decision is anticipated in 2016.

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.

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where PSCo operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. The Colorado Department of Health and Environment is expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision by summer 2016.

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years.

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 Federal Energy Regulatory Commission (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 U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

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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. The City of Seattle filed a petition for review with the Court of Appeals for the Ninth Circuit seeking review of FERC’s order on remand.

Notwithstanding its petition for review, 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 contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. This matter is now pending a decision by the FERC.

In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the 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 PRPs. No accrual has been recorded for this matter.

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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, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	250		$	250
Amount outstanding at period end	—			—
Average amount outstanding	1			4
Maximum amount outstanding	22			97
Weighted average interest rate, computed on a daily basis	0.54		%	0.25		%
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, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	700		$	700
Amount outstanding at period end	53			382
Average amount outstanding	76			167
Maximum amount outstanding	275			393
Weighted average interest rate, computed on a daily basis	0.52		%	0.31		%
Weighted average interest rate at period end	0.43			0.65

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, 2015 and Dec. 31, 2014, there were $5.4 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 line of credit 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, 2015, PSCo had the following committed credit facility available (in millions of dollars):



Credit Facility ^(a)		Drawn ^(b)		Available
$	700	$	58	$	642

^(a) This credit facility expires in October 2019.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at June 30, 2015 and Dec. 31, 2014.

Long-Term Borrowings

In May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025.

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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.

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, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.

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At June 30, 2015, PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in 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, 2015 and 2014.

At June 30, 2015, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards and options at June 30, 2015 and Dec. 31, 2014:


^(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, 2015 and 2014, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:



	Three Months Ended June 30, 2015
	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 Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(182	)	^(a)	$	—			$	—
Vehicle fuel and other commodity	13		—			12			^(b)	—				—
Total	$	13	$	—		$	(170	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	191	^(c)
Natural gas commodity	—		(242		)	—				(22		)	^(d)	—
Total	$	—	$	(242	)	$	—			$	(22	)		$	191

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	Six Months Ended June 30, 2015
	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 Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(363	)	^(a)	$	—			$	—
Vehicle fuel and other commodity	5		—			24			^(b)	—				—
Total	$	5	$	—		$	(339	)		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	380	^(c)
Natural gas commodity	—		(416		)	—				(5,627		)	^(d)	5,460		^(d)
Total	$	—	$	(416	)	$	—			$	(5,627	)		$	5,840



	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	)

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	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	)


^(a)	Recorded to interest charges.


^(b)	Recorded to operating and maintenance (O&M) expenses.


^(c)	Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue as appropriate.

^(d)

Amounts for the three and six months ended June 30, 2015 and six months ended 2014 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 three and six months ended June 30, 2015 and six months ended 2014 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, 2015 and 2014. 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, 2015, seven of PSCo’s 10 most significant counterparties, comprising $22.8 million or 33 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 three significant counterparties, comprising $21.7 million or 32 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, 2015 and Dec. 31, 2014, there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the 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, 2015 and Dec. 31, 2014.

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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, 2015:



	June 30, 2015
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	—	$	4	$	—	$	4	$	—		$	4
Natural gas commodity	—		195		—		195		(163		)	32
Total current derivative assets	$	—	$	199	$	—	$	199	$	(163	)	36
PPAs ^(a)												1,715
Current derivative instruments												$	1,751
Noncurrent derivative assets
PPAs ^(a)												$	4,319
Noncurrent derivative instruments												$	4,319
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	48	$	—	$	48	$	—		$	48
Other derivative instruments:
Commodity trading	—		1		—		1		—			1
Natural gas commodity	—		442		—		442		(163		)	279
Other commodity	—		450		—		450		—			450
Total current derivative liabilities	$	—	$	941	$	—	$	941	$	(163	)	778
PPAs ^(a)												5,189
Current derivative instruments												$	5,967
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	22	$	—	$	22	$	—		$	22
Other derivative instruments:
Other commodity	—		26		—		26		—			26
Total noncurrent derivative liabilities	$	—	$	48	$	—	$	48	$	—		48
PPAs ^(a)												15,581
Noncurrent derivative instruments												$	15,629

^(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, 2015. At June 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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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, 2014:



	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	33	$	—	$	33	$	(18	)	$	15
Total current derivative assets	$	—	$	33	$	—	$	33	$	(18	)	15
PPAs ^(a)												1,716
Current derivative instruments												$	1,731
Noncurrent derivative assets
PPAs ^(a)												$	5,176
Noncurrent derivative instruments												$	5,176
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	53	$	—	$	53	$	—		$	53
Other derivative instruments:
Commodity trading	—		—		—		—		—			—
Natural gas commodity	—		548		—		548		(18		)	530
Total current derivative liabilities	$	—	$	601	$	—	$	601	$	(18	)	583
PPAs ^(a)												5,191
Current derivative instruments												$	5,774
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	46	$	—	$	46	$	—		$	46
Other derivative instruments:
Natural gas commodity	—		35		—		35		—			35
Total noncurrent derivative liabilities	$	—	$	81	$	—	$	81	$	—		81
PPAs ^(a)												18,176
Noncurrent derivative instruments												$	18,257

^(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were no changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2015 and 2014.

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, 2015 and 2014.

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Fair Value of Long-Term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:



	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,135,901	$	4,385,944	$	3,890,229	$	4,328,968

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2015 and Dec. 31, 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other Income, Net

Other income, net consisted of the following:



	Three Months Ended June 30					Six Months Ended June 30
(Thousands of Dollars)	2015		2014			2015			2014
Interest income	$	142	$	157		$	375		$	646
Other nonoperating income	520		1,200			1,297			1,875
Insurance policy income (expense)	103		(445		)	(220		)	(812		)
Other income, net	$	765	$	912		$	1,452		$	1,709


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, 2015
Operating revenues ^(a)(b)	$	751,531	$	191,975		$	9,015	$	—		$	952,521
Intersegment revenues	69		(7		)	—		(62		)	—
Total revenues	$	751,600	$	191,968		$	9,015	$	(62	)	$	952,521
Net income	$	87,676	$	10,613		$	211	$	—		$	98,500

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(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

^(a)Operating revenues include $3 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014.

^(b)Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 2015 and 2014.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Six Months Ended June 30, 2015
Operating revenues ^(a)(b)	$	1,500,992	$	565,178	$	21,801		$	—		$	2,087,971
Intersegment revenues	157		34		—			(191		)	—
Total revenues	$	1,501,149	$	565,212	$	21,801		$	(191	)	$	2,087,971
Net income (loss)	$	162,345	$	47,236	$	(115	)	$	—		$	209,466



(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

^(a)Operating revenues include $4 million and $5 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.

^(b)Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 2015 and 2014.


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)



	Three Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,065		$	5,985		$	232		$	478
Interest cost	12,714			13,319			4,374			5,926
Expected return on plan assets	(18,147		)	(17,677		)	(5,950		)	(7,553		)
Amortization of prior service credit	(784		)	(773		)	(1,562		)	(1,561		)
Amortization of net loss	9,094			8,473			619			1,608
Net periodic benefit cost (credit)	9,942			9,327			(2,287		)	(1,102		)
Cost not recognized due to the effects of regulation	(366		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	9,576		$	9,327		$	(2,287	)	$	(1,102	)

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	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,130		$	11,970		$	464		$	957
Interest cost	25,428			26,638			8,749			11,852
Expected return on plan assets	(36,295		)	(35,354		)	(11,901		)	(15,107		)
Amortization of prior service credit	(1,568		)	(1,546		)	(3,124		)	(3,123		)
Amortization of net loss	18,188			16,946			1,238			3,217
Net periodic benefit cost (credit)	19,883			18,654			(4,574		)	(2,204		)
Cost not recognized due to the effects of regulation	(732		)	—			—			—
Net benefit cost (credit) recognized for financial reporting	$	19,151		$	18,654		$	(4,574	)	$	(2,204	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $20.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2015.


12.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2015 and 2014 were as follows:



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(23,988	)	$	(23,461	)
Other comprehensive loss before reclassifications	8			5
Gains reclassified from net accumulated other comprehensive loss	(106		)	(117		)
Net current period other comprehensive loss	(98		)	(112		)
Accumulated other comprehensive loss at June 30	$	(24,086	)	$	(23,573	)

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	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(23,878	)	$	(23,338	)
Other comprehensive loss before reclassifications	3			2
Gains reclassified from net accumulated other comprehensive loss	(211		)	(237		)
Net current period other comprehensive loss	(208		)	(235		)
Accumulated other comprehensive loss at June 30	$	(24,086	)	$	(23,573	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(182	)	^(a)	$	(182	)	^(a)
Vehicle fuel derivatives	12			^(b)	(7		)	^(b)
Total, pre-tax	(170		)		(189		)
Tax expense	64				72
Total amounts reclassified, net of tax	$	(106	)		$	(117	)



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	(363	)	^(a)	$	(362	)	^(a)
Vehicle fuel derivatives	24			^(b)	(20		)	^(b)
Total, pre-tax	(339		)		(382		)
Tax expense	128				145
Total amounts reclassified, net of tax	$	(211	)		$	(237	)


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.

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.

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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 a 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; cyber security threats and data security breaches; 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 and Exhibit 99.01 of PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.

Results of Operations

PSCo’s net income was approximately $209.5 million for the six months ended June 30, 2015, compared with approximately $208.2 million for the same period in 2014. The positive impact of implementing the CACJA rider, effective Jan. 1, 2015, and lower estimated electric earnings test refunds were offset by lower AFUDC, higher property taxes, depreciation, and O&M expenses, as well as the impact of weather and weather-normalized sales decline.

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 minimal impact on electric margin. The following table details the electric revenues and margin:



	Six Months Ended June 30
(Millions of Dollars)	2015			2014
Electric revenues	$	1,501		$	1,496
Electric fuel and purchased power	(619		)	(684		)
Electric margin	$	882		$	812

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)	2015 vs. 2014
Non-fuel riders^(a)	$	52
Earnings test refund	35
Fuel and purchased power cost recovery	(58		)
Retail rate decrease	(14		)
Trading, including REC sales	(9		)
Other, net	(1		)
Total increase in electric revenues	$	5

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Electric Margin



(Millions of Dollars)	2015 vs. 2014
Non-fuel riders ^(a)	$	52
Earnings test refund	35
Retail rate decrease	(14		)
Retail sales decline, excluding weather impact	(3		)
Total increase in electric margin	$	70

^(a) Increase relates primarily to the new CACJA rider, effective Jan. 1, 2015. This amount positively impacted revenues and more than offset the base rate decrease.

Natural Gas Revenues and Margin

Total natural gas expense 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)	2015			2014
Natural gas revenues	$	565		$	680
Cost of natural gas sold and transported	(310		)	(427		)
Natural gas margin	$	255		$	253

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)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(117	)
Estimated impact of weather	(5		)
DSM program revenues	(3		)
Retail sales decline, excluding weather impact	(2		)
Integrity rider	12
Total decrease in natural gas revenues	$	(115	)

Natural Gas Margin



(Millions of Dollars)	2015 vs. 2014
Integrity rider	$	12
Estimated impact of weather	(5		)
DSM program revenues (offset by expenses)	(3		)
Retail sales decline, excluding weather impact	(2		)
Total increase in natural gas margin	$	2

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $9.2 million, or 2.5 percent, for the six months ended June 30, 2015 compared with the same period in 2014. O&M expenses were higher, primarily due to the timing of planned maintenance and overhauls at our generation facilities, as summarized in the table below:



(Millions of Dollars)	2015 vs. 2014
Plant generation costs	$	8
Employee benefits	1
Total increase in O&M expenses	$	9

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DSM Program Expenses — DSM program expenses decreased $6.3 million, or 9.0 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The decrease was primarily attributable to lower electric and gas recovery rates. Lower DSM program expenses are generally offset by lower revenues.

Depreciation and Amortization — Depreciation and amortization expense increased $12.9 million, or 6.8 percent, for the six months ended June 30, 2015 compared with the same period for 2014. The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $17.3 million, or 20.7 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The increase is primarily due to higher property taxes.

AFUDC — AFUDC decreased $24.8 million for the six months ended June 30, 2015 compared with the same period in 2014. The decrease was primarily due to the implementation of the CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.

Income Taxes — Income tax expense increased $11.8 million for the six months ended June 30, 2015 compared with the same period in 2014. The increase in income tax expense was primarily due to higher pretax earnings in 2015 and decreased permanent plant-related adjustments in 2015. The ETR was 37.2 percent for the six months ended June 30, 2015 compared with 35.1 percent for the same period in 2014. The lower ETR was primarily due to the same adjustments mentioned above.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of PSCo's Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Public Utility Regulation included in Item 2. of PSCo's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

Boulder, Colo. Municipalization — PSCo’s franchise agreement with the City of Boulder (Boulder) expired in December 2010. In November 2011, a ballot measure was passed which authorized the formation and operation of a municipal 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 2013, the CPUC 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. In January 2015, the Boulder District Court affirmed the CPUC decision.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business. PSCo has notified Boulder that its offer was deficient. 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. PSCo filed a motion to dismiss the petition based upon the CPUC’s ruling that it must determine the appropriate system separations prior to Boulder filing its condemnation case. PSCo’s motion to dismiss was granted in February 2015. This decision does not prevent Boulder from filing another condemnation petition if it obtains CPUC approval of its separation plan.

In August 2014, PSCo filed a petition with the FERC requesting an order requiring that Boulder’s attempt to acquire PSCo’s transmission and distribution facilities by condemnation requires prior FERC approval under the Federal Power Act. In December 2014, the FERC issued an order granting PSCo’s petition.

If Boulder proceeds with another condemnation petition and 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.

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In April 2015, Boulder issued a request for proposal for a partial requirements wholesale electric power supply agreement. Boulder indicated that the request for proposal was designed to elicit a wholesale power supply arrangement for a five-year term commencing on Jan. 1, 2018. Boulder has requested that PSCo consider different pricing structures and allow for Boulder to reduce demand over the term of the contract. In May 2015, PSCo sent Boulder a letter indicating its willingness to discuss a power supply arrangement with Boulder, but no formal offer was made. On July 7, 2015, Boulder filed an application with the CPUC requesting approval of Boulder’s proposed separation plan.

Steam System Package Boilers and Regulatory Plan — In December 2014, PSCo filed the results of a steam survey along with both a short-term plan and a long-term plan for the steam system consisting of a request for a conditional CPCN to construct either one or two boilers for its steam utility, dependent on the next two seasons of winter peaking capacity. In April 2015, the CPUC approved a settlement agreement between PSCo and all parties, which resolved all issues.

Cabin Creek Hydro Upgrade — PSCo filed a CPCN with the CPUC in May 2015 to upgrade the Cabin Creek Hydro facility. The upgrade is estimated to cost $89.2 million and will extend the life of the facility by 40 years as well as increase the maximum output by 36 MW. A final CPUC decision is expected in the fourth quarter of 2015.

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, asset transactions and mergers, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation 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, 2014. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any of the ROE complaint proceedings until 2016.

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, 2015, 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.

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.

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Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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, 2014, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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)).
4.01*	Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250,000,000 principal amount of 2.90% First Mortgage Bonds, Series No. 28 due 2025. (Exhibit 4.01 to Form 8-K of PSCo dated May 12, 2015 (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, 2015 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.

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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. 3, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

(Amounts in Thousands) ^(a)(b)

June 30, 2015

Dec. 31, 2014

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel