PUBLIC SERVICE CO OF COLORADO - FORM 10-Q

PUBLIC SERVICE CO OF COLORADO - FORM 10-Q - October 27, 2017

Attached files

Attached files

PUBLIC SERVICE CO OF COLORADO Reports

file	filename
EX-99.01 - EXHIBIT 99.01 - PUBLIC SERVICE CO OF COLORADO	pscoex9901q32017.htm
EX-32.01 - EXHIBIT 32.01 - PUBLIC SERVICE CO OF COLORADO	pscoex3201q32017.htm
EX-31.02 - EXHIBIT 31.02 - PUBLIC SERVICE CO OF COLORADO	pscoex3102q32017.htm
EX-31.01 - EXHIBIT 31.01 - PUBLIC SERVICE CO OF COLORADO	pscoex3101q32017.htm
EX-3.01 - EXHIBIT 3.01 - PUBLIC SERVICE CO OF COLORADO	pscarticles7-1x98.htm

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 Sept. 30, 2017



¨	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, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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)		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 Oct. 27, 2017
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.

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PART I — FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 4 —	Controls and Procedures	29

PART II — OTHER INFORMATION

Item 1 —	Legal Proceedings	30
Item 1A —	Risk Factors	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 Sept. 30						Nine Months Ended Sept. 30
	2017			2016			2017			2016
Operating revenues
Electric	$	877,604		$	897,516		$	2,318,912		$	2,337,547
Natural gas	142,389			152,763			691,302			659,738
Steam and other	10,300			8,898			31,529			29,585
Total operating revenues	1,030,293			1,059,177			3,041,743			3,026,870

Operating expenses
Electric fuel and purchased power	288,997			318,624			857,346			890,509
Cost of natural gas sold and transported	37,243			42,379			303,903			270,182
Cost of sales — steam and other	4,098			3,664			11,991			10,874
Operating and maintenance expenses	173,905			191,011			547,413			570,343
Demand side management expenses	34,520			31,015			92,552			88,094
Depreciation and amortization	118,289			111,803			350,796			330,593
Taxes (other than income taxes)	47,213			45,076			146,481			146,851
Total operating expenses	704,265			743,572			2,310,482			2,307,446

Operating income	326,028			315,605			731,261			719,424

Other income, net	1,536			544			7,085			1,837
Allowance for funds used during construction — equity	8,642			5,343			19,591			13,714

Interest charges and financing costs
Interest charges — includes other financing costs of $1,605, $1,271, $4,669 and $4,735, respectively	49,097			46,664			141,403			138,982
Allowance for funds used during construction — debt	(3,266		)	(1,995		)	(7,610		)	(5,222		)
Total interest charges and financing costs	45,831			44,669			133,793			133,760

Income before income taxes	290,375			276,823			624,144			601,215
Income taxes	104,298			103,216			225,934			224,390
Net income	$	186,077		$	173,607		$	398,210		$	376,825

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 Sept. 30					Nine Months Ended Sept. 30
	2017		2016			2017		2016
Net income	$	186,077	$	173,607		$	398,210	$	376,825

Other comprehensive income (loss)

Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost, net of tax of $1, $0, $3 and $(134), respectively	1		—			3		(217		)

Derivative instruments:
Net fair value increase, net of tax of $0, $(1), $0, and $1, respectively	—		(1		)	—		1
Reclassification of losses to net income, net of tax of $150, $162, $455, and $486, respectively	257		266			753		792

Other comprehensive income	258		265			756		576
Comprehensive income	$	186,335	$	173,872		$	398,966	$	377,401

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)



	Nine Months Ended Sept. 30
	2017			2016
Operating activities
Net income	$	398,210		$	376,825
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	353,653			332,383
Demand side management program amortization	672			1,802
Deferred income taxes	223,121			202,599
Amortization of investment tax credits	(2,102		)	(2,104		)
Allowance for equity funds used during construction	(19,591		)	(13,714		)
Net realized and unrealized hedging and derivative transactions	907			(1,801		)
Other	(11		)	(388		)
Changes in operating assets and liabilities:
Accounts receivable	4,431			27,080
Accrued unbilled revenues	74,918			70,498
Inventories	(250		)	(11,712		)
Prepayments and other	11,717			52,526
Accounts payable	(53,706		)	(20,164		)
Net regulatory assets and liabilities	(28,594		)	(31,152		)
Other current liabilities	(40,789		)	(59,596		)
Pension and other employee benefit obligations	(16,691		)	(13,080		)
Change in other noncurrent assets	(1,149		)	(1,422		)
Change in other noncurrent liabilities	(1,916		)	(15,433		)
Net cash provided by operating activities	902,830			893,147

Investing activities
Utility capital/construction expenditures	(995,680		)	(802,051		)
Proceeds from insurance recoveries	—			608
Allowance for equity funds used during construction	19,591			13,714
Investments in utility money pool arrangement	(659,000		)	(437,000		)
Repayments from utility money pool arrangement	609,000			437,000
Other, net	(657		)	(1,460		)
Net cash used in investing activities	(1,026,746		)	(789,189		)

Financing activities
Repayments of short-term borrowings, net	(129,000		)	(14,000		)
Borrowings under utility money pool arrangement	40,000			357,000
Repayments under utility money pool arrangement	(40,000		)	(306,000		)
Proceeds from issuance of long-term debt	393,795			244,527
Repayments of long-term debt	—			(129,500		)
Capital contributions from parent	158,080			1,571
Dividends paid to parent	(245,291		)	(253,796		)
Other	(110		)	—
Net cash provided by (used in) financing activities	177,474			(100,198		)

Net change in cash and cash equivalents	53,558			3,760
Cash and cash equivalents at beginning of period	5,926			3,585
Cash and cash equivalents at end of period	$	59,484		$	7,345

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(145,461	)	$	(149,786	)
Cash (paid) received for income taxes, net	(7,752		)	32,388
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	133,933		$	84,417

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)



	Sept. 30, 2017			Dec. 31, 2016
Assets
Current assets
Cash and cash equivalents	$	59,484		$	5,926
Accounts receivable, net	299,367			304,900
Accounts receivable from affiliates	13,386			9,421
Investments in utility money pool arrangement	50,000			—
Accrued unbilled revenues	222,160			297,078
Inventories	205,640			202,220
Regulatory assets	81,021			103,783
Derivative instruments	3,681			10,934
Prepayments and other	24,193			34,559
Total current assets	958,932			968,821

Property, plant and equipment, net	13,550,488			12,849,799

Other assets
Regulatory assets	972,876			958,429
Derivative instruments	861			3,398
Other	27,636			25,637
Total other assets	1,001,373			987,464
Total assets	$	15,510,793		$	14,806,084

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	305,437		$	5,270
Short-term debt	—			129,000
Accounts payable	399,402			376,186
Accounts payable to affiliates	32,179			98,797
Regulatory liabilities	61,224			101,110
Taxes accrued	138,924			171,862
Accrued interest	33,430			48,619
Dividends payable to parent	88,588			74,208
Derivative instruments	6,049			6,788
Other	79,265			73,022
Total current liabilities	1,144,498			1,084,862

Deferred credits and other liabilities
Deferred income taxes	3,122,909			2,889,129
Deferred investment tax credits	28,559			30,661
Regulatory liabilities	493,674			512,933
Asset retirement obligations	298,740			289,563
Derivative instruments	4,255			7,828
Customer advances	159,012			162,742
Pension and employee benefit obligations	269,156			285,774
Other	59,909			62,201
Total deferred credits and other liabilities	4,436,214			4,240,831

Commitments and contingencies
Capitalization
Long-term debt	4,303,229			4,210,936
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	—			—
Additional paid in capital	3,851,318			3,633,216
Retained earnings	1,797,778			1,659,239
Accumulated other comprehensive loss	(22,244		)	(23,000		)
Total common stockholder’s equity	5,626,852			5,269,455
Total liabilities and equity	$	15,510,793		$	14,806,084

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 Sept. 30, 2017 and Dec. 31, 2016; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2017 and 2016; and its cash flows for the nine months ended Sept. 30, 2017 and 2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2017 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, 2016 balance sheet information has been derived from the audited 2016 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016. 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, 2016, filed with the SEC on Feb. 24, 2017. 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, 2016, 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 new framework for the recognition of revenue. PSCo expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. PSCo currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo expects that the overall impacts of the Jan. 1, 2018 adoption will not be material.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. PSCo has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. PSCo expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.

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Presentation of Net Periodic Benefit Cost — In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. PSCo expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	319,051		$	324,512
Less allowance for bad debts	(19,684		)	(19,612		)
	$	299,367		$	304,900



(Thousands of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	69,051	$	66,161
Fuel	56,247		66,429
Natural gas	80,342		69,630
	$	205,640	$	202,220



(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	12,542,171		$	12,304,436
Natural gas plant	3,904,223			3,710,772
Common and other property	943,117			919,955
Plant to be retired ^(a)	11,412			31,839
Construction work in progress	874,399			484,340
Total property, plant and equipment	18,275,322			17,451,342
Less accumulated depreciation	(4,724,834		)	(4,601,543		)
	$	13,550,488		$	12,849,799


^(a)	In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.


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, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audits — 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 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. PSCo did not accrue any income tax benefit related to this adjustment.

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In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Sept. 30, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2017, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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



(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	3.7	$	2.9
Unrecognized tax benefit — Temporary tax positions	6.2		16.8
Total unrecognized tax benefit	$	9.9	$	19.7

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



(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(3.9	)	$	(5.8	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and the IRS and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:



(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period	$	(1.1	)	$	(0.4	)
Interest income (expense) related to unrecognized tax benefits recorded during the period	0.9			(0.7		)
Payable for interest related to unrecognized tax benefits at end of period	$	(0.2	)	$	(1.1	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.


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, 2016 and in Note 5 to PSCo’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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Pending Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request, summarized below, is based on forecast test years (FTY) ending Dec. 31, a 10.0 percent return on equity (ROE) and an equity ratio of 55.25 percent.



Revenue Request (Millions of Dollars)	2018		2019		2020		2021		Total
Revenue request	$	74.6	$	74.9	$	59.7	$	35.7	$	244.9
Clean Air Clean Jobs Act (CACJA) revenue conversion to base rates ^(a)	90.4		—		—		—		90.4
Transmission Cost Adjustment (TCA) revenue conversion to base rates ^(a)	42.7		—		—		—		42.7
Total ^(b)	$	207.7	$	74.9	$	59.7	$	35.7	$	378.0

Expected year-end rate base (billions of dollars) ^(b)	$	6.8	$	7.1	$	7.3	$	7.4


^(a)	The roll-in of each of the TCA and CACJA rider revenues into base rates will not have an impact on total customer bills or total revenue as these costs are already being recovered through a rider. Transmission investments for 2019 through 2021 will be recovered through the TCA rider.


^(b)	This base rate request does not include the impacts associated with the renewable energy standard adjustment and retail electric commodity adjustment for the Rush Creek wind investments or any impacts of the proposed Colorado Energy Plan.

Final rates are expected to be effective in June 2018. PSCo also proposed a stay-out provision and earnings test through 2021.

Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.



Revenue Request (Millions of Dollars)	2018		2019		2020		Total
Revenue request	$	63.2	$	32.9	$	42.9	$	139.0
Pipeline System Integrity Adjustment (PSIA) revenue conversion to base rates ^(a)	—		93.9		—		93.9
Total	$	63.2	$	126.8	$	42.9	$	232.9

Expected year-end rate base (billions of dollars) ^(b)	$	1.5	$	2.3	$	2.4


^(a)	The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.


^(b)	The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.

In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), recommended a single 2016 historic test year (HTY), based on an average 13-month rate base, and opposed a multi-year plan (MYP). The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case.

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The following represents adjustments to PSCo’s filed request made by Staff and OCC for 2018:



(Millions of Dollars)	Staff			OCC
Filed 2018 new revenue request	$	63.2		$	63.2
Impact of the change in test year	4.4			4.4
PSCo’s filed 2016 HTY	$	67.6		$	67.6

Recommended adjustments:
ROE (9.0 percent)	(13.5		)	(13.5		)
Capital structure and cost of debt	(10.2		)	(7.5		)
Change in amortization period	(5.4		)	—
Prepaid pension and retiree medical assets	(5.2		)	—
Change from 2016 year end to average rate base	(4.8		)	(4.8		)
Other, net	(5.0		)	(5.5		)
Total adjustments	$	(44.1	)	$	(31.3	)

Total recommended rate increase	$	23.5		$	36.3

The next steps in the procedural schedule are as follows:


•	Rebuttal testimony — Nov. 3, 2017;


•	Intervenor sur-rebuttal testimony — Nov. 15, 2017;


•	Hearings — Dec. 11 - 15 and 18 - 19, 2017; and


•	Statements of position — Jan. 19, 2018.

Interim rates, subject to refund, are expected to be effective Jan. 1, 2018. A final decision by the CPUC is anticipated in March 2018.

Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of Sept. 30, 2017.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 and in Notes 5 and 6 to the

consolidated financial statements included in PSCo’s Quarterly Report on Form 10-Q for the quarterly periods ended March

31, 2017 and June 30, 2017, 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.

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 1,571 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2017 and Dec. 31, 2016, 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.

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Environmental Contingencies

Manufactured Gas Plant (MGP) Sites — PSCo is currently involved in investigating and/or remediating MGP sites. PSCo has identified three sites where former MGP disposal activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these sites, there may be parties that have responsibility for some portion of any remediation. PSCo anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. PSCo had accrued $3.3 million and $1.7 million and for these sites as of Sept. 30, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other potentially responsible parties to offset any costs incurred. PSCo anticipates that any significant amounts incurred will be recovered from customers.

Environmental Requirements

Water and Waste

Federal Clean Water Act (CWA) Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air

Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.

The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.

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Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. In August 2017, the EPA withdrew its prior decision delaying designations of nonattainment areas under the 2015 ozone NAAQS to October 2018. The CAA requires areas to be designated within two years after a revision to the NAAQS but allows a one year extension if the EPA has insufficient information on which to base a decision. The EPA is now re-assessing to what extent it has sufficient information to make designations in October 2017 and whether in some cases an extension is still necessary.

Legal Contingencies

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the district court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. It is uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the administrative law judge (ALJ) issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in the Denver District Court in August 2016. In July 2017, a stipulation to dismiss this lawsuit with prejudice was filed on behalf of all parties and granted by the Denver District Court.

PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.


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 Sept. 30, 2017		Year Ended Dec. 31, 2016
Borrowing limit	$	250	$	250
Amount outstanding at period end	—		—
Average amount outstanding	—		21
Maximum amount outstanding	—		141
Weighted average interest rate, computed on a daily basis	N/A		0.73		%
Weighted average interest rate at period end	N/A		N/A

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Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for PSCo was as follows:



(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017		Year Ended Dec. 31, 2016
Borrowing limit	$	700	$	700
Amount outstanding at period end	—		129
Average amount outstanding	—		24
Maximum amount outstanding	—		154
Weighted average interest rate, computed on a daily basis	N/A		0.70		%
Weighted average interest rate at period end	N/A		0.95

Letters of Credit — PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2017 and Dec. 31, 2016, there were $4 million and $3 million, respectively of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Sept. 30, 2017, PSCo had the following committed credit facility available (in millions of dollars):



Credit Facility ^(a)		Drawn ^(b)		Available
$	700	$	4	$	696

^(a) This credit facility expires in June 2021.

^(b) Includes outstanding 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 Sept. 30, 2017 and Dec. 31, 2016.

Long-Term Borrowings

In June 2017, PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047.


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.

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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 value (NAV).

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

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements 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 Sept. 30, 2017, accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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

PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in 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 nine months ended Sept. 30, 2017 and 2016.

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

The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2017 and Dec. 31, 2016:


^(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.

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The following tables detail the impact of derivative activity during the three months ended Sept. 30, 2017 and 2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:



	Three Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Losses Recognized During the Period in:					Pre-Tax 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	$	—	$	—		$	407	^(a)	$	—	$	—
Total	$	—	$	—		$	407		$	—	$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—	$	(211	)	^(c)
Natural gas commodity	—		(1,635		)	—			—		—
Total	$	—	$	(1,635	)	$	—		$	—	$	(211	)




	Nine Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Losses Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Losses Recognized During the Period in Income
(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	$	—	$	—		$	1,208	^(a)	$	—		$	—
Total	$	—	$	—		$	1,208		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	(23	)	^(c)
Natural gas commodity	—		(8,643		)	—			282		^(d)	(2,990		)	^(d)
Total	$	—	$	(8,643	)	$	—		$	282		$	(3,013	)





	Three Months Ended Sept. 30, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax 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	$	—		$	—		$	407	^(a)	$	—	$	—
Vehicle fuel and other commodity	(2		)	—			21		^(b)	—		—
Total	$	(2	)	$	—		$	428		$	—	$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—	$	(28	)	^(c)
Natural gas commodity	—			(4,848		)	—			—		(6		)	^(d)
Total	$	—		$	(4,848	)	$	—		$	—	$	(34	)

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	Nine Months Ended Sept. 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax 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 (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,211	^(a)	$	—		$	—
Vehicle fuel and other commodity	2		—			67		^(b)	—			—
Total	$	2	$	—		$	1,278		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	200		^(c)
Natural gas commodity	—		(1,172		)	—			7,736		^(d)	(3,242		)	^(d)
Total	$	—	$	(1,172	)	$	—		$	7,736		$	(3,042	)


^(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)

Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and nine months ended Sept. 30, 2017 included no settlement gains or losses and $0.9 million of settlement gains, respectively. Amounts for the three and nine months ended Sept. 30, 2016 included no settlement gains or losses. The remaining derivative settlement gains and losses for the nine months ended Sept. 30, 2017 and 2016 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 nine months ended Sept. 30, 2017 and 2016. 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 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 Sept. 30, 2017, five of PSCo’s 10 most significant counterparties for these activities, comprising $4.5 million or 10 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $17.3 million or 39 percent of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $8.1 million or 18 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Nine of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. At Sept. 30, 2017 and Dec. 31, 2016, there were no derivative instruments in a material liability position with such underlying contract provisions.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2017 and Dec. 31, 2016.

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 Sept. 30, 2017:



	Sept. 30, 2017
	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	$	116	$	3,238	$	5	$	3,359	$	(2,652	)	$	707
Natural gas commodity	—		1,394		—		1,394		(135		)	1,259
Total current derivative assets	$	116	$	4,632	$	5	$	4,753	$	(2,787	)	1,966
PPAs ^(a)												1,715
Current derivative instruments												$	3,681
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	511	$	—	$	511	$	(109	)	$	402
Total noncurrent derivative assets	$	—	$	511	$	—	$	511	$	(109	)	402
PPAs ^(a)												459
Noncurrent derivative instruments												$	861
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	144	$	3,104	$	3	$	3,251	$	(3,188	)	$	63
Natural gas commodity	—		962		—		962		(135		)	827
Total current derivative liabilities	$	144	$	4,066	$	3	$	4,213	$	(3,323	)	890
PPAs ^(a)												5,159
Current derivative instruments												$	6,049
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	406	$	—	$	406	$	(109	)	$	297
Total noncurrent derivative liabilities	$	—	$	406	$	—	$	406	$	(109	)	297
PPAs ^(a)												3,958
Noncurrent derivative instruments												$	4,255


^(a)	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 Sept. 30, 2017. At Sept. 30, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $0.5 million. 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, 2016:



	Dec. 31, 2016
	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	$	1,124	$	5,453	$	—	$	6,577	$	(5,137	)	$	1,440
Natural gas commodity	—		7,778		—		7,778		—			7,778
Total current derivative assets	$	1,124	$	13,231	$	—	$	14,355	$	(5,137	)	9,218
PPAs ^(a)												1,716
Current derivative instruments												$	10,934
Noncurrent derivative assets
Other derivative instruments:
Natural gas commodity	$	—	$	1,652	$	—	$	1,652	$	—		$	1,652
Total noncurrent derivative assets	$	—	$	1,652	$	—	$	1,652	$	—		1,652
PPAs ^(a)												1,746
Noncurrent derivative instruments												$	3,398
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	$	1,628
Total current derivative liabilities	$	1,386	$	5,357	$	22	$	6,765	$	(5,137	)	1,628
PPAs ^(a)												5,160
Current derivative instruments												$	6,788
Noncurrent derivative liabilities
PPAs ^(a)												$	7,828
Noncurrent derivative instruments												$	7,828


^(a)	During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

There were immaterial gains and losses recognized in earnings for Level 3 commodity trading derivatives in the three and nine months ended Sept. 30, 2017 and 2016.

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 nine months ended Sept. 30, 2017 and 2016.

Fair Value of Long-Term Debt

As of Sept. 30, 2017 and Dec. 31, 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Sept. 30, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	4,608,666	$	4,958,850	$	4,216,206	$	4,491,570

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2017 and Dec. 31, 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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9.	Other Income, Net

Other income, net consisted of the following:



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016			2017			2016
Interest income	$	1,422		$	162		$	2,406		$	451
Other nonoperating income	193			511			4,940			1,594
Insurance policy expense	(79		)	(129		)	(261		)	(205		)
Other nonoperating expense	—			—			—			(3		)
Other income, net	$	1,536		$	544		$	7,085		$	1,837


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 Sept. 30, 2017
Operating revenues ^(a)(b)	$	877,604	$	142,389	$	10,300	$	—		$	1,030,293
Intersegment revenues	47		222		—		(269		)	—
Total revenues	$	877,651	$	142,611	$	10,300	$	(269	)	$	1,030,293
Net income	$	178,648	$	5,815	$	1,614	$	—		$	186,077

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2016
Operating revenues ^(a)(b)	$	897,516	$	152,763	$	8,898	$	—		$	1,059,177
Intersegment revenues	54		6		—		(60		)	—
Total revenues	$	897,570	$	152,769	$	8,898	$	(60	)	$	1,059,177
Net income (loss)	$	168,328	$	4,918	$	361	$	—		$	173,607

^(a)Operating revenues include $0 and $2 million of affiliate electric revenue for the three months ended Sept. 30, 2017 and 2016.

^(b)Operating revenues include $1 million of other affiliate revenue for the three months ended Sept. 30, 2017 and 2016.



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2017
Operating revenues ^(a)(b)	$	2,318,912	$	691,302	$	31,529	$	—		$	3,041,743
Intersegment revenues	206		318		—		(524		)	—
Total revenues	$	2,319,118	$	691,620	$	31,529	$	(524	)	$	3,041,743
Net income	$	342,195	$	53,133	$	2,882	$	—		$	398,210



(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2016
Operating revenues ^(a)(b)	$	2,337,547	$	659,738	$	29,585	$	—		$	3,026,870
Intersegment revenues	196		84		—		(280		)	—
Total revenues	$	2,337,743	$	659,822	$	29,585	$	(280	)	$	3,026,870
Net income	$	320,192	$	53,883	$	2,750	$	—		$	376,825

^(a)Operating revenues include $1 million and $7 million of affiliate electric revenue for the nine months ended Sept. 30, 2017 and 2016, respectively.

^(b)Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2017 and 2016.


11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)




	Three Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	6,820		$	6,487		$	192		$	192
Interest cost	12,639			13,852			4,191			4,518
Expected return on plan assets	(17,134		)	(17,692		)	(5,476		)	(5,575		)
Amortization of prior service credit	(803		)	(801		)	(1,562		)	(1,562		)
Amortization of net loss	7,089			6,692			961			483
Net periodic benefit cost (credit)	8,611			8,538			(1,694		)	(1,944		)
Credits not recognized due to the effects of regulation	736			682			—			—
Net benefit cost (credit) recognized for financial reporting	$	9,347		$	9,220		$	(1,694	)	$	(1,944	)

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	Nine Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	20,460		$	19,445		$	576		$	576
Interest cost	37,919			41,554			12,573			13,554
Expected return on plan assets	(51,402		)	(53,076		)	(16,428		)	(16,725		)
Amortization of prior service credit	(2,409		)	(2,408		)	(4,686		)	(4,686		)
Amortization of net loss	21,267			20,078			2,883			1,449
Net periodic benefit cost (credit)	25,835			25,593			(5,082		)	(5,832		)
Credits not recognized due to the effects of regulation	1,898			1,947			—			—
Net benefit cost (credit) recognized for financial reporting	$	27,733		$	27,540		$	(5,082	)	$	(5,832	)

In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans, of which $16.8 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2017.


12.	Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:



	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(22,284	)	$	(218	)	$	(22,502	)
Losses reclassified from net accumulated other comprehensive loss	257			1			258
Net current period other comprehensive income	257			1			258
Accumulated other comprehensive loss at Sept. 30	$	(22,027	)	$	(217	)	$	(22,244	)



	Three Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(23,308	)	$	(217	)	$	(23,525	)
Other comprehensive loss before reclassifications	(1		)	—			(1		)
Losses reclassified from net accumulated other comprehensive loss	266			—			266
Net current period other comprehensive income	265			—			265
Accumulated other comprehensive loss at Sept. 30	$	(23,043	)	$	(217	)	$	(23,260	)



	Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(22,780	)	$	(220	)	$	(23,000	)
Losses reclassified from net accumulated other comprehensive loss	753			3			756
Net current period other comprehensive income	753			3			756
Accumulated other comprehensive loss at Sept. 30	$	(22,027	)	$	(217	)	$	(22,244	)

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	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23,836	)	$	—		$	(23,836	)
Other comprehensive income (loss) before reclassifications	1			(219		)	(218		)
Losses reclassified from net accumulated other comprehensive loss	792			2			794
Net current period other comprehensive loss	793			(217		)	576
Accumulated other comprehensive loss at Sept. 30	$	(23,043	)	$	(217	)	$	(23,260	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:




	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2017				Three Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	407		^(a)	$	407		^(a)
Vehicle fuel derivatives	—			^(b)	21			^(b)
Total, pre-tax	$	407			$	428
Tax benefit	(150		)		(162		)
Total, net of tax	$	257			$	266
Defined benefit pension and postretirement losses:
Amortization of net loss	$	2		^(c)	$	—		^(c)
Total, pre-tax	2				—
Tax benefit	(1		)		—
Total, net of tax	1				—
Total amounts reclassified, net of tax	$	258			$	266



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2017				Nine Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	1,208		^(a)	$	1,211		^(a)
Vehicle fuel derivatives	—			^(b)	67			^(b)
Total, pre-tax	1,208				1,278
Tax benefit	(455		)		(486		)
Total, net of tax	$	753			$	792
Defined benefit pension and postretirement losses:
Amortization of net loss	$	6		^(c)	$	—		^(c)
Total, pre-tax	6				—
Tax benefit	(3		)		—
Total, net of tax	3				—
Total amounts reclassified, net of tax	$	756			$	792


^(a)	Included in interest charges.


^(b)	Included in O&M expenses.


^(c)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including PSCo’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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, trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; actions of credit rating agencies; 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; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

PSCo’s net income was approximately $398.2 million for 2017 year-to-date, compared with approximately $376.8 million for the same period of 2016. The increase is driven by higher electric margin, lower O&M expenses and lower ETR, which were partially offset by increased depreciation expense.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details the electric revenues and margin:



	Nine Months Ended Sept. 30
(Millions of Dollars)	2017			2016
Electric revenues	$	2,319		$	2,338
Electric fuel and purchased power	(857		)	(891		)
Electric margin	$	1,462		$	1,447

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The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues



(Millions of Dollars)	2017 vs. 2016
Fuel and purchased power cost recovery	$	(33	)
Non-fuel riders	5
Trading	4
Earnings test	2
Other, net	3
Total decrease in electric revenues	$	(19	)

Electric Margin



(Millions of Dollars)	2017 vs. 2016
Non-fuel riders	$	5
Trading	3
Earnings test	2
Other, net	5
Total increase in electric margin	$	15

Natural Gas Revenues and Margin

Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:



	Nine Months Ended Sept. 30
(Millions of Dollars)	2017			2016
Natural gas revenues	$	691		$	660
Cost of natural gas sold and transported	(304		)	(270		)
Natural gas margin	$	387		$	390

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the nine months ended Sept. 30:

Natural Gas Revenues



(Millions of Dollars)	2017 vs. 2016
Purchased natural gas adjustment clause recovery	$	33
Infrastructure and integrity rider	9
Retail rate decrease	(5		)
Estimated impact of weather	(4		)
Other, net	(2		)
Total increase in natural gas revenues	$	31

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Natural Gas Margin



(Millions of Dollars)	2017 vs. 2016
Retail rate decrease	$	(5	)
Estimated impact of weather	(4		)
Infrastructure and integrity rider	9
Other, net	(3		)
Total decrease in natural gas margin	$	(3	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $22.9 million, or 4.0 percent, for 2017 year-to-date. The decrease primarily reflects the timing of planned maintenance and overhauls at various generation facilities, the timing of transmission line maintenance and the impact of costs associated with storm damage in 2016, as summarized in the table below:



(Millions of Dollars)	2017 vs. 2016
Plant generation costs	$	(13.1	)
Electric distribution costs	(8.0		)
Transmission costs	(3.1		)
Employee benefits expense	3.2
Other, net	(1.9		)
Total decrease in O&M expenses	$	(22.9	)

DSM Program Expenses — Demand side management (DSM) program expenses increased $4.5 million, or 5.1 percent, for 2017 year-to-date. The increase was due to higher recovery rates. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization — Depreciation and amortization expense increased $20.2 million, or 6.1 percent, for 2017 year-to-date. The increase was primarily attributable to electric and natural gas investments as well as a new enterprise resource planning system.

AFUDC, Equity and Debt — Allowance for funds used during construction (AFUDC) increased $8.3 million for 2017 year-to-date. The increase was primarily due to an increase in wind construction work in progress, particularly Rush Creek.

Income Taxes — Income tax expense increased $1.5 million for 2017 year-to-date. The increase in income tax expense was primarily due to higher pretax earnings, partially offset by increased permanent plant-related adjustments (e.g., AFUDC-equity); a tax benefit for adjustments attributable to the 2016 tax return filed in the third quarter; and a tax expense for state tax credit valuation allowances in 2016. The ETR was 36.2 percent for 2017 year-to-date, compared with 37.3 percent for the same period of 2016. The lower ETR in 2017 was primarily due to the adjustments referenced 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, 2016 and Public Utility Regulation included in Item 2 of PSCo’s Quarterly Report on Form

10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

Rush Creek Wind Ownership Proposal — In 2016, the CPUC granted PSCo a Certificate of Public Convenience and Necessity (CPCN) to build, own and operate a 600 MW wind generation facility in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.

All major contracts required to complete the project have been executed including the Vestas turbine supply and balance of plant agreements. Vestas production tax credit (PTC) components for safe harboring the facility have been fabricated and are currently being stored at Vestas facilities in Colorado. Construction of roads, collection systems, and foundations began in April 2017.

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Colorado Energy Plan (CEP) — In May 2016, PSCo filed its 2016 Electric Resource Plan which included the estimated need for additional generation resources through 2024. In April 2017, the CPUC approved the modeling assumptions that will be used in the Request for Proposal (RFP) process. In August 2017, PSCo filed an updated capacity need with the CPUC of 450 MW.

In August 2017, PSCo, along with various other stakeholders, filed a stipulation agreement proposing the CEP. The major components include:


•	Early retirement of 660 MW of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);


•	An RFP which could result in the addition of up to 1,000 MW of wind, 700 MW solar and 700 MW of natural gas and/or storage;


•	Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;


•	Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;


•	Reduction of the Renewable Energy Standard Adjustment rider, from two percent to one percent, subject to regulatory proceedings, effective beginning 2021 or 2022; and


•	Construction of a new transmission switching station to further the development of renewable generating resources.

In August 2017, PSCo issued an All-Source RFP. Bids are due on Nov. 28, 2017. PSCo anticipates filing its’ recommended portfolios in April 2018. The CPUC is expected to rule on the stipulation agreement in March 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018.

Approval of the CEP could increase the total capital investment up to $1.5 billion.

Advanced Grid Intelligence and Security — In July 2017, the CPUC approved PSCo’s CPCN for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing communications infrastructure. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures.

In June 2017, the CPUC approved a settlement, which delayed the advanced meter deployment from 2017-2021 to 2019-2024. The total capital cost of the project included in the CPCN is approximately $537 million for 2017-2024. As a result of the settlement, approximately $120 million of capital investment was deferred to 2022-2024.

Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism, which would adjust annual revenues based on changes in weather normalized average use per customer for the residential and small commercial classes.

In July 2017, the CPUC issued a decision which approved the following key decisions regarding decoupling:


•	Effective Jan. 1, 2018 through December 2023 (subject to establishing new rates in the next electric rate case);


•	Applicable to the residential class and small commercial class;


•	Based on total class revenues (subject to establishing the base period in the next electric rate case);


•	Based on actual sales; and


•	Subject to a soft cap of 3 percent on any annual adjustment.

In August 2017, the CPUC denied PSCo’s request for reconsideration of the order.

Boulder, Colo. Municipalization — In 2011, in the City of Boulder, Colo. (Boulder), voters passed a ballot measure authorizing the formation of a municipal utility, subject to certain conditions. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility. In 2016, the Colorado Court of Appeals preserved PSCo’s ability to do so. Subsequently, Boulder filed a Petition for Writ of Certiorari with the Colorado Supreme Court. In August 2017, the Colorado Supreme Court granted the petition to review the Colorado Court of Appeals decision.

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In 2015, the Boulder District Court affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated to preserve reliability, safety and effectiveness. Further, the Boulder District Court dismissed the condemnation action Boulder had filed, finding that the CPUC must give approval before Boulder files any future condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time.

Beginning in 2015, Boulder filed multiple separation applications, the most recent one being in May 2017. In June 2017, PSCo and other intervenors filed alternatives to Boulder’s separation plan and opposed certain sharing; contracting and financing aspects of the plan.

In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position, stating PSCo is not required to:


•	Finance Boulder’s municipalization efforts;


•	Design or construct future Boulder electric distribution facilities;


•	Enter into joint use of pole arrangements with Boulder; and


•	Use a third party to design and build facilities.

The CPUC provided conditional approval related to the transfer of some of the electrical distribution assets in Boulder, however subject to completion of certain items, including:


•	Filing an agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;


•	Filing a complete and accurate revised list of distribution assets to be transferred; and


•	Filing an agreement to address numerous aspects of payments from Boulder to PSCo for costs of Boulder’s municipalization efforts.

The CPUC requested those filings be made by Dec. 13, 2017. The CPUC has established a process whereby once those filings are made, additional hearings may be held.

At the end of 2017, several Boulder measures expire absent voter approvals, including the Utility Occupational Tax (UOT) which funds Boulder’s municipalization efforts. In response, Boulder has placed the following measures on the November 2017 ballot:


•	An extension and increase of the UOT for funding Boulder’s exploration of municipalization;


•	Requiring final voter approval prior to Boulder issuing debt to acquire assets and fund the start up of a local electric utility; and


•	Extending Boulder city council’s authority to hold non-public, executive sessions to discuss legal strategy related to municipalization, but not to discuss certain settlement options with PSCo.

Mountain West Transmission Group (MWTG) — PSCo, along with six other transmission owners from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning. In September 2017, the MWTG determined that membership in the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) would provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. If participation with SPP proceeds, the MWTG utilities expect an economic benefit. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.

SPP’s organizational group will address respective findings, objectives and next steps related to MWTG’s consideration of SPP membership. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in mid-2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019, at the earliest.

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Summary of Recent Federal Regulatory Developments

FERC

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, 2016 and Quarterly Report on Form 10-Q for the quarterly periods ended

March 31, 2017 and June 30, 2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

North American Electric Reliability Corporation (NERC) Supply Chain Standards — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remand the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effective on the first calendar quarter that is 18 months after the effective date of the approval. PSCo is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.

Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint Against CPUC — In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge (Magistrate) issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively starts over and PSCo is expected to intervene in the proceeding again. The timing of a resolution in this case is unclear.

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 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 Sept. 30, 2017, 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.

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Internal Control Over Financial Reporting

In 2016, PSCo implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. PSCo initiated deployment of work management systems modules and is continuing to implement additional modules including the conversion of existing work management systems to this same system during 2017. In connection with this ongoing implementation, PSCo is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. PSCo does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

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

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 Part I Item 2 and Note 5 to the consolidated financial statements for a 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, 2016, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 6 — EXHIBITS



*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors



3.01	Amended and Restated Articles of Incorporation dated July 15, 1998.
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)).
10.1*+	Fourth Amendment to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to Form 10-Q of Xcel Energy for the quarter ended Sept. 30, 2017 (file no. 001-03034)).
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 Sept. 30, 2017 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

Oct. 27, 2017	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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

Sept. 30, 2017

Dec. 31, 2016

Megawatt hours of electricity

Million British thermal units of natural gas