UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 20172018
or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-3280
Public Service Company of Colorado
(Exact name of registrant as specified in its charter)
Colorado 84-0296600
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
   
1800 Larimer, Suite 1100  
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
(303) 571-7511
(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 July 28, 201727, 2018
Common Stock, $0.01 par value 100 shares

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

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
 
   
Item l —
Item 2 —
Item 4 —
   
PART II — OTHER INFORMATION
 
   
Item 1 —
Item 1A —
Item 6 —
   

  
Certifications Pursuant to Section 3021
Certifications Pursuant to Section 9061
Statement Pursuant to Private Litigation1

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).

PART I — FINANCIAL INFORMATION

Item 1FINANCIAL STATEMENTS

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands)
Three Months Ended June 30 Six Months Ended June 30Three Months Ended June 30 Six Months Ended June 30
2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Electric$729,920
 $722,569
 $1,441,308
 $1,440,031
$716,195
 $729,920
 $1,414,469
 $1,441,308
Natural gas192,777
 178,481
 548,913
 506,975
186,661
 192,777
 550,647
 548,913
Steam and other8,219
 8,802
 21,229
 20,687
9,010
 8,219
 20,048
 21,229
Total operating revenues930,916
 909,852
 2,011,450
 1,967,693
911,866
 930,916
 1,985,164
 2,011,450
              
Operating expenses 
  
     
  
    
Electric fuel and purchased power279,522
 275,955
 568,349
 571,885
271,891
 279,522
 553,061
 568,349
Cost of natural gas sold and transported70,258
 59,327
 266,660
 227,803
58,559
 70,258
 249,824
 266,660
Cost of sales — steam and other3,507
 3,429
 7,893
 7,210
3,664
 3,507
 7,540
 7,893
Operating and maintenance expenses187,907
 200,946
 373,508
 379,332
188,991
 187,394
 372,066
 372,482
Demand side management expenses29,928
 29,356
 58,032
 57,079
33,202
 29,928
 65,954
 58,032
Depreciation and amortization117,513
 109,909
 232,507
 218,790
116,553
 117,513
 238,160
 232,507
Taxes (other than income taxes)49,470
 50,301
 99,268
 101,775
49,743
 49,470
 102,400
 99,268
Total operating expenses738,105
 729,223
 1,606,217
 1,563,874
722,603
 737,592
 1,589,005
 1,605,191
              
Operating income192,811
 180,629
 405,233
 403,819
189,263
 193,324
 396,159
 406,259
              
Other income, net1,832
 844
 5,549
 1,293
799
 1,319
 1,030
 4,523
Allowance for funds used during construction — equity6,341
 4,053
 10,949
 8,371
13,555
 6,341
 24,499
 10,949
              
Interest charges and financing costs 
  
     
  
    
Interest charges — includes other financing costs of $1,543, $1,725, $3,064 and
$3,464, respectively
46,424
 46,570
 92,306
 92,318
Interest charges — includes other financing costs of $1,601 and $1,543, $3,173, and $3,064 respectively51,221
 46,424
 101,142
 92,306
Allowance for funds used during construction — debt(2,438) (1,617) (4,344) (3,227)(5,205) (2,438) (9,786) (4,344)
Total interest charges and financing costs43,986
 44,953
 87,962
 89,091
46,016
 43,986
 91,356
 87,962
              
Income before income taxes156,998
 140,573
 333,769
 324,392
157,601
 156,998
 330,332
 333,769
Income taxes56,411
 53,229
 121,636
 121,174
35,305
 56,411
 74,314
 121,636
Net income$100,587
 $87,344
 $212,133
 $203,218
$122,296
 $100,587
 $256,018
 $212,133
 
See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)
 Three Months Ended June 30 Six Months Ended June 30 Three Months Ended June 30 Six Months Ended June 30
 2017 2016 2017 2016 2018 2017 2018 2017
Net income $100,587
 $87,344
 $212,133
 $203,218
 $122,296
 $100,587
 $256,018
 $212,133
                
Other comprehensive income (loss)      
  
      
  
                
Pension and retiree medical benefits:                
Amortization of losses (gains) included in net periodic benefit cost,
net of tax of $1, $1, $2 and $(134), respectively
 1
 2
 2
 (217)
Amortization of losses included in net periodic benefit cost, net of tax of $0, $1, $0, and $2, respectively 2
 1
 4
 2
                
Derivative instruments:      
  
      
  
Net fair value increase, net of tax of $0, $3, $0, and $2, respectively
 
 4
 
 2
Reclassification of losses to net income, net of tax of $153, $161, $305, and $324, respectively 250
 262
 496
 526
Reclassification of losses to net income, net of tax of $99, $153, $197 and $305, respectively 303
 250
 603
 496
                
Other comprehensive income 251
 268
 498
 311
 305
 251
 607
 498
Comprehensive income $100,838
 $87,612
 $212,631
 $203,529
 $122,601
 $100,838
 $256,625
 $212,631

See Notes to Consolidated Financial Statements


PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
Six Months Ended June 30Six Months Ended June 30
2017 20162018 2017
Operating activities      
Net income$212,133
 $203,218
$256,018
 $212,133
Adjustments to reconcile net income to cash provided by operating activities: 
  
 
  
Depreciation and amortization234,143
 220,027
240,577
 234,143
Demand side management program amortization672
 1,466

 672
Deferred income taxes126,252
 126,796
25,579
 126,252
Amortization of investment tax credits(1,401) (1,402)(1,399) (1,401)
Allowance for equity funds used during construction(10,949) (8,371)(24,499) (10,949)
Net realized and unrealized hedging and derivative transactions1,951
 (372)(1,917) 1,951
Other
 (388)1
 
Changes in operating assets and liabilities: 
  
 
  
Accounts receivable24,042
 55,101
21,991
 24,042
Accrued unbilled revenues81,649
 69,983
66,497
 81,649
Inventories38,452
 39,833
44,769
 38,452
Prepayments and other(4,837) 34,979
1,522
 (4,837)
Accounts payable(51,894) (22,032)(22,097) (51,894)
Net regulatory assets and liabilities(2,499) (37,452)30,405
 (2,499)
Other current liabilities(67,418) (72,786)(119,132) (67,418)
Pension and other employee benefit obligations(16,543) (15,676)(27,457) (16,543)
Change in other noncurrent assets(717) (337)3,880
 (717)
Change in other noncurrent liabilities(228) (18,169)(14,546) (228)
Net cash provided by operating activities562,808
 574,418
480,192
 562,808
      
Investing activities 
  
 
  
Utility capital/construction expenditures(609,369) (524,086)(825,463) (609,369)
Proceeds from insurance recoveries
 608
Allowance for equity funds used during construction10,949
 8,371
24,499
 10,949
Investments in utility money pool arrangement(777,000) (437,000)(198,000) (777,000)
Repayments from utility money pool arrangement625,000
 437,000
56,000
 625,000
Other, net(657) (1,460)
 (657)
Net cash used in investing activities(751,077) (516,567)(942,964) (751,077)
      
Financing activities 
  
 
  
Repayments of short-term borrowings, net(129,000) (14,000)
 (129,000)
Borrowings under utility money pool arrangement40,000
 123,000
526,000
 40,000
Repayments under utility money pool arrangement(40,000) (83,000)(526,000) (40,000)
Proceeds from issuance of long-term debt394,611
 244,830
692,697
 394,611
Repayments of long-term debt
 (129,500)
Capital contributions from (to) parent82,475
 (31,162)
Capital contributions from parent216,508
 82,475
Dividends paid to parent(161,312) (167,288)(171,546) (161,312)
Other(110) 
(118) (110)
Net cash provided by (used in) financing activities186,664
 (57,120)
Net cash provided by financing activities737,541
 186,664
      
Net change in cash and cash equivalents(1,605) 731
274,769
 (1,605)
Cash and cash equivalents at beginning of period5,926
 3,585
7,513
 5,926
Cash and cash equivalents at end of period$4,321
 $4,316
$282,282
 $4,321
      
Supplemental disclosure of cash flow information: 
  
 
  
Cash paid for interest (net of amounts capitalized)$(84,452) $(87,649)$(88,912) $(84,452)
Cash (paid) received for income taxes, net(12,195) 40,849
Cash paid for income taxes, net(96,448) (12,195)
Supplemental disclosure of non-cash investing transactions: 
  
 
  
Property, plant and equipment additions in accounts payable$103,774
 $75,934
$131,823
 $103,774

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)
June 30, 2017 Dec. 31, 2016June 30, 2018 Dec. 31, 2017
Assets      
Current assets      
Cash and cash equivalents$4,321
 $5,926
$282,282
 $7,513
Accounts receivable, net278,981
 304,900
272,293
 294,403
Accounts receivable from affiliates17,269
 9,421
38,650
 14,719
Investments in utility money pool arrangement152,000
 
162,000
 20,000
Accrued unbilled revenues215,429
 297,078
229,304
 295,801
Inventories166,938
 202,220
169,720
 214,489
Regulatory assets79,221
 103,783
76,419
 77,337
Derivative instruments4,190
 10,934
5,340
 3,197
Prepayments and other39,396
 34,559
39,237
 35,720
Total current assets957,745
 968,821
1,275,245
 963,179
      
Property, plant and equipment, net13,265,886
 12,849,799
14,541,078
 14,025,751
      
Other assets 
  
 
  
Regulatory assets966,270
 958,429
980,811
 950,258
Derivative instruments888
 3,398
2,716
 1,009
Other27,362
 25,637
23,259
 27,429
Total other assets994,520
 987,464
1,006,786
 978,696
Total assets$15,218,151
 $14,806,084
$16,823,109
 $15,967,626
      
Liabilities and Equity 
  
 
  
Current liabilities 
  
 
  
Current portion of long-term debt$5,303
 $5,270
$705,869
 $305,577
Short-term debt
 129,000
Accounts payable362,799
 376,186
433,822
 492,829
Accounts payable to affiliates40,034
 98,797
38,395
 58,749
Regulatory liabilities87,657
 101,110
95,053
 66,126
Taxes accrued99,774
 171,862
108,812
 222,517
Accrued interest49,290
 48,619
49,803
 48,552
Dividends payable to parent83,978
 74,208
100,338
 76,195
Derivative instruments6,259
 6,788
5,428
 7,348
Other74,509
 73,022
92,583
 92,333
Total current liabilities809,603
 1,084,862
1,630,103
 1,370,226
      
Deferred credits and other liabilities 
  
 
  
Deferred income taxes3,021,402
 2,889,129
1,678,207
 1,644,476
Deferred investment tax credits29,260
 30,661
26,459
 27,858
Regulatory liabilities505,132
 512,933
1,926,944
 1,933,488
Asset retirement obligations295,648
 289,563
355,028
 347,769
Derivative instruments5,259
 7,828
2,471
 3,468
Customer advances160,021
 162,742
170,659
 162,614
Pension and employee benefit obligations269,306
 285,774
260,012
 287,783
Other61,383
 62,201
49,454
 58,923
Total deferred credits and other liabilities4,347,411
 4,240,831
4,469,234
 4,466,379
      
Commitments and contingencies

 



 

Capitalization 
  
 
  
Long-term debt4,604,528
 4,210,936
4,594,193
 4,302,698
Common stock — 100 shares authorized at $0.01 par value; 100 shares
outstanding at June 30, 2017 and Dec. 31, 2016, respectively

 
Common stock — 100 shares authorized at $0.01 par value; 100 shares
outstanding at June 30, 2018 and Dec. 31, 2017, respectively

 
Additional paid in capital3,778,821
 3,633,216
4,273,146
 4,032,826
Retained earnings1,700,290
 1,659,239
1,882,558
 1,822,229
Accumulated other comprehensive loss(22,502) (23,000)(26,125) (26,732)
Total common stockholder’s equity5,456,609
 5,269,455
6,129,579
 5,828,323
Total liabilities and equity$15,218,151
 $14,806,084
$16,823,109
 $15,967,626

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of June 30, 20172018 and Dec. 31, 2016;2017; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 20172018 and 2016;2017; and its cash flows for the six months ended June 30, 20172018 and 2016.2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 20172018 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, 20162017 balance sheet information has been derived from the audited 20162017 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2016.2017. 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, 2016,2017, filed with the SEC on Feb. 24, 2017.23, 2018. 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, 2016,2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.Accounting Pronouncements

Recently Issued

Revenue RecognitionLeases — I In May 2014,n February 2016, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers,Leases, Topic 606842 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of revenue. PSCo expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs. PSCo has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. 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 tostandard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). On Jan. 1, 2017 that are currently2019 agreements considered leases are expected to be recognized onfor 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-fueledfossil-fueled generating facilities.facilities are expected to be recognized on the consolidated balance sheet.

Recently Adopted

Revenue Recognition In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. PSCo expects that similar agreements enteredimplemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on PSCo’s consolidated financial statements. For related disclosures, see Note 13 to the consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, will generally qualify as leases underthe FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, but hasother than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. PSCo implemented the guidance on Jan. 1, 2018 and the implementation did not yet completedhave a material impact on its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.consolidated financial statements.



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 has not yet fully determined the impacts of adoption of the standard, but expects that asAs a result of the application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the currenthistorical 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. ThisPSCo implemented the new guidance will be effectiveon Jan. 1, 2018, and as a result, $1.0 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for interim and annual reportingthe six months ended June 30, 2017. Under a practical expedient permitted by the standard, PSCo used benefit cost amounts disclosed for prior periods beginning after Dec. 15, 2017.as the basis for retrospective application.

3.Selected Balance Sheet Data
(Thousands of Dollars) June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
Accounts receivable, net        
Accounts receivable $298,371
 $324,512
 $290,832
 $314,009
Less allowance for bad debts (19,390) (19,612) (18,539) (19,606)
 $278,981
 $304,900
 $272,293
 $294,403
(Thousands of Dollars) June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
Inventories        
Materials and supplies $71,245
 $66,161
 $70,940
 $68,940
Fuel 54,485
 66,429
 62,532
 73,893
Natural gas 41,208
 69,630
 36,248
 71,656
 $166,938
 $202,220
 $169,720
 $214,489
(Thousands of Dollars) June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
Property, plant and equipment, net        
Electric plant $12,455,436
 $12,304,436
 $12,780,963
 $12,627,592
Natural gas plant 3,826,695
 3,710,772
 4,211,977
 4,102,075
Common and other property 930,588
 919,955
 1,040,638
 1,022,333
Plant to be retired (a)
 17,820
 31,839
 10,306
 10,949
Construction work in progress 658,741
 484,340
 1,444,140
 1,014,338
Total property, plant and equipment 17,889,280
 17,451,342
 19,488,024
 18,777,287
Less accumulated depreciation (4,623,394) (4,601,543) (4,946,946) (4,751,536)
 $13,265,886
 $12,849,799
 $14,541,078
 $14,025,751

(a) 
In the second halfthird quarter of 2017, PSCo expects to both early retireretired Valmont Unit 5 and convertconverted 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, 20162017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.


Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:
  Six Months Ended June 30
  2018 2017
Federal statutory rate 21.0 % 35.0 %
State tax, net of federal tax effect 3.7
 3.0
Increases (decreases) in tax from: 
 
Regulatory differences - ARAM (a)
 (3.2) (0.1)
Regulatory differences - ARAM deferral (b)
 3.0
 
Regulatory differences - other utility plant items (1.3) (0.9)
Tax credits, net of federal income tax expense (1.0) (0.7)
Other, net 0.3
 0.1
Effective income tax rate 22.5 % 36.4 %

(a)
The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.
(b)
As we receive direction from our regulatory commissions regarding the return of excess deferred taxes (to our customers resulting from the Tax Cuts and Jobs Act
(TCJA)), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue.

Federal Audits  PSCoPSCO 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 2013 federal income tax returns following extensions, expires in December 2017.expire as follows:
Tax Year(s)Expiration
2009 - 2011December 2018
2012 - 2014October 2019
2015September 2019
2016September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including athe 2009 carryback claim. The IRS has proposed an adjustment to the federal tax loss carryback claims that would resultand in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015, claims. In 2016 the IRS audit team and Xcel Energy presented their casesforwarded the issue to the Office of Appeals; however,Appeals (Appeals). In 2017 Xcel Energy and Appeals reached an agreement and the outcome and timing of a resolution is uncertain.benefit related to the agreed upon portions was recognized. PSCo isdid not expected to accrue any income tax expensebenefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the secondthird quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment to tax year 2012 that maywould impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy is evaluatingfiled a protest with the IRS’ proposalIRS. As of June 30, 2018, the case has been forwarded to Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain.unknown.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2017,2018, 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) June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions $3.1
 $2.9
 $4.4
 $4.0
Unrecognized tax benefit — Temporary tax positions 17.8
 16.8
 5.0
 6.1
Total unrecognized tax benefit $20.9
 $19.7
 $9.4
 $10.1

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) June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
NOL and tax credit carryforwards $(6.7) $(5.8) $(4.7) $(4.0)

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 audit progressthe IRS and state audits resume. As the IRS Appeals progresses and the IRS audit progress,resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $11$8 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 payableThe payables for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars) June 30, 2017 Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period $(1.1) $(0.4)
Interest expense related to unrecognized tax benefits recorded during the period (0.4) (0.7)
Payable for interest related to unrecognized tax benefits at end of period $(1.5) $(1.1)

at June 30, 2018, and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 20172018 or Dec. 31, 2016.2017.


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, 20162017 and in Note 5 to the consolidated financial statements to PSCo’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017,2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

PendingTax Reform Regulatory Proceedings

The specific impacts of the TCJA on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas, including Colorado, have opened dockets to address the impacts of the TCJA.

Colorado Natural Gas — In February 2018, the administrative law judge (ALJ) approved PSCo and Recently Concluded Regulatory Proceedings —the Colorado Public Utilities Commission (CPUC) Staff’s TCJA settlement agreement which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up would provide customers the full net benefit of the TCJA retroactive to January 2018.

Colorado Electric— In April 2018, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) filed a TCJA settlement agreement that recommended a customer refund of $42 million in 2018, with the remainder of $59 million be used to accelerate the amortization of an existing prepaid pension asset.  In June 2018, the CPUC approved the customer refund of $42 million, effective June 1, 2018. The CPUC set the decision regarding the remainder of the $59 million for hearing before an ALJ. Revisions to the TCJA settlement will be addressed in a future electric rate case.


Pending Regulatory Proceedings — CPUC

Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request was based on forecast test years (FTY), a 10.0 percent return on equity (ROE) and an equity ratio of 55.25 percent. Interim rates, subject to refund and interest, were to be effective on June 1, 2018.
Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total
Revenue request $74
 $75
 $60
 $36
 $245
Clean Air Clean Jobs Act (CACJA) rider conversion to base rates 90
 
 
 
 90
Transmission Cost Adjustment (TCA) rider conversion to base rates 43
 
 
 
 43
  Total $207
 $75
 $60
 $36
 $378
           
Expected year-end rate base (billions of dollars) $6.8
 $7.1
 $7.3
 $7.4
  
In March 2018, PSCo, CPUC Staff and OCC reached a settlement and filed a motion with the CPUC requesting changes to the procedural schedule and scope of the electric case, which included delaying the implementation of provisional rates from June 2018 to January 2019 and requiring PSCo to file updated test year information for 2019 through 2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case.

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 to recover capital investments and increased operating costs since PSCo’s previous case in 2015.approximately $139 million over three years. The request, detailed below, iswas based on forecast test years,FTYs, a 10.0 percent return on equity (ROE)ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars) 2018 2019 2020 Total
New 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
 N/A
Revenue Request (Millions of Dollars) 2018 2019 2020 Total
Revenue request $63
 $33
 $43
 $139
Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates (a)
 
 94
 
 94
Total $63
 $127
 $43
 $233
         
Expected year-end rate base (billions of dollars) (b)
 $1.5
 $2.3
 $2.4
  
(a)
The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.
(b)
The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.

In February 2018, the administrative law judge (ALJ) approved a TCJA settlement agreement between PSCo and the CPUC Staff, which reduced provisional rates by $20 million, based on a preliminary TCJA estimate of $29 million. The settlement remains subject to CPUC approval. The impact of the TCJA will be trued-up later in 2018. Annualized provisional rates of approximately $43 million were effective March 1, 2018.

In May 2018, the ALJ issued an interim recommended decision which would result in a 2018 overall rate increase of approximately $46 million, prior to the impact of the TCJA. The estimated rate increase reflects a 2016 HTY with a 13-month average rate base of $1.6 billion, a ROE of 9.35 percent and an equity ratio of 54.2 percent.
On July 12, 2018, the CPUC deliberated and approved several of the ALJ’s recommendations including application of a 2016 HTY, with a 13-month average rate base, and an ROE of 9.35 percent.  The CPUC adjusted the equity ratio to 54.6 percent and provided no return on the prepaid pension and retiree medical asset.  With these adjustments the total rate increase, prior to TCJA impacts, would be $47 million.


(a) The roll-inestimated impact of PSIA rider revenue into base rates will not have an impactthe CPUC’s decision is presented below:
(Millions of Dollars) Estimated Impact of the CPUC’s Decision
Filed 2018 revenue request based on a FTY $63
Impact of the change in test year 5
PSCo’s deficiency based on a 2016 HTY - year-end rate base 68
   
Adjustments:  
  ROE at 9.35 percent (9)
Equity ratio of 54.6 percent (2)
Change in amortization period for certain regulatory assets, including a debt return (6)
Loss of return on prepaid pension and retiree medical (4)
Change from 2016 year-end to average rate base (5)
Other, net 5
Total adjustments (21)
   
Total rate increase, prior to the TCJA impacts 
 $47
The CPUC is expected to issue its order on customer bills or total revenue as these costs are already being recovered from customers through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of new, incremental PSIA related investments in 2019 and 2020 are includednatural gas rate case in the base rate request.third quarter of 2018. The CPUC is expected to issue a final decision with the impacts of the TCJA, later in 2018.

(b) The additional rate base in 2019 predominantly reflects the roll-inProvisional rates, subject to refund, were implemented on Jan. 1, 2018. A current liability which represents PSCo’s best estimate of capitala refund obligation associated with the PSIA rider.

Finalprovisional rates are expected to be effective in February 2018. In conjunction with the multi-year base rate step increases, PSCo is also proposing a stay-out provision and an earnings test through the end of 2020.

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. In July 2017, the CPUC approved PSCo’s 2016 earnings test, which does not result in any earnings sharing. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liabilitywas recorded as of June 30, 2017.2018.

PSIA Rider
In June 2018, PSCo filed for an extension to the PSIA rider through 2020. PSCo requested an expedited decision by Nov. 15, 2018. PSCo also requested authorization to roll-in recovery of costs in the current PSIA rider into base rates effective Jan. 1, 2019, if the CPUC rejects the proposed PSIA extension or fails to rule on the request by the end of 2018.

Additionally, PSCo reduced PSIA revenues by approximately $8 million for 2018 for the impact of the TCJA, effective May 1, 2018. PSIA revenues are subject to the CPUC approved PSIA rider true-up process.

6.Commitments and Contingencies

Except to the extent noted below and in Note 5 above,to the consolidated financial statements, 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, 20162017 and in Notes 5 and 6 to the
consolidated financial statements included in PSCo’s Quarterly Report on Form 10-Q for the quarterly period ended March
31, 2016,2018, 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 megawattsMegawatts (MW) of capacity under long-term PPAs as of June 30, 20172018 and Dec. 31, 2016,2017, 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 various expiration dates through 2032.


Environmental Contingencies

Manufactured Gas Plant (MGP), Landfill or Disposal Sites — PSCo is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. PSCo has identified threefour sites where former MGP disposal activities have or may have resulted in site contamination is present and are under currentwhere investigation and/or remediation. At some or all of these sites, thereremediation activities are currently underway. Other parties may be parties that have responsibility for some portion of any remediation.the investigation and/or remediation activities. PSCo anticipates that the majority of thethese investigation or remediation at these sitesactivities will continue through at least 2018. PSCo had accrued $1.7$2 million as of June 30, 2018 and an immaterial amount as of Dec. 31, 2017, for these sites at June 30, 2017 and Dec. 31, 2016, respectively.sites. There may be insurance recovery and/or recovery from other potentially responsible parties tothat will offset any costs incurred. PSCo anticipates that any significant amounts incurredspent will be fully 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 expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The final rule will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. 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 by the end of 2017.

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.”

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 to hold the litigation in abeyance until June 27, 2017, and is considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, to determine whether and how the court continues or ends the stay that currently applies to the CPP. On June 9, 2017, the EPA submitted a proposed rule to the Office of Management and Budget entitled “Review of the Clean Power Plan.”

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. ThePSCo meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, howeverArea. PSCo’s scheduled retirement of its coal fired plants in the Denver that began in 2011 and will be completed in August 2017, should help in anynon-attainment area helped Colorado’s plan to mitigate non-attainment. In June 2017,2018, the EPA announceddesignated the parts of the Denver Metropolitan Area that it is delaying designations of nonattainment areas undercurrently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone NAAQSstandard. Colorado will continue to October 2018consider further reductions that are available in the non-attainment area as it develops plans to allow itmeet the ozone standards. The gas plants that operate in PSCo’s non-attainment area may be required to complete its reviewimprove or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of the 2015 ozone NAAQS.future Colorado state plans.

Legal Contingencies

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

Employment, Tort and Commercial Litigation

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver StateDistrict 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 involvesinvolved claims by over fifty developers. In May 2016,February 2018, the district court granted PSCo’s motionColorado Supreme Court denied DRC’s petition to dismissappeal the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the district court’sDenver District Court’s dismissal of the lawsuit, andeffectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to 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.Appeals. It is uncertain whether the Colorado Supreme Courtwhen a decision 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 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 Denver District Court in August 2016. DRC has requested a hearing for oral arguments, which has yet to be granted or set by the Denver District Court.rendered regarding this appeal.

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 June 30, 2017 Year Ended Dec. 31, 2016 Three Months Ended June 30, 2018 Year Ended Dec. 31, 2017
Borrowing limit $250
 $250
 $250
 $250
Amount outstanding at period end 
 
 
 
Average amount outstanding 
 21
 60
 
Maximum amount outstanding 
 141
 156
 20
Weighted average interest rate, computed on a daily basis N/A
 0.73% 1.84% 0.92%
Weighted average interest rate at period end N/A
 N/A
 N/A
 N/A

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for PSCo was as follows:
(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2017 Year Ended Dec. 31, 2016 Three Months Ended June 30, 2018 Year Ended Dec. 31, 2017
Borrowing limit $700
 $700
 $700
 $700
Amount outstanding at period end 
 129
 
 
Average amount outstanding 109
 24
 84
 54
Maximum amount outstanding 260
 154
 257
 268
Weighted average interest rate, computed on a daily basis 1.19% 0.70% 2.17% 1.08%
Weighted average interest rate at period end N/A
 0.95
 N/A
 N/A

Letters of Credit PSCo uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At each of June 30, 20172018 and Dec. 31, 2016,2017, 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 June 30, 2017,2018, PSCo had the following committed credit facility available (in millions of dollars):
Credit Facility (a)
Credit Facility (a)
 
Drawn (b)
 Available
Credit Facility (a)
 
Drawn (b)
 Available
$700
 $3
 $697
700
 $4
 $696

(a)    This credit facility expires in June 2021.
(b)    Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at June 30, 20172018 and Dec. 31, 2016.2017.

Long-Term Borrowings

PSCo issued $400$350 million of 3.803.70 percent first mortgage green bonds due June 15, 2047.2028 and $350 million of 4.10 percent first mortgage green bonds due June 15, 2048.


8.Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value (NAV).value.


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 June 30, 2017,2018, accumulated other comprehensive losses related to interest rate derivatives included $1.0$1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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


PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in 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 tohad no income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2016.2018 and 2017.

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

The following table details the gross notional amounts of commodity forwards and options at June 30, 20172018 and Dec. 31, 2016:2017:
(Amounts in Thousands) (a)(b)
 June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
Megawatt hours of electricity 10,690
 6,283
 20,813
 22,260
Million British thermal units of natural gas 17,677
 42,203
 18,798
 13,410

(a) 
Amounts are not reflective of net positions in the underlying commodities.
(b) 
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.


The following tables detail the impact of derivative activity during the three months ended June 30, 20172018 and 2016,2017 on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
 Three Months Ended June 30, 2017  Three Months Ended June 30, 2018 
 
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
    
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
  
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 $
 $
 $403
(a) 
$
 $
  $
 $
 $402
(a) 
$
 $
 
Total $
 $
 $403
 $
 $
  $
 $
 $402
 $
 $
 
Other derivative instruments                      
Commodity trading $
 $
 $
 $
 $(192)
(c) 
 $
 $
 $
 $
 $200
(b) 
Natural gas commodity 
 (1,621) 
 
 
  
 (249) 
 
 
(c) 
Total $
 $(1,621) $
 $
 $(192)  $
 $(249) $
 $
 $200
 
            
  Six Months Ended June 30, 2017 
  
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
 
Pre-Tax Gains (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)
  
Derivatives designated as cash flow hedges           
Interest rate $
 $
 $801
(a) 
$
 $
 
Total $
 $
 $801
 $
 $
 
Other derivative instruments  
         
Commodity trading $
 $
 $
 $
 $187
(c) 
Natural gas commodity 
 (7,008) 
 282
(d) 
(2,990)
(d) 
Total $
 $(7,008) $
 $282
 $(2,803) 
           
           
 Three Months Ended June 30, 2016  Six Months Ended June 30, 2018 
 
Pre-Tax Fair Value
Gains Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
    
Pre-Tax Fair Value
Losses Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
 
Pre-Tax (Gains) 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 Gains
Recognized
During the Period
in Income
  
Accumulated
Other
Comprehensive
Loss
 
Regulatory
(Assets) and
Liabilities
 
Accumulated
Other
Comprehensive
Loss
 
Regulatory
Assets and
(Liabilities)
 
Derivatives designated as cash flow hedges                      
Interest rate $
 $
 $402
(a) 
$
 $
  $
 $
 $800
(a) 
$
 $
 
Vehicle fuel and other commodity 7
 
 21
(b) 

 
 
Total $7
 $
 $423
 $
 $
  $
 $
 $800
 $
 $
 
Other derivative instruments             
         
Commodity trading $
 $
 $
 $
 $211
(c) 
 $
 $
 $
 $
 $724
(b) 
Natural gas commodity 
 5,626
 
 

25
(d) 
 
 (420) 
 2,749
(c) 
(1,581)
(c) 
Total $
 $5,626
 $
 $
 $236
  $
 $(420) $
 $2,749
 $(857) 

           
 Six Months Ended June 30, 2016  Three Months Ended June 30, 2017 
 
Pre-Tax Fair Value
Gains Recognized
During the Period in:
 
Pre-Tax Losses
Reclassified into Income
During the Period from:
    
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 (Losses)
Recognized
During the Period
in Income
  
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 $
 $
 $804
(a) 
$
 $
  $
 $
 $403
(a) 
$
 $
 
Vehicle fuel and other commodity 4
 
 46
(b) 

 
 
Total $4
 $
 $850
 $
 $
  $
 $
 $403
 $
 $
 
Other derivative instruments                      
Commodity trading $
 $
 $
 $
 $228
(c) 
 $
 $
 $
 $
 $(192)
(b) 
Natural gas commodity 
 3,677
 
 7,736
(d) 
(3,236)
(d) 
 
 (1,621) 
 
 
(c) 
Total $
 $3,677
 $
 $7,736
 $(3,008)  $
 $(1,621) $
 $
 $(192) 
  Six Months Ended June 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 Gains (Losses)
Recognized
During the Period
in Income
 
Derivatives designated as cash flow hedges           
Interest rate $
 $
 $801
(a) 
$
 $
 
Total $
 $
 $801
 $
 $
 
Other derivative instruments           
Commodity trading $
 $
 $
 $
 $187
(b) 
Natural gas commodity 
 (7,008) 
 282
(c) 
(2,990)
(c) 
Total $
 $(7,008) $
 $282
 $(2,803) 

(a) 
RecordedAmounts are recorded to interest charges.
(b) 
RecordedAmounts are recorded to operating and maintenance (O&M) expenses.
(c)
interest charges. 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)(c) 
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 six months ended June 30, 2018 included no settlement gains or losses and $1.2 million of settlement losses, respectively. Amounts for the three and six months ended June 30, 2017 included no settlement gains or losses and $0.9 million of settlement gains, respectively. Amounts for the three and six months ended June 30, 2016 included an immaterial amount of settlement losses. The remaining derivative settlement gains and losses for the six months ended June 30, 20172018 and 20162017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 20172018 and 2016.2017. 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 June 30, 2017, five2018, four of PSCo’s 10 most significant counterparties for these activities, comprising $5.9$27.6 million or 1047 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. FourFive of the 10 most significant counterparties, comprising $21.7$12.2 million or 3721 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. Another of theseThe one remaining significant counterparties,counterparty, comprising $0.7$5.2 million or 19 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. EightNine of these significant counterparties are municipal or cooperative electric entities, or other utilities.


Credit Related Contingent Features  Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unablePSCo’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 maintain its credit ratings.payment terms or other covenants. At June 30, 20172018 and Dec. 31, 2016,2017, there were no derivative instruments in a material liability position with such underlying contract provisions that required the posting of collateral or settlement of outstanding contracts if the credit ratings of PSCo were downgraded below investment grade.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 June 30, 20172018 and Dec. 31, 2016.2017.

Recurring Fair Value Measurements  The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at June 30, 2017:2018:

 June 30, 2017 June 30, 2018
 Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
   Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Current derivative assets                        
Other derivative instruments:                        
Commodity trading $702
 $4,013
 $2
 $4,717
 $(3,220) $1,497
 $332
 $12,812
 $118
 $13,262
 $(9,729) $3,533
Natural gas commodity 
 977
 
 977
 
 977
 
 919
 
 919
 
 919
Total current derivative assets $702
 $4,990
 $2
 $5,694
 $(3,220) 2,474
 $332
 $13,731
 $118
 $14,181
 $(9,729) 4,452
PPAs (a)
           1,716
           888
Current derivative instruments           $4,190
           $5,340
Noncurrent derivative assets                        
Other derivative instruments:            
Commodity trading $1
 $2,715
 $
 $2,716
 $
 $2,716
Total noncurrent derivative assets $1
 $2,715
 $
 $2,716
 $
 2,716
PPAs (a)
           888
           
Noncurrent derivative instruments           $888
           $2,716
Current derivative liabilities            
Other derivative instruments:            
Commodity trading $333
 $3,986
 $1
 $4,320
 $(3,220) $1,100
Total current derivative liabilities $333
 $3,986
 $1
 $4,320
 $(3,220) 1,100
PPAs (a)
           5,159
Current derivative instruments           $6,259
Noncurrent derivative liabilities            
Other derivative instruments:            
Commodity trading $
 $11
 $
 $11
 $
 $11
Total noncurrent derivative liabilities $
 $11
 $
 $11
 $
 11
PPAs (a)
           5,248
Noncurrent derivative instruments           $5,259


  June 30, 2018
  Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative liabilities            
Other derivative instruments:            
Commodity trading $333
 $12,409
 $
 $12,742
 $(12,474) $268
Total current derivative liabilities $333
 $12,409
 $
 $12,742
 $(12,474) 268
PPAs (a)
           5,160
Current derivative instruments           $5,428
Noncurrent derivative liabilities            
Other derivative instruments:            
Commodity trading $
 $2,382
 $
 $2,382
 $
 $2,382
Total noncurrent derivative liabilities $
 $2,382
 $
 $2,382
 $
 2,382
PPAs (a)
           89
Noncurrent derivative instruments           $2,471

(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 beis being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b) 
PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2017.2018. At June 30, 2017,2018, derivative assets and liabilities include no obligations to return cash collateral orand rights to reclaim cash collateral.collateral of $2.7 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.


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, 2016:2017:
 Dec. 31, 2016 Dec. 31, 2017
 Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
   Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Current derivative assets                        
Other derivative instruments:                        
Commodity trading $1,124
 $5,453
 $
 $6,577
 $(5,137) $1,440
 $528
 $4,488
 $12
 $5,028
 $(3,554) $1,474
Natural gas commodity 
 7,778
 
 7,778
 
 7,778
 
 18
 
 18
 (10) 8
Total current derivative assets $1,124
 $13,231
 $
 $14,355
 $(5,137) 9,218
 $528
 $4,506
 $12
 $5,046
 $(3,564) 1,482
PPAs (a)
           1,716
           1,715
Current derivative instruments           $10,934
           $3,197
Noncurrent derivative assets                        
Other derivative instruments:    
    
  
  
    
    
  
  
Natural gas commodity $
 $1,652
 $
 $1,652
 $
 $1,652
Commodity trading $
 $1,541
 $
 $1,541
 $(563) $978
Total noncurrent derivative assets $
 $1,652
 $
 $1,652
 $
 1,652
 $
 $1,541
 $
 $1,541
 $(563) 978
PPAs (a)
           1,746
           31
Noncurrent derivative instruments           $3,398
           $1,009
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



  Dec. 31, 2017
  Fair Value 
Fair Value
Total
 
Counterparty
Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative liabilities            
Other derivative instruments:            
Commodity trading $446
 $4,285
 $6
 $4,737
 $(3,431) $1,306
Natural gas commodity 
 1,016
 
 1,016
 (10) 1,006
Total current derivative liabilities $446
 $5,301
 $6
 $5,753
 $(3,441) 2,312
PPAs (a)
           5,036
Current derivative instruments           $7,348
Noncurrent derivative liabilities            
Commodity trading $
 $1,362
 $
 $1,362
 $(563) $799
Total noncurrent derivative liabilities $
 $1,362
 $
 $1,362
 $(563) 799
PPAs (a)
           $2,669
Noncurrent derivative instruments           $3,468

(a) 
During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will beis being 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, 2016.2017. At Dec. 31, 2016,2017, 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 $0.1 million of gains recognized in earnings for Level 3 commodity trading derivatives in the three and six months ended June 30, 2018. There were immaterial gains and losses recognized in earnings for Level 3 commodity trading derivatives in the three and six months ended June 30, 2017 and 2016.2017.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 20172018 and 2016.2017.

Fair Value of Long-Term Debt

As of June 30, 20172018 and Dec. 31, 2016,2017, other financial instruments for which the carrying amount did not equal fair value were as follows:
 June 30, 2017 Dec. 31, 2016 June 30, 2018 Dec. 31, 2017
(Thousands of Dollars) 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
Long-term debt, including current portion $4,609,831
 $4,940,862
 $4,216,206
 $4,491,570
 $5,300,062
 $5,464,543
 $4,608,275
 $5,024,840

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 20172018 and Dec. 31, 2016,2017, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.Other Income, Net

Other income, net consisted of the following:
Three Months Ended June 30 Six Months Ended June 30 Three Months Ended June 30 Six Months Ended June 30
(Thousands of Dollars)2017 2016 2017 2016 2018 2017 2018 2017
Interest income$609
 $148
 $984
 $289
 $508
 $609
 $372
 $984
Other nonoperating income1,326
 747
 4,747
 1,080
 483
 1,326
 956
 4,747
Insurance policy expense(103) (51) (182) (76) (73) (103) (150) (182)
Benefits non-service cost (119) (513) (148) (1,026)
Other income, net$1,832
 $844
 $5,549
 $1,293
 $799
 $1,319
 $1,030
 $4,523


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&Moperating and maintenance (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 Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended June 30, 2017          
Three Months Ended June 30, 2018          
Operating revenues (a)(b)
 $729,920
 $192,777
 $8,219
 $
 $930,916
 $716,195
 $186,661
 $9,010
 $
 $911,866
Intersegment revenues 67
 40
 
 (107) 
 76
 79
 
 (155) 
Total revenues $729,987
 $192,817
 $8,219
 $(107) $930,916
 $716,271
 $186,740
 $9,010
 $(155) $911,866
Net income $87,403
 $12,835
 $349
 $
 $100,587
Net income (loss) $101,956
 $20,963
 $(623) $
 $122,296
          
(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended June 30, 2016          
Three Months Ended June 30, 2017          
Operating revenues (a)(b)
 $722,569
 $178,481
 $8,802
 $
 $909,852
 $729,920
 $192,777
 $8,219
 $
 $930,916
Intersegment revenues 61
 33
 
 (94) 
 67
 40
 
 (107) 
Total revenues $722,630
 $178,514
 $8,802
 $(94) $909,852
 $729,987
 $192,817
 $8,219
 $(107) $930,916
Net income (loss) $79,328
 $8,075
 $(59) $
 $87,344
Net income $87,403
 $12,835
 $349
 $
 $100,587
(a)    Operating revenues include $0 and $2 million of affiliate electric revenue for the three months ended June 30, 20172018 and 2016.2017.
(b)    Operating revenues include $1 million of other affiliate revenue for the three months ended June 30, 20172018 and 2016.2017.
(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Regulated
Electric
 Regulated
Natural Gas
 All
Other
 Reconciling
Eliminations
 Consolidated
Total
Six Months Ended June 30, 2017          
Operating revenues (a)(b)
 $1,441,308
 $548,913
 $21,229
 $
 $2,011,450
Six Months Ended June 30, 2018          
Operating revenues from external customers $1,414,469
 $550,647
 $20,048
 $
 $1,985,164
Intersegment revenues 159
 96
 
 (255) 
 188
 143
 
 (331) 
Total revenues $1,441,467
 $549,009
 $21,229
 $(255) $2,011,450
 $1,414,657
 $550,790
 $20,048
 $(331) $1,985,164
Net income $163,547
 $47,318
 $1,268
 $
 $212,133
Net income (loss) $181,507
 $74,675
 $(164) $
 $256,018

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Regulated
Electric
 Regulated
Natural Gas
 All
Other
 Reconciling
Eliminations
 Consolidated
Total
Six Months Ended June 30, 2016          
Operating revenues (a)(b)
 $1,440,031
 $506,975
 $20,687
 $
 $1,967,693
Six Months Ended June 30, 2017    
      
Operating revenues from external customers $1,441,308
 $548,913
 $21,229
 $
 $2,011,450
Intersegment revenues 142
 78
 
 (220) 
 159
 96
 
 (255) 
Total revenues $1,440,173
 $507,053
 $20,687
 $(220) $1,967,693
 $1,441,467
 $549,009
 $21,229
 $(255) $2,011,450
Net income $151,864
 $48,965
 $2,389
 $
 $203,218
 $163,547
 $47,318
 $1,268
 $
 $212,133
(a)    Operating revenues include $1$0 million and $5$1 million of affiliate electric revenue for the six months ended June 30, 20172018 and 2016, respectively.2017.
(b)    Operating revenues include $2 million of other affiliate revenue for the six months ended June 30, 20172018 and 2016.2017.

11.Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)
        
 Three Months Ended June 30 Three Months Ended June 30
 2017 2016 2017 2016 2018 2017 2018 2017
(Thousands of Dollars) Pension Benefits 
Postretirement Health
Care Benefits
 Pension Benefits 
Postretirement Health
Care Benefits
Service cost $6,820
 $6,492
 $192
 $192
 $7,271
 $6,820
 $152
 $192
Interest cost 12,640
 13,853
 4,191
 4,518
Expected return on plan assets (17,134) (17,692) (5,476) (5,575)
Amortization of prior service credit (803) (800) (1,562) (1,562)
Amortization of net loss 7,089
 6,693
 961
 483
Interest cost (a)
 11,814
 12,640
 3,748
 4,191
Expected return on plan assets (a)
 (17,130) (17,134) (5,674) (5,476)
Amortization of prior service credit (a)
 (845) (803) (1,544) (1,562)
Amortization of net loss (a)
 7,815
 7,089
 1,021
 961
Net periodic benefit cost (credit) 8,612
 8,546
 (1,694) (1,944) 8,925
 8,612
 (2,297) (1,694)
Credits not recognized due to the effects of regulation 426
 499
 
 
 895
 426
 
 
Net benefit cost (credit) recognized for financial reporting $9,038
 $9,045
 $(1,694) $(1,944) $9,820
 $9,038
 $(2,297) $(1,694)

        
 Six Months Ended June 30 Six Months Ended June 30
 2017 2016 2017 2016 2018 2017 2018 2017
(Thousands of Dollars) Pension Benefits Postretirement Health
Care Benefits
 Pension Benefits Postretirement Health
Care Benefits
Service cost $13,640
 $12,958
 $384
 $384
 $14,542
 $13,640
 $304
 $384
Interest cost 25,280
 27,702
 8,382
 9,036
Expected return on plan assets (34,268) (35,384) (10,952) (11,150)
Amortization of prior service credit (1,606) (1,607) (3,124) (3,124)
Amortization of net loss 14,178
 13,386
 1,922
 966
Interest cost (a)
 23,628
 25,280
 7,497
 8,382
Expected return on plan assets (a)
 (34,260) (34,268) (11,349) (10,952)
Amortization of prior service credit (a)
 (1,690) (1,606) (3,089) (3,124)
Amortization of net loss (a)
 15,630
 14,178
 2,042
 1,922
Net periodic benefit cost (credit) 17,224
 17,055
 (3,388) (3,888) 17,850
 17,224
 (4,595) (3,388)
Credits not recognized due to the effects of regulation 1,162
 1,265
 
 
 2,370
 1,162
 
 
Net benefit cost (credit) recognized for financial reporting $18,386
 $18,320
 $(3,388) $(3,888) $20,220
 $18,386
 $(4,595) $(3,388)

(a)
The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January 2017,2018, contributions of $150.0$150 million were made across four of Xcel Energy’s pension plans, of which $16.8$22.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2017.2018.


12.Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 20172018 and 20162017 were as follows:
  Three Months Ended June 30, 2018
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at April 1 $(26,165) $(265) $(26,430)
Losses reclassified from net accumulated other comprehensive loss 303
 2
 305
Net current period other comprehensive income 303
 2
 305
Accumulated other comprehensive loss at June 30 $(25,862) $(263) $(26,125)
  Three Months Ended June 30, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at April 1 $(22,534) $(219) $(22,753)
Losses reclassified from net accumulated other comprehensive loss 250
 1
 251
Net current period other comprehensive income 250
 1
 251
Accumulated other comprehensive loss at June 30 $(22,284) $(218) $(22,502)
 Three Months Ended June 30, 2016 Six Months Ended June 30, 2018
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total Gains and Losses on Cash Flow Hedges Defined Benefit and Postretirement Items Total
Accumulated other comprehensive loss at April 1 $(23,574) $(219) $(23,793)
Other comprehensive income before reclassifications 4
 
 4
Accumulated other comprehensive loss at Jan. 1 $(26,465) $(267) $(26,732)
Losses reclassified from net accumulated other comprehensive loss 262
 2
 264
 603
 4
 607
Net current period other comprehensive income 266
 2
 268
 603
 4
 607
Accumulated other comprehensive loss at June 30 $(23,308) $(217) $(23,525) $(25,862) $(263) $(26,125)
  Six Months Ended June 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 496
 2
 498
Net current period other comprehensive income 496
 2
 498
Accumulated other comprehensive loss at June 30 $(22,284) $(218) $(22,502)

  Six Months Ended June 30, 2016
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Gains and Losses on Cash Flow Hedges Total
Accumulated other comprehensive loss at Jan. 1 $(23,836) $
 $(23,836)
Other comprehensive loss before reclassifications 2
 (219) (217)
Losses reclassified from net accumulated other comprehensive loss 526
 2
 528
Net current period other comprehensive loss 528
 (217) 311
Accumulated other comprehensive loss at June 30 $(23,308) $(217) $(23,525)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 20172018 and 20162017 were as follows:
          
 Amounts Reclassified from Accumulated Other
Comprehensive Loss
  Amounts Reclassified from Accumulated Other
Comprehensive Loss
 
(Thousands of Dollars) Three Months Ended June 30, 2017 Three Months Ended June 30, 2016  Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 
Losses on cash flow hedges:  
     
   
Interest rate derivatives $403
(a) 
$402
(a) 
 $402
(a) 
$403
(a) 
Vehicle fuel derivatives 
(b) 
21
(b) 
Total, pre-tax $403
 $423
  402
 403
 
Tax benefit (153) (161)  (99) (153) 
Total, net of tax $250
 $262
  303
 250
 
Defined benefit pension and postretirement losses:          
Amortization of net loss $2
(c) 
$
(c) 
 2
(b) 
2
(b) 
Total, pre-tax 2
 
  2
 2
 
Tax benefit (1) 
  
 (1) 
Total, net of tax 1
 
  2
 1
 
Total amounts reclassified, net of tax $251
 $262
  $305
 $251
 
     
 
Amounts Reclassified from Accumulated
Other Comprehensive Loss
  
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars) Six Months Ended June 30, 2017 Six Months Ended June 30, 2016  Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 
Losses on cash flow hedges:          
Interest rate derivatives $801
(a) 
$804
(a) 
 $800
(a) 
$801
(a) 
Vehicle fuel derivatives 
(b) 
46
(b) 
Total, pre-tax 801
 850
  800
 801
 
Tax benefit (305) (324)  (197) (305) 
Total, net of tax $496
 $526
  $603
 $496
 
Defined benefit pension and postretirement losses:          
Amortization of net loss $4
(c) 
$
(c) 
 $4
(b) 
$4
(b) 
Total, pre-tax 4
 
  4
 4
 
Tax benefit (2) 
  
 (2) 
Total, net of tax 2
 
  4
 2
 
Total amounts reclassified, net of tax $498
 $526
  $607
 $498
 
(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 to the consolidated financial statements for details regarding these benefit plans.

13.Revenues

PSCo principally generates revenue from the generation, transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such PSCo does not recognize a separate financing component of its collections from customers. PSCo presents its revenues net of any excise or other fiduciary-type taxes or fees.

PSCo has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.


Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments.
  Three Months Ended June 30, 2018
(Thousands of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:        
Residential $222,687
 $104,000
 $2,560
 $329,247
Commercial and industrial (C&I) 383,707
 38,904
 5,326
 427,937
Other 11,455
 
 
 11,455
Total retail 617,849
 142,904
 7,886
 768,639
Wholesale 36,148
 
 
 36,148
Transmission 13,159
 
 
 13,159
Other 14,696
 18,845
 
 33,541
Total revenue from contracts with customers 681,852
 161,749
 7,886
 851,487
Alternative revenue and other 34,343
 24,912
 1,124
 60,379
Total revenues $716,195
 $186,661
 $9,010
 $911,866

  Three Months Ended June 30, 2017
(Thousands of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:        
Residential $225,921
 $117,393
 $2,639
 $345,953
C&I 392,280
 45,032
 4,457
 441,769
Other 11,711
 
 
 11,711
Total retail 629,912
 162,425
 7,096
 799,433
Wholesale 41,579
 
 
 41,579
Transmission 13,180
 
 
 13,180
Other 16,837
 20,040
 
 36,877
Total revenue from contracts with customers 701,508
 182,465
 7,096
 891,069
Alternative revenue and other 28,412
 10,312
 1,123
 39,847
Total revenues $729,920
 $192,777
 $8,219
 $930,916
  Six Months Ended June 30, 2018
(Thousands of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:        
Residential $450,336
 $331,746
 $5,256
 $787,338
C&I 726,933
 124,932
 12,485
 864,350
Other 23,631
 
 60
 23,691
Total retail 1,200,900
 456,678
 17,801
 1,675,379
Wholesale 84,038
 
 
 84,038
Transmission 25,411
 
 
 25,411
Other 33,527
 43,774
 
 77,301
Total revenue from contracts with customers 1,343,876
 500,452
 17,801
 1,862,129
Alternative revenue and other 70,593
 50,195
 2,247
 123,035
Total revenues $1,414,469
 $550,647
 $20,048
 $1,985,164

  Six Months Ended June 30, 2017
(Thousands of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:        
Residential $460,355
 $343,303
 $5,203
 $808,861
C&I 751,977
 131,274
 13,717
 896,968
Other 24,386
 
 63
 24,449
Total retail 1,236,718
 474,577
 18,983
 1,730,278
Wholesale 85,155
 
 
 85,155
Transmission 27,819
 
 
 27,819
Other 33,532
 42,650
 
 76,182
Total revenue from contracts with customers 1,383,224
 517,227
 18,983
 1,919,434
Alternative revenue and other 58,084
 31,686
 2,246
 92,016
Total revenues $1,441,308
 $548,913
 $21,229
 $2,011,450

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 intendedincluding the TCJA’s impact to bePSCo and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should”“should,” “will,” “would” 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, 20162017 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.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin and natural gas margin.  Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measure calculated and presented in accordance with GAAP. PSCo’s management uses non-GAAP measures internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric margin is presented as electric revenues less electric fuel and purchased power expenses and natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas sold and transported are generally recovered through various recovery mechanisms, and as a result, changes in these expenses are offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including steam and other operating revenues, cost of sales - steam and other, O&M expenses, demand side management (DSM) expenses, depreciation and amortization and taxes (other than income taxes).

Results of Operations

PSCo’s net income was approximately $212.1$256 million for 2017 year-to-date,the second quarter of 2018, compared with approximately $203.2$212 million for the same period of 2016.2017. The increase is due towas driven by higher electric and natural gas margins due to the impact of an interim rate increase, subject to refund, and lower O&M expensesfavorable weather and increased allowance for funds used during construction (AFUDC) primarily related to the Rush Creek wind project. These items were partially offset by increased depreciation.higher interest charges and depreciation expense.


Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuationfluctuations in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses,electricity. However, these price fluctuations have minimal impact on electric margin.margin due to fuel recovery mechanisms that recover fuel expenses. The following table details the electric revenues and margin:
 Six Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2017 2016 2018 2017
Electric revenues $1,441
 $1,440
Electric revenues before impact of the TCJA $1,460
 $1,441
Electric fuel and purchased power (568) (572) (553) (568)
Electric margin before impact of the TCJA $907
 $873
Impact of the TCJA (offset as a reduction in income tax expense) (46) 
Electric margin $873
 $868
 $861
 $873

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

Electric Revenues
(Millions of Dollars) 2017 vs. 2016 2018 vs. 2017
Fuel and purchased power cost recovery $(8)
Estimated impact of weather 8
DSM program revenues (offset by expenses) 7
Trading 5
DSM incentive 2
Non-fuel riders $3
 2
Earnings test 2
Fuel and purchased power cost recovery (6)
Firm wholesale 2
Other, net 2
 1
Total increase in electric revenues $1
Total increase in electric revenues before impact of the TCJA $19
Impact of the TCJA (offset as a reduction in income tax expense) (46)
Total decrease in electric revenues $(27)

Electric Margin
(Millions of Dollars) 2017 vs. 2016 2018 vs. 2017
Estimated impact of weather $8
DSM program revenues (offset by expenses) 7
Trading 3
DSM incentive 2
Fuel handling and procurement 2
Non-fuel riders $3
 2
Earnings test 2
Estimated impact of weather (3)
Firm wholesale 2
Other, net 3
 8
Total increase in electric margin $5
Total increase in electric margin before impact of the TCJA $34
Impact of the TCJA (offset as a reduction in income tax expense) (46)
Total decrease in electric margin $(12)


Natural Gas Revenues and Margin

Total natural gas expense tends to varyvaries with changing sales requirements and the cost of natural gas purchases.gas. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effecthas minimal impact on natural gas margin.margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:
 Six Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2017 2016 2018 2017
Natural gas revenues $549
 $507
Natural gas revenues before impact of the TCJA $566
 $549
Cost of natural gas sold and transported (267) (228) (250) (267)
Natural gas margin before impact of the TCJA $316
 $282
Impact of the TCJA (offset as a reduction in income tax expense) (15) 
Natural gas margin $282
 $279
 $301
 $282

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

Natural Gas Revenues
(Millions of Dollars) 2017 vs. 2016 2018 vs. 2017
Retail rate increase (interim, subject to refund) $20
Infrastructure and integrity riders 8
Estimated impact of weather 4
Purchased natural gas adjustment clause recovery $38
 (16)
Infrastructure and integrity rider 10
Retail rate decrease (5)
Estimated impact of weather (4)
Other, net 3
 1
Total increase in natural gas revenues before impact of the TCJA $17
Impact of the TCJA (offset as a reduction in income tax expense) (15)
Total increase in natural gas revenues $42
 $2

Natural Gas Margin
(Millions of Dollars) 2017 vs. 2016 2018 vs. 2017
Infrastructure and integrity rider $10
Retail rate decrease (5)
Retail rate increase (interim, subject to refund) $20
Infrastructure and integrity riders 8
Estimated impact of weather (4) 4
Other, net 2
 2
Total increase in natural gas margin before impact of the TCJA $34
Impact of the TCJA (offset as a reduction in income tax expense) (15)
Total increase in natural gas margin $3
 $19

Non-Fuel Operating Expenses and Other Items

O&MDSM Program Expenses O&MDSM program expenses decreased $5.8increased $8 million, or 1.513.7 percent, for 2017 year-to-date. The decrease was primarily due to the timing of planned maintenance and overhauls and savings from cost management programs, partially offset by increases in employee benefits.

Allowance for Funds Used During Construction (AFUDC), Equity and Debt AFUDC increased $3.7 million for 20172018 year-to-date. The increase was primarily due to an increasehigher recovery rates for electric and natural gas sales. DSM expenses are generally recovered concurrently through riders and base rates. Timing of recovery may not correspond to the period in wind construction projects, particularly Rush Creek.which costs were incurred.

Depreciation and Amortization Depreciation and amortization expense increased $13.7$6 million, or 6.32.4 percent, for 20172018 year-to-date. The increase was primarily attributabledriven by capital expenditures due to planned system investments.

AFUDC, Equity and Debt AFUDC increased $19 million for 2018 year-to-date.  The increase was primarily due to the Rush Creek wind project.

Interest ChargesInterest charges increased $9 million, or 9.6 percent, for 2018 year-to-date. The increase was primarily due to higher debt levels to fund capital investments.investments, partially offset by refinancings at lower interest rates.


Income Taxes — Income tax expense increased $0.5decreased $47 million for 2017 year-to-date.the first six months of 2018 compared with the same period in 2017. The increase in income tax expensedecrease was primarily driven by a lower federal tax rate due to higher pretax earnings in 2017, partially offset by increased permanent plant-related adjustments (e.g., AFUDC-equity) in 2017 and a tax expense for a state tax credit valuation allowance in 2016.the TCJA. The ETR was 36.422.5 percent for 2017 year-to-date,the first six months of 2018 compared with 37.436.4 percent for the same period of 2016.2017. The lower ETR in 2017 was2018 is primarily due to the adjustments referenced above.lower federal tax rate. See Note 4 to the consolidated financial statements.

Public Utility Regulation

Except to the extent noted below and in Note 5 to the consolidated financial statements, 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, 20162017 and Public Utility Regulation included in Item 2 of PSCo’s Quarterly Report on Form
10-Q for the quarterly period ended March 31, 2017,2018, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

Rush Creek Wind Ownership ProposalColorado Energy Plan (CEP) 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 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.

In June 2017, PSCo filed its report required under Colorado rules that require PSCo to consider Best Value Employment Metrics (BVEM) as a factor in selecting contractors for generation projects. On July 5, 2017, several building trades filed comments arguing that PSCo’s Balance of Plant Contractor selection was inappropriate as it did not follow a more detailed and quantitative analysis. The trade unions argued that the BVEM deficiencies could be remedied through execution of a Project Labor Agreement on the project. PSCo filed its reply indicating that it satisfied the BVEM rule requirements on July 18, 2017, which was discussed by the CPUC on July 20, 2017. The CPUC took no action other than to request reconsideration of whether bidder’s BVEM information can be provided as public information. PSCo is evaluating this request.

2016 Electric Resource Plan (ERP) — In May 2016, PSCo filed its 2016 ERP which included itsthe estimated need for additional generation resources and its proposal to acquire those resources through a competitive Request for Proposal (RFP) process. The CPUC issued its decision on Phase I in late Aprilspring of 2024. In 2017, approving the Phase I modeling assumptions to be used in Phase II and directed PSCo to filefiled an updated capacity need prior to issuing any RFPs. PSCo plans to updatewith the rangeCPUC of resource need to be considered within the competitive RFP process and issue the RFP450 MW in August 2017. The CPUC is expected to rule on the RFP results in the second quarter of 2018.2023.

Advanced Grid IntelligenceIn 2017, PSCo and Security In July 2017,various other stakeholders filed a stipulation agreement proposing the CPUC approvedCEP, an alternative plan that increases PSCo’s CPCN for implementationpotential capacity need up to 1,110 MW due to the proposed retirement 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.two coal units.

In June 2017,2018, PSCo filed its 120-day update report with the CPUC approvedwhich includes multiple portfolios and recommends a settlement, which delayedpreferred CEP portfolio. PSCo's investment under the advanced meter deployment from 2017-2021preferred CEP portfolio would be approximately $1 billion, including investment in transmission to 2019-2024.support the significant increase in renewable generation in the state. The total capital costpreferred CEP portfolio includes the following additions as well as the retirement of the project is currently estimated to be approximately $537 milliontwo coal-fired generation units:
Total CapacityPSCo's Ownership
Wind generation1,100 MW500 MW
Solar generation700 MW
Battery storage275 MW
Natural gas generation380 MW380 MW

On July 13, 2018, the Independent Evaluator (IE) for 2017-2024. As a resultthe ERP filed their report on the process, modeling and evaluation of the settlement, approximately $120 millionvarious offers received through the RFP process.  Generally, the IE report was favorable to the process employed and the outcomes included in the modeling.  Certain recommendations for future ERP processes were provided with a primary focus regarding enhanced modeling of capital investment was deferred to 2022-2024.new resource types such as battery storage.
On July 23, 2018, various stakeholders commented on the 120-day update report for the ERP and the CEP. Many community, advocate and developer interests supported the CEP, while certain stakeholders opposed the CEP and the associated early coal plant retirements. The CPUC staff indicated that PSCo’s preferred CEP plan is a valid option, but expressed concerns on the saving assumptions, complexity of modeling and the utilization of production tax credits.

A CPUC decision is anticipated in September 2018.

Decoupling FilingPublic Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC Sustainable Power Group, LLC (sPower) has proposed to construct over 1,500 MW of solar and wind generation in Colorado and is seeking to require PSCo to contract for these resources under PURPA. In July 2016, PSCoMarch 2017, sPower filed a request withcomplaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find a December 2016 CPUC ruling that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process violated PURPA and FERC rules. In June 2018, the court denied a motion by the CPUC to approve a partial decoupling mechanism, which would adjust annual revenues based on changes in weather normalized average use per customer fordismiss. The case remains pending further action from the residential and small commercial classes. court.


Open Access Transmission Tariff (OATT) Reform In July 2017,May 2018, the CPUCFERC denied a request by PSCo to amend its OATT to allow large generating interconnection agreements to be suspended by the generator only due to a force majeure event, rather than allowing suspension for up to 36 months for any reason.  PSCo requested the changes to facilitate more efficient processing of generator interconnection requests.  PSCo has initiated a process to achieve broader generator interconnection queue reform and anticipates requesting additional OATT changes later in 2018.  In April, 2018, the FERC had issued a decision which approved the following key decisions regarding decoupling:
Effective Jan. 1, 2018 through December 2023 (subjectfinal rule requiring generator interconnection OATT queue reforms in addition (but generally complimentary) to establishingreforms PSCo already requested. PSCo currently has more than 22,000 MW of new ratesgenerator projects in the next electric rate case);
Applicableits interconnection queue.  The broader interconnection queue reforms are intended to allow generators to proceed to interconnection on a “first ready, first served” basis, similar to the residential class and small commercial class;
Based on total class revenues (subject to establishing the base periodprocesses already use in the next electric rate case);
Based on actual sales; and
Subject to a soft cap of 3 percent on any annual adjustment.
PSCo plans to seek reconsideration of the order.MISO.

Boulder, Colo.Colorado Municipalization In 2011, City of Boulder, Colorado (Boulder) voters passed a ballot measure authorizing the formation of aan electric municipal utility.utility, subject to certain conditions. Since that time, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system separation plans were not final. The Boulder District Court dismissed the case for lack of subject matter jurisdiction. PSCo appealed this decision. In September 2016, the Colorado Court of Appeals vacated the District Court’s decision, and ultimately preservedruled in PSCo’s ability to challenge the utility formation. Boulder subsequently filedfavor, vacating a Petition for Writ of Certiorari withlower court decision. In June 2018, the Colorado Supreme Court. The Supreme Court has not yetrejected Boulder’s request to dismiss the case and ruled whether it will exercise its discretion and reviewthat the petition.

In January 2015,case be remanded for hearing at the Boulder District Court affirmed a prior CPUC decision that (District Court).

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 how the systems are separated to preserve reliability, safety and effectiveness. In February 2015, the Boulder District Court also dismissed the condemnation action Boulder had filed. The CPUC must approve thefiled multiple separation plan before Boulder files its condemnation proceeding.
In July 2015, Boulder filed an applicationapplications with the CPUC, requesting approval of its proposed separation plan. PSCo filed a motion to dismiss Boulder’s application. The CPUC dismissed a portion of Boulder’s application, but allowed Boulder to supplement its application. Boulder filed its second supplemental application in September 2016. In March 2017,which have been challenged by PSCo and other parties filed their testimony outlining their concerns aboutintervenors. In September 2017, the Boulder separation plan and raised legal concerns aboutCPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC approved the plan.
designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings. In April 2017, despite extensive negotiations between PSCo and Boulder, the Boulder City Council voted to continue litigation for municipalization. Also,July 2018, the CPUC orderedapproved Boulder and PSCo’s joint request to file a third supplemental separation plan clearly laying out Boulder’s proposal.extend the time by which these filings would be due until Aug. 24, 2018. Boulder proposed a plan that would cost approximately $75 million. Boulder proposed sharing of certain distribution and substation facilities and requested that PSCo be required to construct Boulder’s new facilities and finance the construction. In June 2017, PSCo and other intervenors filed alternatives to Boulder’s separation plan and opposed the sharing; contracting and financing aspects of the plan. Evidentiary hearings began July 26, 2017.
Mountain West Transmission Group (MWTG) — PSCo initiated discussions with six other transmission ownersdoes not have authorization from the Rocky Mountain regionCPUC to evaluate the merits of creating and operating pursuant toinitiate a joint transmission tariff that may increase wholesale market efficiency and improve regional transmission planning.  In 2016, the MWTG established a non-binding memorandum of understanding to guide their process and issued a request for information to four established RTOs. In January 2017, the MWTG initiated preliminary discussions with the SPP to begin evaluation of the costs and benefits of MWTG participation in the SPP RTO. The CPUC has held informational meetings on certain issues including financial implications and reliability. If PSCo were to move forward with RTO participation, CPUC and FERC approval would be required. If approved, operations within the RTO would not be expected to begin until 2019,condemnation proceeding at the earliest. PSCo will evaluate its options later in 2017 and beyond.this time.


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, 20162017 and Quarterly Report on Form 10-Q for the quarterly period ended
March 31, 2017.2018. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

StatusXcel Energy, which includes PSCo, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC Commissioners — The FERC is normally comprised of five commissioners appointed by the President and confirmed by the Senate. There is currently only one sitting commissioner.  Without three commissioners, the FERC does not have a quorumCommodity Futures Trading Commission jurisdictions. Public campaigns are conducted to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction of interstate natural gas pipeline facilities to serve the utility subsidiaries.  PSCo does not expect any disruption in operations or material delay in decisions on contested matters pending before the FERC. President Trump has submitted nominations to fill threeraise awareness of the vacant seats and has indicated his intentpublic safety issues of interacting with our electric systems. While programs to submit one additional nomination. The three submitted nominationscomply with regulatory requirements are pending confirmation byin place, there is no guarantee the full Senate.

Public Utility Regulatory Policies Act (PURPA) Enforcement Complaintcompliance programs or other measures will be sufficient to ensure 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 has intervened in that proceeding and the CPUC has 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. The Magistrate’s recommendation is pending before the District Court.violations.

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 June 30, 2017,2018, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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 1LEGAL PROCEEDINGS

PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See 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, 2016,2017, 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*
3.02*
4.01*


101The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended June 30, 20172018 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.


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
   
July 28, 201727, 2018By:/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)


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